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November 7, 2024

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PJM Rejects Storage as Alternative to Brandon Shores RMR

PJM is rejecting a study that suggests it could avoid extending the 1,295-MW Brandon Shores generator’s life by installing storage and reconductoring several lines outside Baltimore. 

The analysis, conducted by GridLab and Telos Energy, found that installing a 600-MW battery at the Brandon Shores point of interconnection and reconductoring several 115-kV lines could provide the grid services offered by the generator and be in place in time for the 2025 retirement requested by plant owner Talen Energy.  

The study estimated the battery would cost $452 million after tax credits and could produce $348 million in net revenues over 20 years. Comparing Brandon Shores to other generators that have received RMR contracts, the study estimated that continuing to run Brandon Shores could cost $258 million per year. 

“We think this is a model that could be exported throughout PJM and even in other ISO regions as well: opportunities to replace retiring generation with storage as a means to avoid an RMR and … have a stronger system, a more reliable system, instead of paying for an uneconomical plant to stay online for several more years until transmission upgrades come in,” Gridlab Senior Program Manager Casey Baker said. 

PJM is in talks with Talen Energy to keep the generator running until its $796 million Grid Solutions Package is completed in 2028 to address expected reliability violations. The project includes a new 500-kV substation, a new 500-kV line between the Peach Bottom and Graceton substations and a 230-kV line from Graceton to a new 230-kV Batavia Road substation outside Baltimore. (See FERC Approves PJM RTEP Projects over State Protests.)  

PJM spokesperson Jeff Shields told RTO Insider that a battery installation is not a viable alternative to an RMR for Brandon Shores. (See “Brandon Shores Deactivation to Require $786M in Grid Upgrades” PJM PC/TEAC Briefs: June 6, 2023.) 

“PJM does not believe that a battery solution would address the comprehensive reliability needs in the BGE and surrounding areas, be able to be put in place by 2025, or be economically feasible,” Shields said in an email. “The Brandon Shores RMR is a must to maintain regional reliability until any additional enhancements could even be considered in the future.”  

Sierra Club Senior Attorney Casey Roberts said she believes there is time for PJM to consider alternatives to keeping Brandon Shores online. 

“The deactivation dates are June 2025, so we think there’s actually a pretty good amount of time for PJM to look at alternative solutions and see what else can be implemented. PJM has expressed some urgency with nailing down an RMR agreement with Talen for Brandon Shores as soon as possible, but in our view it’s better to take a little bit of extra time to make sure you have the most cost-effective and reliable solution rather than rushing to the thing you’ve always done,” she said. 

She pointed to the example of the Petersburg Generating Station retirement owned by AES Indiana, where the utility is planning on switching two of the four coal units to natural gas, retiring the other two and installing an 800-MWh battery. 

“We have definitely seen examples of coal plant sites and interconnection rights being repurposed for varying forms of clean energy, also for natural gas, but it’s essentially a way of seamlessly replacing the grid services provided by a retiring asset by something else. … Some of those examples are storage,” Roberts told RTO Insider. 

Roberts said that RTOs can be limited by a status-quo bias that pushes them to prefer solutions and resources that their staff have prior experience with. 

“PJM doesn’t see itself as being in the business of procuring generation, so in the example where an RMR could be avoided by the installation of wind or solar, for example, PJM just doesn’t see that as a tool in their toolbox right now. They see their only tool as to procure transmission technologies … or to pay the retiring generator to stick around for a few more years,” she said, adding that other RTOs do have processes to procure the reliability services provided by thermal resources. She noted that the Maryland Public Service Commission had protested PJM’s Grid Solutions Package filing, arguing that the RTO’s proposed solution had not considered a state law requiring the development of 3 GW of storage in the state, which the PSC argued provided an opportunity for PJM to work with the state to find alternatives (ER23-2612). 

Tori Leonard, spokesperson for the PSC, said the commission appreciates the study and understands that PJM will be providing a full assessment of its findings. 

To conduct the study, GridLab and Telos consulted with PJM to perform their own reliability analysis, confirming that the deactivation of Brandon Shores without any modifications to the grid would result in reliability violations. The most severe line overloads were found under summer peak load conditions with an unplanned outage occurring during a maintenance outage — an N-1-1 scenario.  

The worst voltage collapse contingency was seen during an extended winter peak with high generation or transmission outages, such as the December 2022 Winter Storm Elliott. Baker said that the modeling showed that if the summer violations were resolved, winter needs would also be met. 

In an announcement of the analysis, the Sierra Club argued that storage combined with the line reconductoring identified could not only meet the needs until the Grid Solutions Package’s completion, but that the battery’s characteristics could bring added reliability over the retiring coal generator. 

“The battery storage solution can also be more reliable than the coal solution, since batteries can start up and inject power far more quickly than a coal plant. Many reliability events arise on short notice due to unexpected outages of other power facilities, so the quick response of the battery could make all the difference in keeping the lights on,” the announcement said.  

“Unfortunately, PJM lacks a framework to evaluate alternatives like this to RMR agreements. Instead of clearly defining the reliability need and seeking the most cost-effective solution, PJM assumes only the retiring generator can provide reliability, and will pay whatever it takes to keep them online … PJM’s approach reflects a missed opportunity to uphold its responsibility to ensure bulk power system reliability while also supporting state clean energy policies.” 

