Search
`
November 12, 2024

Posted on

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.

Posted on

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. 

Posted on

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.

Posted on

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. 

Posted on

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.” 

Posted on

Northwest Public Power Group Endorses Markets+ over EDAM

A group representing the Northwest’s extensive network of publicly owned utilities has asked the Bonneville Power Administration to choose SPP’s Markets+ when the agency issues its day-ahead market “leaning” in April. 

The Portland, Ore.-based Public Power Council (PPC) laid out its case for favoring Markets+ over CAISO’s Extended Day-Ahead Market (EDAM) in a Feb. 23 letter addressed to BPA Administrator John Hairston.  

The PPC’s argument included the need to defend the right of BPA’s “preference” customers to access low-cost electricity from the Federal Columbia River Power System, continued reservations about CAISO’s ability to alter its state-run governance structure and concerns about the fairness of CAISO’s existing market practices — with the last point eliciting a pointed response from CAISO provided to RTO Insider. 

The letter also praised SPP’s stakeholder-driven approach for developing Markets+. 

“Currently, the Southwest Power Pool (SPP) Markets+ offering is PPC’s preferred day-ahead market option, and we support BPA making a similar declaration in its April leaning,” said the letter signed by PPC Executive Director Scott Simms and members of the group’s Market Development Committee (MDC). “While information is still evolving, the majority of criteria that PPC has evaluated supports continued pursuit of BPA’s participation in Markets+.” 

The letter was signed by all eight members of the MDC, which includes representatives from Idaho Falls Power, Tacoma Power, Fall River Rural Electric Cooperative (Idaho), Clatskanie (Ore.) Public Utility District, Pacific County (Wash.) PUD, Modern Electric Water Co. (Wash.), Grant County (Wash.) PUD and Snohomish County (Wash.) PUD. 

The MDC crafted the letter at the direction of the PPC’s Executive Committee, Lauren Tenney Denison, the organization’s director of market policy and grid strategy, told RTO Insider.  

Until recently, the MDC included Seattle City Light’s (SCL) Emeka Anyanwu, who left the utility last fall to take over as CEO at Lincoln Power in Nebraska. SCL, which operates a small balancing authority area, has been a key participant in the West-Wide Governance Pathways Initiative, which is working to establish the framework for a Western RTO that expressly includes CAISO and rests on the ISO’s technical capabilities. SCL did not respond to a request for comment on its position on BPA’s market choice in time for publication of this article. 

‘Dual Roles’

The Feb. 23 letter indicates PPC members clearly doubt the Pathways Initiative will be able to settle the CAISO governance issue in a manner they think is equitable for entities outside California.

“Current California law stipulates several areas that keep CAISO’s mission and operation tied with the interests of California,” the PPC letter says. “First, CAISO’s corporate status is tied to oversight from the state of California and thus the CAISO Board of Governors can neither irrevocably delegate authority nor allow another entity to unilaterally make decisions on market policies.” 

Second, the ISO’s Board of Governors is appointed by California’s governor and confirmed by the state Senate, the letter notes. 

The letter also argues that CAISO’s independence as the operator of a multistate market is “further confused” by its “dual roles.” 

“The CAISO functions both as a market operator and as a participant Balancing Authority Area (BAA) in the [Western Energy Imbalance Market] and EDAM markets. At times there is a lack of transparency about which role CAISO is serving when taking certain actions. This only adds to concerns about equity among market participants,” the letter states. 

Tenney Denison told RTO Insider that legal analysis conducted by the PPC and CAISO’s own legal staff as part of work by the WEIM’s Governance Review Committee indicates “a legislative change would be necessary to provide PPC members the assurance they need that their interests would receive equal consideration under CAISO governance. 

“We are closely watching the approach that is being taken by the Pathways Initiative, including developing a legal review of multiple options, and look forward to discussing those results with other stakeholders,” she said. “We are uncertain at this time whether there would be sufficient support for the types of changes that PPC is seeking and there is not a clear timeline of when such changes could be implemented if they are pursued.” 

The PPC’s governance concerns extend to CAISO market design issues that the group contends will carry over into the EDAM from the WEIM. The letter particularly points to market outcomes stemming from a sharp January cold snap in the Northwest, when the region was forced to import large volumes of power from the Rockies and Southwest regions, with supplies from the latter wheeled through the ISO. (See WPP: Cold Snap Showed ‘Tipping Point’ for Northwest Reliability.) 

Energy flows during the Jan. 12-16 weather event, which caused four entities to enter an Energy Emergency Alert (EEA) Watch, EEA 1 or EEA 3, and caused significant northbound transmission congestion out of CAISO and into Oregon, leading some Northwest entities to contend the ISO unfairly raked in the lion’s share of the revenue associated with that congestion, a point amplified in the PPC’s letter. 

