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November 7, 2024

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New Jersey BPU Approves Invenergy Offshore Wind Delay

New Jersey’s Board of Public Utilities has approved a request by offshore wind developer Invenergy to delay until Dec. 20 the enforcement of its contract to give the developer time to find an economically viable turbine.

The board accepted the developer’s Motion for a Stay of Order to delay enforcement of the January 2024 agreement that endorsed the developer’s 2,400 MW Leading Light Wind (LLW) Project in the state’s third solicitation. Because of the stay, Invenergy temporarily will avoid making “significant financial obligations” required by the contract.

The company’s July petition said it initially planned to use turbines from one of three manufacturers — GE Vernova, Siemens Gamesa Renewable Energy (SGRE) or Vestas. But changes in the cost or size of their turbines mean Invenergy’s project no longer would be economically feasible if they were used.

Invenergy said it needs time to find a new turbine supplier. Their petition argued that without the stay, the project would have to move ahead without a clear understanding of costs, putting in jeopardy the “significant environmental and economic benefits” of the project.

The Sept. 25 board order unanimously approving the stay largely agreed.

“The public’s interest, in the context of the requested stay, is in reaping the benefits of the LLW Project, or at least preserving the status quo and the opportunity to do so,” the order said.

“Denial would result in Invenergy and the LLW Project having insufficient time to engage in meaningful negotiations with wind turbine manufacturers and the ability to identify in a timely manner a cost-effective wind turbine option, a necessary element of an OSW project,” the order states. Without the stay, it added, “Invenergy must contemplate whether it is possible to continue development of the LLW Project, given the deterioration of the LLW Project economics.”

‘Critical’ to the State

The BPU decision comes almost a year after Danish developer Ørsted pulled the plug on the state’s most advanced project, Ocean Wind 1, awarded in the state’s first solicitation in 2019, and the sister project Ocean Wind 2, awarded in the second solicitation in 2021. Ørsted at the time said the projects no longer were economically viable. Gov. Phil Murphy (D) since has scrambled to accelerate New Jersey’s offshore wind program to make up the two years lost by abandonment of the projects. (See UPDATED: Ørsted Cancels Ocean Wind, Suspends Skipjack.)

The BPU is evaluating three bids submitted in July for its fourth solicitation, with bid selection expected in December. In May, Murphy accelerated the timeline for the state’s fifth solicitation, with the process expected to begin in the second quarter of 2025 (See 3 OSW Proposals Submitted to NJ.)

BPU President Christine Guhl-Sadovy said after the 4-0 vote the state is “committed …. to our offshore wind goals.”

“It is critical towards our fight, and to mitigate climate change, and I think that this action will allow Invenergy to find a suitable wind turbine supplier,” she said. “We look forward to them delivering on the project.”

Commissioner Zenon Christodoulou said he shared Guhl-Sadovy’s optimism. “I’m fully confident that they’ll be able to work through these little hurdles and make sure that an industry which has taken over in many places in the world will apply here in New Jersey as well,” he said.

Shifting Options

Invenergy said it developed its proposal with a “turbine agnostic” approach and the products of all three manufacturers appeared viable at the time it submitted its project proposal to the BPU in August 2023. But the developer soon deemed the Vestas turbines “unsuitable for the site” due to “cost and technical factors.”

Three weeks after the board approved the project in January, GE announced it would not produce the turbine Invenergy planned to use. An Aug. 8 filing in the case by the New Jersey Division of Rate Counsel said the developer had planned to use GE’s Haliade-X 18 MW turbine, but the manufacturer in February announced in a financial filing that it had refocused its business and instead would manufacture the smaller Haliade-X 15.5 MW-250 turbine.

In June, SGRE “notified Invenergy that it was substantially increasing the cost of its turbine offering,” which meant the developer no longer had a “viable turbine supplier,” Invenergy said in its petition.

“The stay … is in the public interest in that it will permit the company the time needed to address these unforeseen circumstances in a thorough and thoughtful manner,” the developer’s petition said, adding that Invenergy “remains committed to bringing the economic and environmental benefits of offshore wind energy” to New Jersey.

Without the stay, the BPU contract would require Invenergy to pay the agency $120 million in security commitments and “multiple other funding commitments,” the New Jersey Division of Rate Counsel said in its Aug. 8 filing. If the project did not meet those commitments, the BPU could modify the price of Offshore Wind Renewable Energy Certificates, the filing said.

The ratepayer advocate said it was not opposed to Invenergy’s petition but had concerns about the board’s “frequent post-award alterations to the Board’s offshore wind solicitation process.”

“The Board’s competitive solicitation process must ensure all bidders are subject to the same rules,” the filing said. “Changing the bidders’ requirements following the close of bidding undermines the competitive process.”

Financial Reporting

The board’s decision comes three weeks after the board approved a slight change in the contract requirements placed on another developer selected in the third solicitation — Attentive Energy, which is developing a 1,342 MW project.