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Utility Regulators Repeat Concerns About Tx Siting Oversight

State utility regulators reiterated their concerns about FERC’s efforts to promote transmission development at the Feb. 28 meeting of the task force established for that purpose. 

The issue of federal authority usurping state and local control has been raised repeatedly since plans were announced to create National Interest Electric Transmission Corridors (NIETCs) and to give backstop authority to FERC. (See What are National Interest Electric Transmission Corridors and Why Do We Need Them?) 

Grid constraints are a potentially fatal obstacle to the electrification goals set by the federal government and many states. Siting new transmission to address those constraints can be slow and difficult, particularly for lines that cross regional boundaries. NIETCs and backstop authority are two ways to potentially address this. 

The Feb. 28 meeting was the eighth for the Joint Federal-State Task Force on Electric Transmission, formed under a June 2021 FERC order (Docket AD21-15-000). FERC Chair Willie Phillips and Kimberly Duffley of the North Carolina Utility Commission co-chair the task force. 

Phillips said Feb. 28 that FERC has already heard the concerns of states and stakeholders during the comment process, “but there is something to be said for sitting around this table and hearing from you directly, and face-to-face.” 

Moderator Jonathan Raab opened the discussion by asking task force members to identify the transmission siting challenges that exist in their regions. 

Kansas Corporation Commission Chair Andrew French said the growth of renewable generation on the Plains has created difficult optics. 

“More and more,” he said, “as energy becomes exported, there’s at least a perception that Kansas land is increasingly being used to benefit faraway customers in other states to satisfy their policy goals.” 

Riley Allen of the Vermont Public Utility Commission had good things to say about the transmission siting process in his state and in the ISO-NE region. But he noted it typically takes 13 to 20 months in Vermont, which exceeds the 12-month threshold that is one of the triggers proposed for FERC backstop action.  

“But I think there’s room for improvement,” he said. “I think backstop authority will certainly add some life to the timeliness of these things going forward.” 

Darcie Houck of the California Public Utilities Commission said complications frequently arise when working with federal land management agencies, particularly when coordinating joint environmental processes. Also, federal technical studies supporting permitting often are delayed. And the PUC must coordinate with tribal nations and local governments, creating a complex process with many stakeholders.  

“Another challenge to timely siting of transmission comes from substantial community opposition,” Houck added, which often includes legal challenges demanding PUC response. 

Tricia Pridemore of the Georgia Public Service Commission listed several complicating factors nationwide, including regulations on federal land, local opposition, disagreements over environmental reviews and cost allocation, interconnection queue delays, supply chain constraints and multilayered planning processes with multiple responsible entities.  

These usually are not an issue in the Southeast, she said, due to its market structure, but major transmission projects there still take years to build, due to their complexity — seven years or longer for a 50-mile, 500-kV line. 

“The intensely local and regional differences are of course what makes one-size-fits-all transmission policies very challenging,” Pridemore said.  

She welcomed changes to federal policies that would remove barriers to transmission development but added: “From the vantage point of the Southeast, we must also ensure that those changes do not upend processes that are working so well.” 

The task force retained a collegial tone, but Pridemore was not alone with concerns; others cited other potential sticking points. 

Wyoming PSC Chair Mary Throne said whatever new federal process emerges should allow state and local review to play out before initiating a parallel federal process. 

“Concurrent proceedings are probably not ideal,” she said. “Certainly, in Wyoming’s case and most places in the interior West, I don’t think it’s the state and local proceedings that are slowing down the processes — not that we are incapable of our own bureaucratic delays and duplication. But understanding the local lay of the land before you start is essential.” 

Pennsylvania Public Utility Commission Vice Chair Kimberly Barrow made a similar point: “A simultaneous prefiling process that’s going on while the state process is ongoing will be problematic.” 

States appreciate the need for speed and efficiency, but parallel proceedings would be confusing for stakeholders, she added, and it would be a conflict of interest for PUC staff to participate in both at once. 

Allen said the idea of simultaneous state and federal reviews is his one significant issue with the backstop proposal. “I would much rather see the processes sequenced,” he said, adding that stakeholders should be directed toward the state review because state processes have been groomed over the course of decades and inherently are local in character. 

That said, Allen does support the idea of backstop authority. “I just worry that if we push too hard in parallel it’s going to create some complications that are going to undermine the longer-term objectives,” he added. 

French urged that FERC not make some existing problems worse as it addresses others. “While I think that our planning does need to get more anticipatory, more holistic, solving multiple needs,” he said, “I think as you do those things, it becomes much more difficult to communicate to the public and to landowners why your state needs to build this project that is maybe serving lots of different stakeholders.” 

Connecticut Public Utilities Regulatory Authority Chair Marissa Paslick Gillett said many utility regulatory agencies are having trouble recruiting engineers and other staff to do the work needed, and many of those hired are early in their careers, so technical assistance from federal agencies is helpful. 

“I will say however, sometimes it’s difficult to even take advantage of free assistance.” That might sound like an oxymoron, she acknowledged, but if a state requires a contract and a fixed timeline for anyone involved in the process, it is not. 