“CAISO’s congestion policies resulted in over $100M of congestion revenues being collected by the CAISO BAA, despite most of the generation serving the Northwest coming from outside California. The policy creating this result is explicitly maintained in the CAISO EDAM,” the PPC wrote. 

But CAISO contested that assertion in its Feb. 27 email to RTO Insider. The ISO said outages on Oregon transmission lines during the cold snap meant the ISO could not send some energy north without damaging the Northwest grid. The resulting congestion on the California-Oregon Intertie resulted in CAISO collecting about $100 million in congestion rent from Northwest entities. 

“Despite the assertions in the PPC letter, the ISO does not collect congestion rent for itself,” CAISO said in the email. “It distributes it to holders of congestion revenue rights (CRRs). CRRs are mechanisms that guard against high congestion prices. They are available to a variety of market participants, including load-serving entities in the Pacific Northwest.”  

The ISO also noted it operates the only mechanism in the West for managing congestion in the day-ahead time frame. 

“Operators of transmission lines in the Pacific Northwest do not,” it said. “As a result, CAISO cannot ignore transmission constraints; it must avoid sending energy to areas where it cannot be received.” 

“That is why the ISO had to take action, and why congestion rents were collected on the California side of the constraint of the border and not by entities in the Pacific Northwest,” the ISO said. 

The PPC letter also raised another, more enduring complaint among Northwest electricity sector participants — that CAISO’s pricing policies don’t accurately account for the value of the region’s flexible hydroelectric generation. 

“This means that the federal generating facilities funded by PPC members would receive lower compensation for their generation, thus increasing the costs borne by PPC members for operating those facilities. A study co-funded by the PPC showed the potential for CAISO’s pricing policies to reduce revenues for Northwest generators selling into the CAISO BAA by $100M-$200M per year,” the PPC wrote. 

The PPC also points to a complaint shared with entities elsewhere in the West regarding CAISO’s decision, after California’s 2020 summer blackouts, to alter its tariff to restrict “wheel-throughs” in its territory during periods of extremely tight supplies. (See FERC Approves CAISO Wheel-through Rule Changes.) 

“This policy, which was heavily criticized by non-California parties, demonstrates the California-centric nature of the CAISO decision making process,” the PPC said.  

Stakeholders, Not Staff

The PPC’s critical comments about CAISO were matched by laudatory ones regarding SPP and Markets+.  

“SPP Markets+ has an equitable, inclusive, representative and independent governance structure. It includes committees comprised of market participants and stakeholders, which has resulted in a high level of engagement in the market’s design,” the group said. 

In a reference to CAISO’s more staff-driven model for initiating market changes, the PPC pointed out that in Markets+, “participants and stakeholders determine what proposals advance to the decision-makers, not SPP staff.” 

Referring to the proposed board structure for Markets+, the letter noted that “decisions are also made by a ‘panel’ of independent members who have no responsibility or obligations to any group of participants over another. This decision-making process ensures all market stakeholders have a voice in what policies are explored, developed and ultimately implemented.” 

The letter also points out that Markets+ includes elements that “will help BPA continue to serve its historic mission and return value to Northwest ratepayers for the federal assets they have financed through BPA’s rates.” 

Those include price formation policies that “will more adequately compensate BPA (and all suppliers) for flexible and reliable generation made available to the market — particularly in times of scarcity,” as well as the ability to “attribute” generation to specific loads. 

“PPC sees this as a useful tool for meeting BPA’s statutory obligation to serve preference customers from the federal system,” the letter said. “These and other tools included in Markets+ will also ensure that BPA customers can claim the environmental attributes of the low-carbon federal system,” helping PPC members to meet policy goals to reduce carbon emissions. 

“As stated in their letter to Bonneville Power Administration, the PPC believes Markets+ will allow fair pricing for generation and the ability to attribute generation to specific loads,” SPP spokesperson Meghan Sever said via email. “While these are a few of the benefits most recognizable to this group of entities, there are many more benefits of participation in Markets+, and SPP is pleased to be a part of developing a market that provides financial and environmental benefits and enhances electric reliability in the Western Interconnection for years to come.” 

Seams vs. ‘Superior Market Design’

The PPC letter played down the concerns among some industry stakeholders about potential costs and inefficiencies stemming from “seams” between two Western day-ahead markets. The issue was the subject of a recent study commissioned by the Western Power Trading Forum and Public Generating Pool. (See Western Market Seams Issues to Differ from East, Study Finds.) 

“Seams do have the potential to reduce market efficiency, but they also exist today in multiple areas (not just market to market, but [between] different Resource Adequacy programs, different carbon regulations, etc.) and will continue to exist into the future,” the PPC wrote, noting the loss of efficiency “can be outweighed by the benefits of superior market design and governance.” 