The BPU on Sept. 4 approved the developer’s request to file unaudited financial statements quarterly, rather than audited statements, and to submit them within 60 days of the end of the quarter. The BPU ruled that annual audited financial reports must be submitted 120 days after the end of the year, and not after 180 days, as the developer suggested.

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Report Calls for $75B in New Tx to Meet Western Needs

The Western Interconnection will need about 15,600 new line miles of high-voltage transmission at a cost of about $75 billion over the next 20 years to meet the anticipated increase in load growth, according to a report commissioned by Gridworks and GridLab published Sept. 23.

Conducted for the two groups by Energy Strategies, the Connected West study found that the Western grid’s reliability is at risk even if $30 billion of planned grid investments are implemented in the next decade. The current planned investments represent approximately 5,900 line miles, which may not be enough to support “an electrified and deeply decarbonized Western grid in 2045,” according to the report.

Instead, the report recommends an additional 15,600 new line miles over 20 years. The study found that approximately 85% of the new transmission capacity across the West can be achieved by upgrading existing corridors. Some 2,400 miles of new greenfield transmission would be needed for the proposed transmission system, the report said.

“The high-voltage investment gap to support reliability and efficiency of the grid, representing the next tranche of regional-scale transmission investments not currently planned for, is on the order of at least $75 billion,” the report said. “This investment, at a minimum, is necessary to address the transmission constraints identified in the Connected West scenario.”

The report added that the investment gap “should be considered a ‘floor’ not a ‘ceiling’ of future transmission need.”

Casey Baker, senior program manager for GridLab, said in an email to RTO Insider that the study provides stakeholders with recommendations on how to complete transmission plans “that can be implemented in the various FERC Order 1920 compliance efforts kicking off in regions around the country.” (See FERC Open Meeting Showcases Order 1920 Rehearing Debate.)

“Transmission stakeholders can take the Connected West study and use it in their efforts to promote best practices as their regions move towards completing their own long range transmission plans,” Baker added.

The study builds on the Nature Conservancy’s 2022 Power of Place: West report, which explored the land use requirements and conservation impacts of achieving net-zero greenhouse gas emissions across the Western U.S.

Connected West leveraged Nature Conservancy’s findings to analyze transmission needs for a high electrification scenario involving various clean energy technologies, according to the report. The study evaluated three transmission expansion portfolios, with each portfolio exploring different pathways to improve grid capacity, reliability and efficiency.

Baker noted that although the costs are significant, “the benefit to cost ratio for all three portfolios was approximately 1.4 and assumed significant (approximately 70%) load growth over the next 20 years which could be leveraged to support this investment.”

Total benefits from the new transmission explored in Connected West would be between $250 billion to $275 billion, including up to $150 billion in avoided investments in power plants, $50 billion in avoided losses from extreme weather and $35 billion in reduced energy costs, among other benefits, according to the report.

“Our analysis shows that this level of expansion is not only achievable but necessary to meet the energy demands of the future,” Matthew Tisdale, executive director of Gridworks, said in a news release. “With proper planning, we can build the infrastructure needed to support a robust economy while minimizing costs. Simply put: it will be better for ratepayers, businesses and communities in the West if we make the right investments now to avoid higher costs and greater disruptions later.”

‘Unprecedented’

The Connected West study appears well-positioned to contribute to Western transmission discussions as two parallel efforts ramp up to spur development of the kind of interregional projects the region has struggled to build.

One of those is the Western Power Pool’s Western Transmission Expansion Coalition (WestTEC), which is being guided by electricity industry participants.

The other is the Western States Transmission Initiative (WSTI), which is being facilitated by Gridworks on behalf of the Committee on Regional Electric Power Cooperation’s membership of state energy agency officials. (See In West, Proposals for Tx Planning Proliferate Faster than New Lines.)

Baker called Connected West an “unprecedented study that provides a template for completing a 20-year, holistic, multi-benefit transmission plan.”

“Many other entities including WECC, CAISO, and the U.S. [Department of Energy] have completed 20-year transmission studies, but this is the first long-range transmission plan to integrate economy-wide decarbonization, multiple benefit streams, transmission technology portfolios and environmental siting considerations across the entire Western grid,” he said.

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With Three Mile Island Restart, Debate Continues on Co-located Load in PJM

Data centers and other concentrated electric consumers are increasingly seeking to purchase their power directly through nuclear generators in PJM, raising concerns among state regulators, consumer advocates and utilities that they may be able to skirt paying their fair share. 

Five years after shuttering, Three Mile Island Unit 1 is being resurrected as the Crane Clean Energy Center (CCEC) to supply Microsoft with energy through a power purchase agreement, while Talen Energy is seeking to amend the interconnection service agreement (ISA) for its Susquehanna Nuclear Plant to reduce its output to PJM and instead supply a co-located data center sold to Amazon Web Services. (See Constellation to Reopen, Rename Three Mile Island Unit 1 and Talen Energy Deal with Data Center Leads to Cost Shifting Debate at FERC.)  