New York PSC Commissioner John Howard urged greater federal control over a specific area of concern for his state: getting the mandated 9 GW of electricity from offshore wind turbines to land, and someday more than 20 GW. New York has finite opportunities for radial transmission lines from each wind farm to land because of its geography, he said. A meshed offshore grid that spans RTO boundaries from New England to the Mid-Atlantic is a better solution. 

“Now is the time to begin planning for this multi-ISO meshed network,” he said. “I would pose the question to this group and to FERC: Is it time to acknowledge that the Atlantic Ocean may be a national interest corridor in and of itself? That is something we should come to grips with very quickly.” 

Howard added: “I don’t believe that the states alone will be able to find the individual leadership necessary to move this process forward.” 

Houck said California supports the goals of NIETC and backstop, but she picked apart some of the details of those proposals. Twelve months may not be enough time for a state to approve a complex project, she said, but at the end of those 12 months, the state might be able to conclude the process more quickly than FERC would if it started a backstop proceeding. 

She called for a more nuanced approach than a one-size-fits-all solution. 

Michigan PSC Chair Dan Scripps said if a proposed transmission line is entirely within a state and will serve only that state, great deference should be given to the local siting authority. “It’s unclear to me why FERC would substitute its judgment for the local siting authority — for a single-state project.” 

If a multistate RTO project benefiting multiple states is being blocked by one state, there could be a role for backstop authority, Scripps added, but FERC should limit itself to siting, and leave cost allocation and planning to the RTO.  

French made a similar point: ”If a state is, in FERC’s opinion, acting too parochially in looking at the need for the line, not considering regional and interregional benefits,” he could understand FERC stepping in. 

But if FERC finds it needs to override a state decision, he said, it should do so as narrowly as possible, and defer as much as possible to the state’s underlying proceeding, particularly on the routing of a proposed line — review of which is a large part of the state regulator’s workload. 

French also urged clarification on what exactly a FERC siting permit would entail — just routing, or also things such as interconnection and cost recovery mechanisms. “I think there is a lot of angst from folks about what approval of a line through the backstop siting process really means.” 

Duffley said she thought that with the Feb. 28 meeting, the task force had covered the ground it set out to cover. “FERC’s final rule on transmission issues, we’re all anticipating that it will be issued soon,” she said. 

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Groups Ask Montana PSC to Consider Climate Impacts in Rulemakings

More than 40 Montana organizations this week petitioned the state’s Public Service Commission to consider climate impacts when issuing utility rulemakings.  

The organizations — including the Montana Wildlife Federation, Montana Environmental Information Center, the Montana chapter of the Sierra Club and Forward Montana, and represented by Earthjustice and the Western Environmental Law Center — filed Feb. 28 to compel the Montana PSC to “include consideration of the economic, social and environmental implications its regulatory decisions have on the climate.” 

The groups cited August’s Held v. State of Montana ruling, which found that the Montana Constitution entitles residents to “a fundamental constitutional right to a clean and healthful environment, which includes climate as part of the environmental life-support system.” The state district court also found that the constitution charges the government with taking “active steps to realize this right” and said that “Montana’s climate, environment and natural resources are unconstitutionally degraded and depleted due to the current atmospheric concentration of [greenhouse gases] and climate change.” 

Lander Busse, one of 16 youth plaintiffs in Held v. State of Montana, joined in signing the petition to the PSC. 

The Held case challenged a Montana Environmental Policy Act (MEPA) requirement that forbade state agencies from contemplating climate change in decisions. The Montana Legislature has exempted the PSC from MEPA. However, the petitioners say that the regulators nevertheless have a clear “constitutional obligation to maintain and improve a clean and healthful environment for present and future generations.”  

In February, state Attorney General Austin Knudsen appealed the ruling to the Montana Supreme Court, contending that Montana cannot remedy the harm to the plaintiffs because the state is not solely responsible for GHG emissions.  

The appeal came a month after the Supreme Court declined to stay the ruling, saying state regulators must consider climate change in their permitting decisions pending an appeal.   

The Held plaintiffs have until mid-March to respond to the state’s appeal brief. 

The environmental groups said the PSC makes decisions concerning Montana gas and electric utilities “that can either promote or discourage continued utility investment in fossil fuel infrastructure,” the chief cause of climate change. 

“Thus, the PSC has the most consequential role of any decision-making body in the state in determining Montana’s impact on the climate,” they wrote in a Feb. 28 press release. 

The groups said Montanans need greater protection from “profit-seeking and environmentally destructive utility decisions that could saddle them with higher utility bills and increase harm to the climate.” They said if PSC refuses to factor the economic and environmental impacts from climate change into utility oversight, customers will pay more for electricity in the long run and be forced to “endure further unaffordable and unconstitutional effects of a changing climate.”  

“After this summer’s historic ruling in the Held v. State of Montana youth climate trial, it is clear that all state agencies must act affirmatively to preserve and protect Montanans’ constitutional right to a healthy climate,” wrote Nick Fitzmaurice, an energy transition engineer with Montana Environmental Information Center. “Burning fossil fuels for energy is the primary driver of our changing climate which is harming our environment and economy. As Montana’s regulator of monopoly utilities, the Public Service Commission is uniquely positioned to stifle climate impacts in the state and promote more affordable clean energy. It is the commission’s constitutional mandate to fully consider climate impacts in its regulation of Montana utilities.”  