The group also expressed hope there will be “large incentives” for the two markets to work together to reduce seams issues “to the greatest extent possible, to facilitate continued trade.” 

PPC expects seams impacts could be mitigated by “significant amounts” of trading outside the day-ahead market. 

“Multiple studies evaluating different market footprints have suggested that seams have the greatest potential to impact entities in California, who rely on imports of Northwest resources at a low price,” the letter said, pointing to studies conducted by the Western Markets Exploratory Group. “This should only work to create an even greater incentive for the existing CAISO market to work together with Markets+ to ensure that trading can continue.” 

Asked how the PPC’s letter will influence BPA’s day-ahead market decision, agency spokesperson Nick Quinata said: “BPA appreciates the PPC’s participation in our public process and it is a comment we will consider as we continue to do our due diligence on whether or not to join a market and which market we select if we go that way.” 

Posted on

NYPA and NYU Partner to Scale up Transformer Monitoring Study

The New York Power Authority (NYPA) and the New York University Tandon School of Engineering on Feb. 22 announced a partnership that could help state utilities prevent costly and time-consuming large power transformer outages through a novel monitoring technique. 

NYPA will test NYU Tandon’s “Online Detection of Winding Deformations in Large Power Transformer” study at its Advanced Grid Innovations Laboratory for Energy (AGILe) simulation facility to assess if the school’s technique can be scaled up for the wider New York grid to improve the detection of transformer-winding deformations without statewide interruptions. 

“NYU Tandon aims to integrate into NYPA’s AGILe processes by developing a comprehensive model encompassing various common deformations in transformer windings,” Shayan Behzadirafi, a project engineer on NYPA’s Research, Technology Development and Innovation team, told RTO Insider. 

Experimental setup for winding deformation diagnostics system test; normal transformer (right), deformed transformer (left) | NYU Tandon, IEEE Transactions on Power Delivery (April 2018)

The partnership, supported by a nearly $190,000 grant from the New York State Energy Research and Development Authority’s Future Grid Challenge program — itself funded through the nearly $2.4 billion Clean Energy Fund — aims to digitally monitor NYPA’s large-scale transformers by continuously tracking the voltage and currents of transformers while accurately calculating its leakage impedance (14-M-0094). 

“The idea is to scale up the technique, which was tested with a 1-kVA lab transformer, to the NYPA large transformers of hundreds of megavolt-amperes,” Francisco de Leon, a NYU Tandon professor of electrical and computer engineering and one of the study’s authors, wrote in an email to RTO Insider. “If the project is successful, the condition-monitoring device will save money in unnecessary tests when the transformer is healthy or prevent catastrophic failures when the transformer has been damaged.” 

NYPA estimates that if the technique prevents many of the diagnostics required once a transformer is taken out of service because of winding deformations, the state could save about $15,000 per day and up to $1.5 million per incident. 

“Basically, what we are doing for transformers is giving them a smartwatch,” de Leon said in an interview with RTO Insider. “It is something that is monitoring all the time and giving real-time analysis of some of [the transformer’s] components without having to disconnect the transformer.” 

This has big implications for NYPA, the largest state public power organization in the U.S., as it operates more than 1,400 circuit-miles of transmission lines, has 16 generating facilities — including the hydroelectric Niagara Power and the St. Lawrence-FDR Power projects — and produces more than 80% of its electricity from renewables. 

Transforming the Future

NYU Tandon’s paper, published in the journal IEEE Transactions on Power Delivery in 2018, emphasizes how transformers’ windings, which consist of metal coils wound around the transformer’s core, “are subjected to strong electromagnetic forces” that can cause deformations. 

“To avoid crucial damage, it is necessary to detect winding deformation at an early stage,” the paper reads. 

New York has experienced transformer-related outages, explosions and fires, often because of equipment failures, which led to extended disruptions and costly repairs. 

Notable incidents include the December 2018 transformer explosion at a Consolidated Edison plant in Astoria, Queens, which painted New York City’s skyline bright blue. A 2021 incident captured on video in which a man in Queens survived a transformer explosion directly beneath him, and in January, another Con Ed transformer in Queens reportedly exploded, knocking out power for hundreds of customers for hours. 

Transformers with deformed windings are typically taken out of service for a frequency response analysis to test the mechanical integrity, but the technique being studied at AGILe could reduce the frequency of these occurrences and the need for such service interruptions. 

“Traditionally, bringing transformers out of service for frequency response tests is the norm,” Behzadirafi said. “However, if NYU Tandon’s methodology proves successful, it would eliminate the need for such disruptive measures. 

“By enabling the detection of transformer issues while the unit remains in service, the study offers a substantial improvement in minimizing downtime, increasing efficiency and enhancing the overall reliability and performance of the energy infrastructure.” 