The latter has drawn protests from Exelon, American Electric Power and the Pennsylvania Public Utility Commission arguing that more information is needed about how the configuration may affect the grid and whether it will benefit from ancillary services, such as black start and regulation, without being assessed proper transmission fees. 

During a Sept. 24 hearing on co-located load held by the Maryland Public Service Commission, FirstEnergy Chief Risk Officer Abigail Phillips said nuclear generation can help meet a resource adequacy gap identified in 2029, with load forecasts driven by data centers and thermal resource deactivations outpacing development in PJM. 

“Right now it doesn’t seem like the capacity markets are paying for those capital costs of generation, and the price signals that PJM talked about this morning are increasing the prices, but in the past auction, no new dispatchable generation is going to come online,” she said. “So how long is it going to take to make those price signals work, and how long are we willing to wait and depend on that before we need to do something to get new generation on in Maryland and the rest of PJM?” 

Data center developers could be choosing to co-locate with dependable generators out of a concern that the PJM grid may not offer the same security it traditionally has, Phillips said, which underscores the need to determine how to ensure adequate capacity. Additional nuclear generation could hold the promise to meeting resource adequacy needs and climate goals at once, she said. 

“Nuclear is getting back into the conversation as a part of a zero-carbon solution. I know Maryland has clean energy goals, and I think that having nuclear back in the game is going to be helpful with achieving long-term capacity and long-term goals, not only for Maryland, but for PJM and the country,” Phillips said. 

Greg Poulos, executive director of the Consumer Advocates of the PJM States, drew a distinction between the CCEC and co-located load requests, saying that most advocates are supportive of bringing new nuclear generation online as the balance between supply and demand grows increasingly tight in PJM. Whereas the CCEC will bring about 835 MW of new generation online to serve existing load, he said co-location may be taking generation out of the markets to serve load not considered part of the grid and exempt from service charges. 

Where Poulos does see common ground between the CCEC PPA and co-located load configurations is the potential for major market impacts caused by the addition of large data centers, whether they are in or out of PJM’s market. 

He stressed that consumer advocates are supportive of the economic development that data centers promise the states they locate within, so long as there are rules to ensure that they pay their fair share for any services they consume or grid impacts they prompt. Co-location could also push transmission costs lower by reducing the need for new lines, he said. 

Advocates are also concerned about market power, Poulos said, with the potential for generation owners with a broad portfolio within a tight zone having the ability to pick a resource to take out of the market and push energy and capacity prices higher. Generators could contract with a data center to provide power well below the regional clearing price, knowing that other resources in their portfolio will clear at a higher price. Co-located configurations have the potential to distort price signals even without market manipulation by removing large volumes of load and generation from a zone, he said. 

“The market is supposed to provide the appropriate price signal, but if you have this other massive load being served in the same area offline, so to speak, it could impact the price signals. It could make them not accurate so the price signals aren’t reasonable in the market and for consumers,” Poulos said. 

PJM stakeholders had considered several proposals to change the market rules for co-located configurations last year, but none of them received majority support, and the topic was dropped. Poulos said it’s unlikely stakeholders will be able to make progress while FERC and state commissions are looking at the topic, and it will likely have to be FERC that makes the first move on the broad legal and jurisdictional questions. (See “Proposed Rules for Generation with Co-located Load Rejected,” PJM MRC Briefs: Oct. 25, 2023.) 

The RTO issued guidance around co-located configurations recommending that parties receive firm transmission service while stating that it does not have the authority to prevent private contracts between generators and load seeking to co-locate off the grid. (See “Additional Guidance on Co-located Load,” PJM MRC Briefs: April 25, 2024.) 

During the PSC hearing, Aftab Khan, PJM’s executive vice president of operations, planning and security, said the RTO has requests to study about 8 GW of co-located load configurations, mostly to serve data centers. When such requests are received, he said PJM conducts the “necessary studies” to ensure there is no adverse impact to the grid. Any required transmission upgrades to support the configuration are identified and must be implemented at the cost of the generator before the co-located load can come online. 

He said PJM considers non-network load co-located with interconnected generators to also be electrically connected to the RTO’s grid and benefiting from ancillary services, but it has no way of assessing fees. 

“Under any configuration, co-located load is electrically connected and synchronized to the PJM system when consuming power and therefore benefits from the use of the transmission system and ancillary services, such as black start and regulation services,” Khan said. “PJM network load accounts for such services, but there are no transmission or ancillary service charges to the off-system load. PJM previously tried to address this with proposed rule changes for ancillary services, but the proposal did not achieve the consensus of the PJM members.” 

Independent Market Monitor Joe Bowring also said the load is part of PJM’s grid and the broad impact should be holistically studied to identify impacts, rather than examined through amendments to generators’ ISAs. 