The PSC declined to comment.  

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SERC: Details Crucial for Physical Security Plan

Utilities attending SERC Reliability’s Spring Reliability and Security Webinar certainly needed no reminders of the dangers firearms pose to electrical equipment. Barely a year had passed since the Moore County shootings of December 2022 — when still-unidentified attackers damaged two Duke Energy substations, leading to a loss of power for about 45,000 customers — and the nearly weeklong crisis hasn’t been far from grid operators’ minds since. (See Duke Completes Power Restoration After NC Substation Attack.) 

But SERC Senior CIP Engineer Justin Kelly noted in the Feb. 28 webinar that gunfire damage also may have a much more mundane cause, discussing his experiences with rural utilities that must deal with “a gun club next door.” 

“I remember hearing a story of an entity that was having their insulators shot in a specific area,” Kelly said. “What they did is, they hung a target from the transmission line so that [the neighbors] would have something to shoot at, and … the people stopped shooting at their insulators as soon as they did that.” 

Kelly said his goal was to remind attendees that physical security threats can arise for a broad range of reasons, not all of them malicious — but utilities always must take them seriously.  

Compliance with NERC’s Critical Infrastructure Protection (CIP) reliability standards is a good starting point, Kelly said, but he agreed with his colleague Drew Slabaugh — the regional entity’s senior legal counsel for legal and regulatory affairs — that entities must understand the standards’ requirements are “results based, not paperwork based.” Treating compliance as an exercise in “check the box just to say we did it” may leave important vulnerabilities exposed. 

Kelly emphasized that while there are basic protections that can and should be installed at most facilities, such as cameras and fences, utilities also must look beyond these generic steps to ensure their substations are truly secure. This means considering the “unique characteristics” present at a facility that adversaries can take advantage of. 

As an example, Kelly mentioned a substation he visited with a “dead-end tower” nearby — meaning a self-supporting tower installed where transmission lines change direction that must be built to heavier specifications to manage their large “lateral loads.” Kelly noted construction going on near the tower, adding pointedly that “if you take the bolts off of the bottom of those towers, they can pull over in the direction that they’re being pulled by the line.” 

Terrain is another variable that can lead to differences in vulnerability between facilities. Bill Peterson, SERC’s director of entity development and communication, observed that a mountain was a key factor in the 2013 attacks on the Metcalf substation in California, giving the attackers clear visibility into the facility that was in a depression nearby. (See Substation Saboteurs ‘No Amateurs’.) 

Even when entities properly identify their unique threats, there may be little benefit without follow-through. Kelly said utilities must make sure threats are met with proper responses and that everyone involved in the entity’s CIP compliance is on board.  

“I remember one entity I was at; they identified a threat [from] a specific actor. They did not provide any information [about] how they were addressing that threat, but when we asked about it, they said, ‘Oh, that person is actually in jail. That’s why we’re not doing anything about it,’” Kelly said. “But they didn’t document that anywhere. So there [was] no real ranking and understanding of what [they considered] to be the biggest threat here [and] the biggest vulnerability.” 

Kelly also noted that many utilities fail to categorize their threats appropriately, ranking hazards like copper theft with the same urgency as much more immediate threats to reliability. He urged entities to work on prioritizing their risks so they devote appropriate resources to keeping the grid safe in the most efficient manner. 

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EPA Tackles Port Pollution With $3B in IRA Funds

EPA has launched an all-out effort to reduce greenhouse gas emissions and other air pollution at U.S. ports by investing close to $3 billion in federal funds to replace diesel-powered equipment with zero-emissions ships, trucks, trains and other cargo-handling infrastructure.  

The lion’s share of the money from EPA’s Clean Ports Program, $2.8 billion, will be awarded through a Zero Emission (ZE) Technology Deployment Competition, which will target “mobile-source” emissions, according to a Feb. 28 announcement. Another $150 million will go to a Climate and Air Quality Planning Competition, to fund a range of climate and air quality initiatives, including emissions inventories, strategy analysis, community engagement and identification of resiliency measures. 

The deadline for applications for both programs is May 28, and individual groups or organizations can apply for funding from both programs, according to EPA. 

As outlined in the funding announcements, Clean Ports aims to balance the vital role ports play in the U.S. economy with the large amount of air pollution ― including greenhouse gas emissions and small particulate matter ― produced by the diesel-powered trucks, trains and other equipment used at these facilities. 

“Our nation’s ports are among the busiest in the world, helping us to create good jobs here in America, move goods, and grow our economy,” EPA Administrator Michael Regan said in the announcement. The new funding from the Inflation Reduction Act would help ensure “America leads in creating globally competitive solutions … [with] cleaner and more efficient technologies while cutting air pollution to protect the people who work at and live near ports.” 

“Communities near our nation’s ports are disproportionately impacted by air pollution and other environmental hazards,” said Brenda Mallory, chair of the White House Council on Environmental Quality. “Today’s announcement will help ensure families who live, work and play near our ports have cleaner air to breathe and a healthier environment.”   