“All load, including co-located load, is on the grid, affects the grid and benefits from the grid,” Bowring said. “As a result, decisions about co-located load affect all customers.” 

Bowring said the Monitor’s analysis of co-location configurations did not find a substantial difference between cost allocation to consumers regardless of whether the load is considered part of PJM’s network or if the large load additions were made miles away from the generator. Instead, he said the underlying issue is how PJM identifies and studies large consumers. 

“It’s not just a question of co-located load; it’s a question about load in general. … What that illustrates and emphasizes is that the analysis has to be done carefully,” he said. 

Phillips told the PSC that it’s critical that the consequences of allowing generators to take their output off the market to serve non-network load is fully understood, both in terms of costs and reliability. 

“Any reduction in dispatchable, on-demand generation that’s available to serve residential customers should be analyzed before we make any changes to policy or regulation. We have to really understand when you co-locate and what that does to capacity, both short term and long term, how does that trickle down into who’s paying for it, who gets the benefit, and we have to make sure it’s not only cost affordable, but [also] we maintain that reliability,” she said. 

In a white paper published Sept. 23, Tony Clark, former FERC commissioner and senior adviser at Wilkinson Barker Knauer, and Vincent Duane, principal at Copper Monarch and former senior vice president of law, compliance and external relations at PJM, argue that allowing data centers to co-locate with nuclear generators allows them to avoid lengthy waiting periods while transmission upgrades necessary to accommodate their load are planned and built. But it can also alter power flows to require network upgrades before other networked loads can interconnect. They call for a cost allocation methodology that recognizes the benefits co-located load and generators receive from being part of the grid. 

“We would not advocate assigning to the co-locating generator the full cost impact of its withdrawal (as is done under the ‘but for’ test for new interconnections),” they wrote. “Nevertheless, the underlying principle — rooted in cost causation — offers a path to assign to the co-location arrangement its share of these cost impacts, thus restoring them to the position they would be in had they connected in the traditional manner.” 

Clark and Duane raise similar concerns about cost allocation for ancillary services and note that nuclear units receive public benefits, such as tax credits, grants and accelerated depreciation from the federal government and states. They argue that makes it especially questionable to allow units to leave RTO markets to serve private load. 

“From this perspective, nuclear generation is uniquely imbued with the public interest, making it unsettling if not unseemly for units, once the first data center comes knocking, to pull up stakes and desert customers that for decades have had their back,” they wrote. 

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Brattle Paper Weighs Pros and Cons of Utility-owned Generation in NY

Allowing utilities to own generation again in New York state could speed up their deployment, according to a Brattle Group white paper prepared for Consolidated Edison released Sept. 24.

“Con Edison has been the champion for renewable energy generation for its customers for decades,” Vice President of Distributed Resource Integration Raghu Sudhakara said in a statement. “We believe that utility ownership of renewable energy will provide New Yorkers with additional renewable generation for the green energy that they need when they need it, and with the highest value.”

The state’s Climate Leadership and Community Protection Act requires 70% of load be met with renewables by 2030 and full decarbonization by 2040, which translates into the need to add tens of thousands of megawatts to the grid over the next decade.

Currently renewables outside of Long Island are largely procured with New York State Energy Research and Development Authority contracts and New York Power Authority ownership, the paper says. NYSERDA runs competitive solicitations, and while it has attracted some new supplies, since the end of 2020, it has only procured 2.7 GW of new onshore wind and solar.

“New York greatly needs to add large amounts of renewable resources in the next decade if it is going to meet the state’s ambitious decarbonization and renewable generation goals,” Brattle Principal and report co-author Metin Celebi said in a statement. “Utility ownership of renewables alongside private ownership of assets could not only help expedite the development of new renewable resources but ultimately even save utility customers in the state money, alongside other benefits.”

The paper evaluated the costs customers would incur during the first 30 years of operation for a new 100-MW onshore wind or solar facility under both utility and private ownerships, with different scenarios based on energy market prices, financing costs, contract durations and repowering assumptions. The renewable projects were identical except for the different ownership, with the only difference in final costs to customers based on cost recovery mechanisms, expected rates of returns and how tax credits are treated.

Allowing utility ownership “with sufficient guardrails against anticompetitive behavior” could allow customers to benefit from the advantages of both utility ownership and private ownership of renewables. When power prices are high and the cost of capital is high for private developers, utility-owned generation saves up to 14% compared to private developers, but other scenarios have privately owned renewables coming in cheaper for consumers by up to 11%.

The data for the costs of the power plants and how much money they are likely to make in the energy markets came from the National Renewable Energy Laboratory. The utility cost of capital is based on what the New York Public Service Commission has approved — 6.75% — while the private cost of capital is based on current market conditions at 6.99%.

“The cost of capital for private renewable developers is uncertain, especially recently due to supply chain constraints, which have put further risk on the development of renewable energy projects in the United States and New York in particular,” the report says.

To account for uncertainty, the study includes higher costs in one scenario: 7.5% for private solar developers and 9% for wind developers.

“We find that the customer costs are broadly comparable between the utility ownership option and the private ownership option,” Brattle said. “However, in the scenarios we analyzed, customer costs for new solar generation tend to be slightly lower under private ownership, while utility ownership tends to result in lower costs for new onshore wind generation.”

Ultimately, both ownership models result in a similar level of costs, and the different ownership models come with their own pros and cons, the paper says.

Utility-owned generation can help bring more renewables online and offers effective project execution and risk management to provide benefits and cost savings under some circumstances.

“However, utility ownership would likely shift most risks currently borne by private owners to electricity customers with respect to asset performance and investment cost overruns,” the report says. “In addition, depending on the implementation rules, utility ownership may raise concerns about cross-subsidization of costs and the availability of open access to information on the transmission and distribution systems to all developers of renewable generation in the state.”

The state will need 110 GW of nameplate capacity and 240 TWh of energy by 2040, but most of the projects in NYSERDA’s last five solicitations have been canceled, the paper notes. Of the 85 projects awarded by the authority between 2018 and 2021, all but eight have been canceled.

In its most recent solicitation in November, of the 68 projects that bid, 60 of them had been previously awarded contracts from which they backed out. NYSERDA ultimately picked 24 of those, representing 2.4 GW of capacity.

With the cancellations, the percentage of load served by renewables in 2022 was down compared to 2014. And with demand growth back in the mix, the gap is only getting wider.

The paper specifically highlights Dominion’s Coastal Virginia Offshore Wind Project as a successful utility development, noting that the firm financed and built a Jones Act-compliant vessel to install the project. The lack of such vessels was overlooked by some competitive suppliers, which led to project abandonments.

“Ideally, regulated utilities’ particular understanding of the regulatory and permitting environment in New York state, a direct interest in a highly reliable energy system in the state and a long-term commitment to the state increase the likelihood of project completion,” the paper says. “However, there is still no guarantee in this regard, given utilities’ exposure to similar market forces that would also impact competitive suppliers, including financing costs, rising capital costs and supply-chain limitations.”

In addition to competitive concerns, which crop up in part because the utilities own the transmission and distribution systems their competitors also need to connect with, the paper also says that letting the utilities into development would put the risk of failed projects onto customers.

“Despite the significant project cancellations described above, as a result of New York’s competitive procurement model, which allocates risks and benefits to private companies instead of customers, customers have not borne the costs of these canceled projects,” the paper says. “In contrast, if the costs of a canceled utility-owned project were determined to be prudently incurred, those costs would be recoverable from customers.”

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Data Centers Contribute to 60% Increase in San Jose Load Forecast

Data centers are contributing to significant load growth and project needs in Silicon Valley, according to CAISO representatives speaking at the Sept. 23 kickoff meeting for the ISO’s 2024/25 transmission planning process. 

While the San Jose area — a 115-kV network between the Newark and Metcalf substations — has seen the largest forecast increases, the greater Bay Area also has seen large load growth. 

In the 2021/22 transmission planning cycle, the California Energy Commission forecast about 9,500 MW for the Bay Area, a figure that since has grown to about 12,000 MW.  

“The Bay Area in general has grown, and that’s fuel switching; that’s EV; that’s just growth in general,” Jeff Billinton, CAISO director of transmission infrastructure planning, said in the meeting. “We’re also doing a sensitivity because there is a significant number of interconnections that PG&E is receiving for data centers in that area.” 

The San Jose area saw particularly significant load forecast increases, said Binaya Shrestha, manager of regional transmission north at the ISO. In the 2024/25 planning cycle, the region saw an increase of about 3,400 MW in the base case and 4,200 in the long-term sensitivity scenario. As a result, a project approved in the 2021/22 cycle, as well as the overall long-term transmission plan for the area, was re-evaluated. 

The ISO is considering alternatives to the previously approved project: a multi-terminal HVDC configuration that would connect the San Jose B converter to the Newark HVDC converter, meant to address load serving issues. When the project was approved, the long-term load in the area was about 2,100 MW. 

“Coming to this cycle, 24/25, when we look at the load in the long-term scenario in 21/22, it’s about a 60% load increase,” Shrestha said. 

A sensitivity case was developed to evaluate how an increase of load in the area would affect the proposed project and whether there was flexibility to expand the plan to serve more load. The ISO found that addition of the project would cause “severe overloads.” 

Additionally, LS Power, the project sponsor, identified a cost increase for the HVDC equipment, and worked with the ISO to develop alternatives to the project that could reliably deliver power without significant overloads or price increases. 

Multiple alternatives were considered, including high-capacity AC lines, a bi-pole multi-terminal HVDC, and a hybrid AC-HVDC solution. 