“There’s an incredible array of new technologies that can make ports cleaner and greener,” National Climate Advisor Ali Zaidi added. “The Clean Ports Program is demonstrating how these technologies can work together.” 

Who, What, Where and How Much

Eligible applicants for both funding opportunities are port authorities or state, regional, local or tribal agencies with jurisdiction over a port, air pollution control agencies or private companies that work at or partner with ports.  

Equipment eligible for ZE funding includes cargo handling equipment such as tractors, forklifts and top handlers, which are used to move large containers. Trucks, locomotives and rail cars used to transport goods from ports can be funded, along with “harbor craft” such as tugboats, fishing vessels, barges, patrol boats and ferries. 

As outlined in the announcement, the ZE competition will include three “tiers” for different sizes and types of ports. 

One tier, for large water ports, will award five to 10 grants of $150 million to $500 million, while the second tier for smaller water ports and truck and rail facilities, called “dry ports,” will give out 25 to 70 awards ranging from $5 million to $150 million.  

Smaller ports are defined as those that have handled less than 8 million tons of cargo per year for the past three years, based on data from the U.S. Army Corps of Engineers. 

A final tier, for tribal applicants at small or dry ports, will provide two to 10 awards of $2 million to $50 million.  

The top tier will require 20% in matching funds; smaller and dry port projects will need a 10% match, and tribal awards will cover 100% of costs.  

The Climate and Air Quality Planning Competition will provide funding for a broad range of activities, such as collecting and analyzing data for current emissions inventories or projected future inventories, truck counts and traffic studies, and assessing the cost and feasibility of various emissions reduction strategies.  

EPA expects to award between 50 and 70 grants, with a minimum amount of $200,000 and a maximum amount of $3 million. The EPA has 10 regional offices across the country, and at least one award will be made in each of these regions. A minimum of 10 awards also will be reserved for small water ports, and at least two for tribal applicants. 

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WestTEC Transmission Effort Selects Stakeholder Committee

Western Power Pool has announced the 24 members of a stakeholder group that will participate in the Western Transmission Expansion Coalition (WestTEC), a West-wide transmission planning effort. 

The appointments to the Regional Engagement Committee (REC) complete WestTEC’s organizational structure as the group dives into its work this year. 

WestTEC’s goal is to approach transmission planning across the West in a “holistic and coordinated manner” to meet the grid’s future needs, according to a concept paper released last October. (See Plan Seeks to Boost Prospects for New Transmission in the West.) 

Western Power Pool (WPP) serves as the WestTEC facilitator. 

“Having this last committee filled is a big step,” WPP CEO Sarah Edmonds said in a statement Feb. 27. “We will bring the group together in the very near future so they can start their important work.” 

The WestTEC effort is being overseen by a Steering Committee consisting of representatives of transmission-owning utilities from across the West; WECC; and the region’s three planning groups — CAISO, WestConnect and NorthernGrid. The steering committee is WestTEC’s primary decision-making body. 

A WestTEC Assessment Technical Team (WATT) will define the scope and approach for a transmission study, working with consultant Energy Strategies. WATT will receive guidance from the steering committee. 

The REC will provide input to the steering committee and will play a “critical role” in WestTEC, according to Edmonds. 

Among the REC’s 24 members are four members of the WestTEC Steering Committee, who will “ensure continuity between committees,” WPP said: Kris Bremer of PacifiCorp, Todd Fridley of Public Service Company of New Mexico, Ravi Aggarwal of the Bonneville Power Administration and Kris Raper of WECC. 

In addition, REC will include representatives of the following sectors: 

    • consumer-owned utilities: four members, including Chris Heimgartner of Whatcom County (Wash.) PUD. 
    • public interest organizations: four members, including Vijay Satyal of Western Resource Advocates. 
    • ratepayer advocacy organizations: two members. 
    • tribes: one member. 
    • independent transmission companies: four members, including Robb Davis of GridLiance. 
    • independent power producers: four members, including Tashiana Wangler of Avangrid Renewables. 
    • industrial customers: one member, Heidi Ratz of the Clean Energy Buyers Association. 

The REC’s makeup changed from that outlined in the concept paper in response to stakeholder feedback, WPP said.  

Representation was expanded from two to four members for some sectors, including public interest organizations, independent transmission companies and independent power producers. Other sectors, such as investor-owned utilities, were eliminated from REC due to their representation on the steering committee. 

The state agency sector was removed from REC because states plan to engage with WestTEC through the Committee on Regional Electric Power Cooperation’s Transmission Collaborative. 

A full list of REC members is available in WPP’s release. A list of Steering Committee and WATT members is here. 

WPP gave a WestTEC update during a call Jan. 29. (See Group Looks to Create ‘Actionable’ West-wide Transmission Plan.) In addition, WPP said it plans to hold quarterly public webinars on the project.

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ERCOT CEO Cool to Linking to Neighboring RTOs

ERCOT CEO Pablo Vegas on Tuesday threw cold water on the possibility of linking the ISO and the national grid’s other two interconnections. 

Reacting to “one of the important topics that comes up on a regular basis,” Vegas told his Board of Directors that interconnecting the Texas grid with its neighbors is a complex issue requiring extensive analysis and input from legislators and regulators. Connecting with other grids is not just a reliability and resilience issue, he said, but one of economics. 