“Putting that all together, we are recommending a hybrid solution to move forward in this area,” Shrestha said. “That recommendation includes a 1,000-MW HVDC link between Metcalf and San Jose B, and we are changing the scope of the Newark HVDC to a high-capacity 230-kV AC line.” 

CAISO seeks to expedite approval of the altered project so it still can meet the 2028 planned in-service date, which “the area needs to be able to serve load.” 

The ISO also recommends a new 230-kV line connecting Newark and San Jose B. The scope change will be voted on by the Board of Governors in November. 

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WPP Board Approves WRAP Transition Plan Changes

The Western Power Pool’s Board of Directors has approved changes to the Western Resource Adequacy Program’s transition plan that include postponing the program’s “binding” phase by one year and reducing penalties for participants who come up short on RA obligations.

WPP said Sept. 24 that its board had approved the revised transition plan five days earlier, following through on a request by WRAP participants to push back the start of the program’s penalty phase by one year, from summer 2026 to summer 2027.

WPP staff working on the WRAP told RTO Insider through a spokesperson that the new timeline does not technically represent a delay because the program’s tariff gives WPP flexibility to begin binding operations anytime between 2025 and 2028.

Members of the WRAP’s Resource Adequacy Participants Committee (RAPC) requested a shift from the 2026 date in an April 22 letter addressed to “Western Stakeholders,” in which they warned that they face “significant headwinds” in securing energy resources in light of supply chain issues, forecasts for faster-than-expected load growth and increasing extreme weather events. (See WRAP Participants Seek 1-Year Delay to ‘Binding’ Operations.)

The RAPC on Aug. 29 voted to approve the revised transition plan, which — in addition to shifting the binding phase — also extends the WRAP’s “transition period” by one year to March 2029. (See WRAP Members Vote to Delay ‘Binding’ Phase to Summer 2027.)

Under the updated plan, during the transition period, participants who enter the binding phase but remain deficient in RA are allowed to pay a “discounted deficiency charge” if they fail to secure WRAP Operations Program capacity but show “commercially reasonable efforts” to do so.

The new plan also introduces the concept of “critical mass” into the program by setting a “participating load volume and participant threshold for a [WRAP] subregion below which participants may participate in a nonbinding manner” after the transition period ends.

Inclusion of that concept entails tariff changes that would allow participants to choose to be nonbinding for seasons when critical mass is not achieved in their subregion. The critical mass thresholds would be 15 GW of load and three participants for the Southwest/East Diversity Exchange (SWEDE) subregion, and 20 GW of load and three participants for the Northwest’s Mid-C subregion.

The transition plan changes were put out for public comment and reviewed by the WRAP’s Committee of State Representatives before being submitted to the WPP board, which also voted Sept. 19 to approve seven WRAP business practice manuals and a set of corrections to the program’s tariff.

“This is our robust stakeholder process and independent governance structure on display,” WPP CEO Sarah Edmonds said in a statement. “With the input and direction we’ve received on both the tariff and the business practice manuals, WRAP is well positioned to move forward.”

The WRAP tariff changes will now advance to FERC for approval.

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DHS Offers $280M in Grants for Cyber Investments

The Department of Homeland Security is looking for recipients for $279.9 million in grant funding to invest in cybersecurity for fiscal 2025, which begins Oct. 1. 

The grants are part of the State and Local Cybersecurity Grant Program (SLCGP), which Congress established in the Infrastructure Investment and Jobs Act of 2021. (See Bipartisan Infrastructure Bill Offers Funding for Grid, EVs.) 

The SLCGP, along with the Tribal Cybersecurity Grant Program (TCGP), provides about $1 billion in funding over four years. Both programs are intended to support state, local, territorial and tribal governments in reducing cyber risk and building resilience against cybersecurity threats. Entities may apply for the grants until 5 p.m. Dec. 3, 2024. 

The DHS Cybersecurity and Infrastructure Security Agency (CISA) jointly administers SLCGP and TCGP with the Federal Emergency Management Agency (FEMA). CISA serves as the subject matter expert on cybersecurity issues, while FEMA administers grants and oversees the use of appropriated funds. 

In a press release, CISA Director Jen Easterly said the programs would help “governments lay a solid foundation for building a sustainable and resilient cybersecurity program for the future.” 

According to the Notice of Funding Opportunity (NOFO) issued by DHS, SLCGP applications can be submitted by designated State Administrative Agencies (SAA). States and territories will be responsible for distributing sub-awards to local entities. The IIJA requires local governments to receive at least 80% of awarded funds, with at least 25% to be distributed to rural areas. 

Each state must receive at least 1% of the total available grant funding, according to the SLCGP fact sheet; this mandate also applies to the District of Columbia and Puerto Rico. American Samoa, Guam, the U.S. Virgin Islands and the Northern Mariana Islands each have a minimum allocation of 0.25%. Additional funds will be allocated “based on a combination of state population and rural population totals.” 

To receive grants, states and territories must have a CISA-approved cybersecurity plan and a cybersecurity planning committee and charter. Plans must be submitted by Jan. 30, 2025. Entities that already have a CISA-approved plan do not need to revise it unless the agency notifies them that it does not meet requirements, but CISA indicated that “there are no additional plan requirements” in FY 2025.  

CISA also reminded applicants that implementing the agency’s cybersecurity best practices is a “key requirement” of cybersecurity plans. The NOFO provided a list of practices for entities to incorporate: 

    • multifactor authentication; 
    • enhanced logging; 
    • encrypted data at rest and in transit; 
    • discontinued use of unsupported or end-of-life software and hardware that are accessible from the internet; 
    • restricted use of known, fixed, and default passwords and credentials; 
    • the ability to reconstitute systems from backups; 
    • rapid bidirectional information sharing between CISA and state, local and tribal entities; and 
    • migration to the .gov internet domain. 

CISA said incorporating the recommended best practices will help entities reach the baseline outlined in its cyber performance goals. 

“In the modern threat landscape, every community can — and too often does — face sophisticated cyberattacks on vital systems like hospitals, schools and electrical grids,” said Homeland Security Secretary Alejandro Mayorkas. “Our message to communities everywhere is simple: Do not underestimate the reach or ruthlessness of nefarious cyber actors. Through initiatives like the [SLCGP] we can confront these threats together.” 

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MISO, TVA to Enter Agreement on Emergency Purchases

INDIANAPOLIS — MISO and the Tennessee Valley Authority say they’re poised to strike an agreement on emergency energy transactions after months of RTO leadership complaining that TVA doesn’t return the favor of energy transfers in times of need.

The two have confirmed they will file an agreement with FERC to codify emergency purchases between the federal utility and the RTO.

According to TVA, the agreement is between MISO and two authorized TVA purchaser utilities. It will allow MISO to “act on their behalf to purchase power from TVA during certain emergency conditions, consistent with TVA’s obligations under the TVA Act,” TVA spokesperson Scott Fiedler said.

MISO said the draft agreement is not publicly available yet.

“We are focused on establishing a process for the provision of emergency energy during emergency events to support reliability on our respective systems, as well as provide terms for compensation,” MISO spokesperson Brandon Morris said. MISO did not comment on the degree it expects emergency transfers from TVA to benefit its operations.

During MISO Board Week in Indianapolis on Sept. 17, Vice President of System Planning Aubrey Johnson said in early October, TVA operators will visit MISO’s control room in Little Rock, Ark., to perform desktop exercises to familiarize themselves with MISO operations.

Johnson said he and other MISO leaders in turn will travel to Chattanooga, Tenn., to celebrate the emergency energy agreement the two should have completed by then.

The agreement is meant to forge a more symbiotic relationship between the two. Prior to the agreement, MISO leadership expressed disappointment in TVA because although MISO has assisted TVA with exports — especially during the late December 2022 winter storm — TVA as a rule didn’t flow power to MISO. (See “JOAs with Neighboring Systems?” MISO Winter Recap Centers on December Emergency.)

“TVA is an interesting animal in the Eastern Interconnect. They are limited in who they can sell power to,” Executive Director of Market Operations J.T. Smith said when the agreement was in the works in spring.

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MISO Tries to Win over Stakeholders on New LMR Capacity Accreditation

INDIANAPOLIS — Stakeholders appear wary of MISO’s proposed, availability-based accreditation method that it plans to file with FERC by the end of the year for the RTO’s approximately 12 GW of load-modifying resources (LMRs). 

MISO wants to accredit LMRs based on past performance levels by the 2028/29 planning year. It would split them into two categories — those that can respond in 30 minutes or less and those that can’t — and accredit them accordingly. (See MISO Proposes to Split LMR Participation, Accreditation into Fast/Slow Groups.) 

The LMR Type II category would have a maximum response time of 30 minutes and presumed availability for all maximum generation emergency step 2 events. An LMR Type I class would carry a maximum response time of six hours and be called up earlier, when MISO declares a maximum generation alert. The RTO has long said it needs to be able to access LMRs outside of actual emergency declarations. 

MISO plans to use a similar accreditation to its proposed, availability-based method for its more traditional generation resources. However, to measure demand response, MISO said it would use backward-looking meter data from hours when capacity advisory declarations are in place to accredit resources. The RTO plans to draw on data from a minimum of 65 historical hours per season over the past year and will give more weight in accreditation to performance during hours when capacity advisories escalate into maximum generation events, alerts or warnings. 

The RTO would cap accreditation at an LMR’s maximum stated capability during registration and reduce accreditation when LMR owners submit inaccurate availability information. Currently, MISO does not tie the accuracy of LMR availability data to accreditation values. 

During a Sept. 23 stakeholder workshop, WPPI Energy’s Steve Leovy said he was concerned that the sample size of hours during which capacity advisories are in effect is too small to be a good indicator of LMR performance. He said MISO’s capacity advisories seem too infrequent to use as a basis for accreditation.  