“It’s really a question as to whether it would be the most economical way to improve reliability and resiliency by interconnecting the grid to other grids, or would the dollars spent be better served and give us better reliability if we were to invest inside of Texas in additional transmission and other resources to help with reliability and resiliency,” Vegas told the directors during their bimonthly meeting. “That’s really the fundamental question. We’re not debating that there could be reliability or resiliency benefits by having interconnections. The question is, is it the best way to spend the dollars to get them?” 

During severe weather conditions, he said, ERCOT’s neighbors would also likely be dealing with the same storms, making it less likely they could share energy with the Texas grid operator. Vegas also warned that the interconnections could have a “chilling” effect on new generation investment in ERCOT. 

“[DC ties] could have the effect of making it less economically advantageous to build power plants inside of ERCOT,” Vegas said. “You could see scenarios where it would make more economic sense to build them right outside of our economy, potentially benefiting from some of the capacity market and revenues that would be available in the SPP market or in the MISO market, and then selling that power back into ERCOT when market pricing is high. 

“There’s a lot of really important considerations,” he added. “You really need to model the economic impacts … between regions when [they’re] interconnected to fully understand the cost benefit or the cost impact on the ERCOT market. Those models don’t exist today. Those have to be developed and really assessed to understand the true economic impact inside of ERCOT and outside of our economy.” 

An economic study is coming, said University of Texas engineering professor Michael Webber. Webber posted during the board meeting that his research team has conducted an analysis of the economic, environmental and reliability benefits of connecting ERCOT to neighboring grids. 

The study has been presented and will be published “soon,” he said. 

The calls for interconnection outside of Texas have grown since the 2021 winter storm. During that February, ERCOT was forced to shed load to keep the system balanced as generators dropped offline in the frigid temperatures.  

U.S. Rep. Greg Casar (D-Texas) introduced a bill earlier this month mandating interconnections between ERCOT and its neighboring grids. He says the bill would reduce load shed like that during Winter Storm Uri and allow low-priced renewable energy to be sold outside the Texas grid. 

The legislation was roundly derided by speakers at an ERCOT conference after it was released. (See “AC Link to National Grid Unlikely,” Overheard at Infocast’s 2024 ERCOT Market Summit.) 

Texas does have four DC ties — two with the Eastern Interconnection and two to Mexico totaling about 1,200 MW — that are used for scheduled and emergency trades and are not treated as interstate interconnections.  

A proposed DC tie, Pattern Energy’s Southern Spirit 345-kV link into the SERC Reliability region, gained regulatory approval in 2022 after seven years of review. FERC has said the project, formerly known as Southern Cross Transmission, would not trigger its jurisdiction over Texas. (See “SCT Proceeding Closed,” Texas Public Utility Commission Briefs: Sept. 29, 2022.) 

The Public Utility Commission of Texas and ERCOT have both taken steps to address the issue. The PUC has opened a proceeding on DC ties’ minimum deliverability and planning assumptions and asked stakeholders to submit feedback (55984). The commission is expected to discuss the item during its March 7 open meeting. 

At ERCOT, stakeholders have tabled a revision to the planning guide (PGRR105) since September over cost-allocation concerns. The measure would add DC ties to the list of resources subject to minimum deliverability conditions. 

Vegas, echoing ERCOT’s comments in the PUC’s docket, told the board that any interconnections will require transmission infrastructure on both sides of the tie to “fully leverage and import the energy across them.” 

“You really need to think about the economic cost overall and the economic cost of having those ties and what it means to pricing between ERCOT and the other regions that it’s connected to,” he said. “When pricing is high in ERCOT and lower in areas outside, there is the potential that you could see benefit in lowering the cost to residents inside of ERCOT in that circumstance. The flip is also true. When pricing is higher outside and lower inside of ERCOT, you could see a raising of the pricing inside of ERCOT as the price arbitrage is normalized through these DC ties.” 

R Street Institute’s Beth Garza, who doubted during the ERCOT market summit that Casar’s bill would go anywhere, told RTO Insider she was “intrigued” by Vegas’ questioning of whether interconnection costs would be reasonable compared to other actions to improve reliability. 

“He and the ERCOT board have vigorously challenged the [Independent Market Monitor’s] estimate of the cost of other reliability enhancements,” she said, pointing to the ERCOT contingency reserve service product. The IMM has said the new ancillary service created artificial supply shortages that produced “massive” inefficient market costs totaling about $12.5 billion last year through Nov. 27. (See ERCOT Board of Directors Briefs: Dec. 19, 2023.) 

“We really need to look at the true cost, the economic impacts to the market, the economic impacts to the decision-making around generation and how generation would develop,” Vegas said. “And those are important issues that should be worked through the Public Utility Commission.” 

There were no questions from the board when Vegas finished his comments. 

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DOE Announces $366M for Rural, Tribal Clean Energy Projects

About 300 off-grid homes in the Hopi and Navajo nations soon could have electricity from solar and storage systems paid for with part of the $366 million in funding the U.S. Department of Energy announced Feb. 27. 

The financial awards from the Infrastructure Investment and Jobs Act also will help install 675 whole-home heat pumps in manufactured houses in rural Maine, a microgrid with storage and floating solar panels in the small Colorado town of Fort Lupton and 14 similar clean energy projects in rural and tribal communities. According to the DOE announcement, the projects will be in 20 states and 30 tribal communities.  

“Every community should benefit from the nation’s historic transition to a clean energy future, especially those in rural and remote areas,” Energy Secretary Jennifer Granholm said in the announcement.  

The funding underscores the administration’s commitment “to building an inclusive and equitable clean energy future that creates safer, more resilient communities, enhances tribal energy sovereignty, strengthens energy security and delivers new economic opportunities in every pocket of the nation,” the announcement said.  

The funding is part of DOE’s Energy Improvements in Rural or Remote Areas program, which is being administered by the Office of Clean Energy Demonstrations (OCED). All the projects are in or adjacent to disadvantaged, historically underserved communities with disproportionate levels of environmental pollution. 

The focus on tribal communities in the continental U.S. and Alaska recognizes the historic and economic challenges these areas face. According to a 2023 report from DOE’s Office of Indian Energy, 21% of homes in the Navajo Nation (with a total of 45,000 residents) and 35% in Hopi tribal communities (2,810 residents) do not have electricity, which also means they may not have running water. The report also noted that 31% of tribal homes with electricity report monthly outages. 

All projects designated for awards will enter negotiations for final contracts with OCED.  

Other projects designated for awards include: 

    • Alaskan Tribal Energy Sovereignty project: If finalized, this $26 million award would help upgrade existing diesel-powered microgrids with solar and storage in eight remote tribal villages with no access by road and only seasonal access by boat and air. The upgraded systems could cut diesel use by 40% and cut energy costs across the communities by $100,000 per year. 
    • Microgrids for Community Affordability, Resilience and Energy Decarbonization: Led by the National Rural Electric Cooperative Association, this $45 million project would create a consortium of rural co-ops in Arizona, California, Minnesota, Montana and Tennessee. The co-ops would install microgrids with solar, storage and distribution system upgrades “to demonstrate region-specific energy systems that improve energy access, enhance energy resilience and increase capacity for renewable energy deployments at a community level,” according to DOE. 
    • Montezuma Microgrid project: With a population of 1,460, the town of Montezuma, Iowa, plans to use its $9.4 million award to build the state’s first utility-scale microgrid, including 2.5 MW of solar, 1.5 MWh of storage and electric vehicle chargers “to reduce reliance on aging infrastructure and backup diesel generation.”  

All projects include community benefit plans with provisions for local job training and other economic development measures.  

Contracts with OCED would require ongoing evaluations through a “phased approach” that includes a series of “go/no-go” decision points based on implementation progress, the announcement said.  

In related announcements on Feb. 27, DOE opened a $25 million funding opportunity for additional tribal clean energy projects and an $18 million opportunity for “high-impact clean energy projects in disadvantaged communities, … small- and medium-sized cities and towns, and tribal communities.” 

The $25 million funding for tribal projects will focus on clean energy and energy efficiency projects for tribal buildings, community-scale clean energy and storage projects, and integrated energy systems that can operate off grid. 

The $18 million Communities Sparking Investments in Transformative Energy (C-SITE) program will prioritize funding for community-led projects that deliver direct clean-energy benefits, such as reduced energy costs and improved air quality, while drawing in additional investment for longer-term economic development.

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Sides Forming in Fight Over Michigan Renewable Siting Law

LANSING, Mich. — A fight pitting local governments and agricultural interests against environmental and renewable energy advocates over siting of solar and wind energy projects in Michigan is revving up in earnest ahead of a May petition deadline. 

A group called Citizens for Local Choice has sent out thousands of petitions in hopes of overturning a 2023 law shifting siting authority from local governments to the Public Service Commission.  

Democrats who backed the law said it is a critical step towards Michigan achieving net-zero-carbon status by 2040. It was enacted after numerous local governments, primarily in rural areas, blocked new renewable energy projects by making zoning changes. 

Under Michigan’s Constitution, the Legislature may enact the proposal in the initiated petition, and if it does, Gov. Gretchen Whitmer (D) could not veto the measure.  

If the Legislature does not enact the proposal — as is likely — it automatically goes before the voters in the next general election. With both the Michigan House and Senate under Democratic control, no one anticipates lawmakers passing a proposed law overturning a law they just passed. (Whitmer Signs Climate Bills, Including 100% ‘Clean Energy’ Goal.) 

Supporters need signatures from 356,958 registered voters — 8% of all the votes cast for governor in the 2022 election — by May 29. 

The Michigan Farm Bureau was the first large organization to endorse the proposal, despite supporters’ contention that the new law gives greater protection to farmers who want to either sell or invite projects onto their land. 

Also endorsing the proposal is the Michigan Township Association, which represents the more than 1,200 townships in the state, most of which are rural. 

However, the Michigan Municipal League — representing cities and villages in the state — and the Michigan Association of Counties have not weighed in on the proposal. Nor have any large local governments. 

On Feb. 23, several environmental, alternative energy and public health groups announced their opposition to the petition. 

John Freeman, with the Great Lakes Renewable Energy Association, said giving the PSC siting authority will allow local farmers to realize a second income source by putting renewable energy projects on less productive land. 