Other stakeholders said one year’s worth of data might not be adequate to create a stable, year-to-year accreditation. They pointed out that a particularly heat wave-laden or mild summer could skew the numbers, especially for those LMRs tied to air conditioning loads.  

MISO said it will turn to other previous years as needed if the past season doesn’t have the requisite 65 hours. Joshua Schabla, an economist in MISO’s market design group, also said the RTO intends to account for temperature-based adjustments in the accreditation. 

MISO said it needs the split classification because its long-lead-time LMRs are incapable of deploying in the time it takes for emergencies to materialize. The RTO experiences maximum generation alerts most frequently, with 20 occurring between 2020 and 2023, compared to 10 warnings, four maximum generation emergency step 1 events and five maximum generation emergency step 2 events in the same time frame. 

“Resources that deploy earlier can be used effectively, even if the event escalates quickly,” Schabla said. “In practice, we need these long-lead resources to be called up during maximum generation alerts.”  

MidAmerican Energy’s Dennis Kimm asked for more nuance beyond the two capability classes. He said MidAmerican has several LMRs that can respond within two hours but none that are ready within 30 minutes. Leovy advocated for the 30-minute requirement to be bumped up to a two-hour response time. 

Schabla said LMRs are more highly accredited than any other in its resource stack, yet the LMRs are less available than any other in its resource stack. “There’s a fundamental disconnect here.” 

Though MISO officially has about 12 GW of LMRs, staff have said MISO receives only about 7 GW to 8 GW worth of movement during emergencies. 

Schabla said the gap does not necessarily mean LMR owners are doing anything wrong or gaming the system. He said it likely represents a “misalignment between what is accredited and what is available.” 

In August, Reliability Subcommittee Chair Ray McCausland called the LMR response rate “eye-opening” and “a huge concern.” 

The RTO currently has an “inability to access many of the megawatts available in a useful time frame,” Executive Director of Market and Grid Strategy Zak Joundi said at MISO Board Week this month. The inability is magnified by the fact that MISO currently must declare an emergency before gaining access to load adjustments, he said.  

“We want to make sure [that] if someone is clearing the Planning Resource Auction, we can access those resources and they can deliver,” Joundi said. 

Joundi acknowledged to board members that stakeholders were dissatisfied with MISO’s timeline.  

“Ultimately, we want to make sure the rules we file at FERC are effective,” Joundi said. “Our goal is not necessarily to discourage the megawatts that are important. We want to make sure there are megawatts that we can leverage under the circumstances that we do.” 

MISO will again discuss LMR accreditation with stakeholders at its Oct. 9 Resource Adequacy Subcommittee meeting. 

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California GHG Emissions Decreased 2.4% in 2022

California’s greenhouse gas emissions fell by 2.4% in 2022 compared with the prior year, with the largest decrease seen in the transportation sector, according to a report released Sept. 20 by the California Air Resources Board.

The state’s total GHG emissions were 371 million metric tons (MMT) of CO2 equivalent in 2022, a figure that includes emissions from imported electricity. The decrease from 380 MMT in 2021 resumes the generally declining trend of GHG emissions that the state has seen since 2004.

The year 2021 was an exception to that trend, when GHG emissions grew by about 3%. The emissions increase in 2021 was viewed as rebound from the COVID-19 pandemic, which sent GHG emissions plummeting in 2020.

According to the CARB report, the transportation economic sector accounted for 39% of California’s GHG emissions in 2022, followed by the industrial sector at 23%. The electricity sector contributed 16% of the state’s GHG emissions: 11% from in-state generation and 5% from imports.

Transportation sector emissions fell by 5.2 MMT in 2022, a 3.6% decrease. Emission decreases were seen for passenger vehicles as well as heavy-duty vehicles. CARB attributed the drop to the increased use of renewable fuels and growth in the zero-emission vehicle market.

Emissions from electricity generation fell by 2.6 MMT, or 4.1%, in 2022 due to increases in in-state solar power and hydropower and an increase in imported wind power, according to the report.

GHG emissions dropped in five out of seven sectors that CARB tracked. Emissions were up by 1.7% in the residential and commercial sector, which CARB attributed to an increase in commercial activity following the pandemic. On the residential side, emissions fell slightly in 2022.

California’s agricultural sector accounted for 8.0% of statewide GHG emissions in 2022. Livestock emissions, which are responsible for 70% of the sector’s emissions, fell in 2022 due to the use of methane digesters funded by the California Climate Investments and incentivized by the Low Carbon Fuel Standard, CARB said.

Assembly Bill 32 of 2006 set a state limit of 431 MMT of GHG emissions in 2020. California emissions dropped below that limit in 2014, six years ahead of schedule. Now the state is working to reduce GHG emissions to 260 MMT by 2030, a limit set by Senate Bill 32 of 2016.

The state has set a target of net-zero emissions by 2045.