Laura Sherman, with the Michigan Energy Innovation Business Council, said a solar project on one acre can power 80 houses, and just 90 minutes of wind driving a wind turbine could power a house for one month. 

But local control, which has traditionally been a politically popular position in Michigan, may now have the upper hand as petition-gatherers get out in the field — at least according to a poll cited by the townships’ association. 

The poll — conducted by Lansing-based Marketing Resource Group (which has often done polling for Republican and conservative groups) of 600 people in October — showed 87% of those asked believed local governments should have oversight on renewable energy projects within their borders. Majorities supported that position no matter the respondent’s political beliefs. 

Kevon Martis, a Lenawee County commissioner who is one of the leaders of Citizens for Local Choice, said the group is a successor to Our Home, Our Voice, a group that sought to block the law.  

Lenawee County Commissioner Kevon Martis is one of the leaders of the petition drive. | Lenawee County

In an interview with NetZero Insider, Martis said the group is not opposed to renewable energy but believes state regulators will not enforce noise and setback restrictions sufficient to protect local communities.  

“The focus of Citizens for Local Choice has nothing to do with whether or not one likes renewables,” he said. “I have townships in my county who have been open to solar development on farm ground, others have not. That should be decided locally. Same thing with wind energy: We have counties that host a lot of wind development, others are not happy with it and chose not to.” 

Although the group’s literature says their work is “paid for by regulated funds,” Martis said the group’s funding has come from individual donations and the Farm Bureau with none from either DTE Energy or CMS Energy. Spokespeople for the utilities confirmed they are not backing the effort.  

“When it says paid for by regulated funds, that means that the funds are all part of the campaign and the donations are disclosed,” Martis said. 

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Manchin, Phillips Discuss Expanding the Grid at NARUC

WASHINGTON, D.C. — FERC Chairman Willie Phillips and Sen. Joe Manchin (D-W.Va.) want to pass policies this year that speed up the rollout of transmission, they said at the National Association of Regulatory Utility Commissioners’ (NARUC) Winter Policy Summit on Feb. 27. 

FERC already has released Order 2023, which Phillips said he hoped would speed interconnection queues. Taking a project from entering the line to putting shovels in the ground now takes an average of five years. 

“We’re looking forward to doing long-term and regional planning as well,” Phillips said. “And we’re going to do it in a way that absolutely works with the state, collaborates with our state regulator colleagues, because you do understand the system better than anybody else.” 

When it comes to long-term planning, FERC is not looking to favor one group of state policies over any others, but rather wants to reflect the reality of what is happening on the ground, he added. 

“We know the policies across the country change,” Phillips said. “And we know we have more and different resources coming on all the time. It makes no sense to pretend otherwise.” 

Another transmission issue Phillips is committed to tackling is interregional transfer capability, which is beneficial in the increasingly common winter reliability events that have affected the grid over the past decade. 

“We can say that there are unplanned load sheds, but when something happens every other year, for the past 11 years, it’s difficult to say that it’s unplanned. I think it is stunningly predictable what can happen on the system. So, it’s our responsibility, I believe, to make sure that we have interregional capability to handle this.” 

NERC is working on a study on just how much interregional capacity would make sense, and Phillips said once that was complete, FERC would hit the ground running with a proposal to get that built. 

Manchin, who is retiring at the end of this year, hopes to get a “permitting reform” bill out of what he said was one of the least productive Congresses in history, having passed just 39 bills through its first year-plus compared to an average of more than 250. 

“The politics that we’re dealing with today has been weaponized,” Manchin said. “Whether you’re Democrat or Republican, independent, whatever you might be, God bless you, you’re not the enemy. And the person on the other side is not your enemy.” 

While people certainly have opposing views, they should be viewed as opponents who help strengthen arguments and are people you can work with, not enemies who need to be destroyed as many in Washington view them, he added. 

Manchin hopes to get an exception to that brand of politics by working with his fellow Energy & Natural Resources Committee leader, Sen. John Barrasso (R-Wyo.), on a bill to get energy infrastructure built quicker. 

It’s important to get some significant votes from both parties for their proposal to pass because in recent years, both Republicans and Democrats have made purely partisan pushes on the issue that have gone nowhere, Manchin said. 

“This is our last chance, and I am not walking out of here until I give every ounce of effort that I have to get a permitting bill done that gets you from the start to the finish within two to three years,” he added. 

Manchin said they’re still working out specifics on how to give states a first pass on dealing with major transmission projects that cross multiple states. He floated the idea of giving states and utilities a year to negotiate on siting and cost allocation before the federal government would step in. 

Another issue a bill would tackle is judicial reform, specifically by proposing to limit to six months the time parties have to sue once a project has been approved. They can wait up to six years now, he said. 

All these new policies are against the backdrop of an industry expected to see growing demand in the coming years from data centers, new manufacturing, and increasing electrification of transportation and heating. NERC has said demand should grow 38 GW in the next five years, which Phillips said would continue into future decades, as one study has demand growing at an average of 1% per year for the next three decades. 

“That means 5,000 terawatt hours of new energy on the system by 2050,” Phillips said. “It’s something that we think about a lot. Increasingly, when I’ve been meeting stakeholders, executives across the country, we’re talking about rapidly increasing demand.”