New York Stays AGILe

Launched in 2017 in Albany, AGILe is described as a “a global center for electric grid research,” responsible for developing and testing “new and off-the-shelf clean energy technologies” to strengthen the state’s electric grid by fast-tracking their commercialization. 

It also helps utilities better understand the potential impacts of new technologies or techniques on the state’s grid. 

“Through this study, we hope to be able to give utilities confidence that this technique is reliable and will work for full-size transformers in the field,” said Alan Ettlinger, NYPA’s senior director of research, technology development and innovation. 

Behzadirafi elaborated on how NYU Tandon’s developed prototype would be evaluated. “Leveraging AGILe’s hardware-in-the-loop facilities, we will test the developed hardware against the deformation models to assess its performance and ensure its effectiveness in real-world applications.” 

“NYPA will conduct the study by evaluating whether the developed hardware can effectively detect various winding deformations using information provided by the software model,” he said. “The success of the study will be determined by the alignment between the outputs generated by the software model and the actual data obtained from the transducers, as well as hardware’s ability to detect, ensuring that the hardware reliably detects winding deformations in practical applications.” 

The prototype being assessed by AGILe identifies changes in short-circuit impedance, a key transformer health indicator, using advanced techniques like Lissajous curve methods to track winding deformations in real time. 

If found to work, the digital tool will detect emerging transformer winding deformations caused by stress from short-circuit events and send a warning alarm to an operator informing them the unit has a leakage reactance higher than the standard 3% recommended by the Institute of Electrical and Electronics Engineers.  

“If the outcome of this collaboration proves successful, NYPA is considering a potential second phase, which involves implementing the detector relay in conjunction with a real transformer,” Behzadirafi said. “Additionally, there is a possibility of engaging popular relay manufacturers to contribute to the development of the relay during the practical phase in the real-world scenario.”

Overview of New York Power Authority’s existing assets in state | NYSERDA

 

“My dream,” NYU’s de Leon said, “is that our technique is found to be successful and viable, since then we can partner with a relay manufacturer to produce a new relay prototype that is equipped with our tools and is then commercialized.” 

“Unique research collaborations like this one with NYU Tandon, supported by NYSERDA, enable the Power Authority and New York state to innovate and modernize its electric grid for the benefit of all New Yorkers,” NYPA CEO Justin Driscoll said. 

Posted on

FERC Challenges Market-based Rates for Idaho Power’s Home Territory

FERC threatened to revoke Idaho Power’s market-based rate authority in its home balancing authority area, citing the utility’s failure of a key market power test. 

The company, which provides electricity in a 24,000-square-mile territory in southern Idaho and eastern Oregon, submitted an updated market power analysis in October 2023, noting that it had increased its generation capacity in the Idaho Power BAA by 100 MW (ER10-2126-008). 

Although the company passed the pivotal supplier indicative screen for its BAA, it failed the wholesale market share indicative screen in three seasons, FERC said. 

The commission said the failures establish “a rebuttable presumption of horizontal market power” and required it to open a proceeding under Section 206 of the Federal Power Act to determine whether the utility’s market-based rate authority in its home region remains just and reasonable. 

FERC’s Feb. 27 order to show cause (EL24-62) does not threaten Idaho Power’s ability to charge market-based rates outside its home territory. The company said it passed the pivotal supplier and wholesale market share indicative screens in the Avista Corp., Bonneville Power Administration, Nevada Power Co., NorthWestern Corp., PacifiCorp-East and PacifiCorp-West balancing authority areas, as well as CAISO’s Western Energy Imbalance Market. 

Idaho Power told FERC it increased its generation by 100 MW:  

    • In June 2023, it began taking delivery of the entire output of the 40-MW Black Mesa Solar facility under a long-term firm power purchase agreement that runs until 2043; 
    • in June 2023, it downgraded the capacity rating at its Langley Gulch Power Plant by 20 MW; and 
    • in July 2023, it energized its standalone 80-MW Hemingway battery energy storage system. 

FERC gave the utility 60 days to respond to its order by either challenging the commission’s threat to revoke its MBRA, proposing mitigation to eliminate its market power or accepting cost-based rates. 

The commission said it already is examining a delivered price test analysis Idaho Power submitted to prove it lacked market power. It said the company can submit additional evidence that it lacks market power, such as historical sales and transmission data. 

The company can continue charging market-based rates in the BAA — but will be liable for potential refunds — while the commission evaluates the delivered price test. 

Posted on

Texas RE Warns Cyber Plan Essential amid Growing Threats

With an ever-increasing number of adversaries in cyberspace targeting the North American power grid, speakers at a webinar hosted by the Texas Reliability Entity on Feb. 27 emphasized that rigorous planning and testing are essential to maintaining electric reliability. 

“We need to remain at high alert and have a decisive plan that can respond to these types of threats,” said Texas RE CIP cyber and physical security analyst Jason Georgoulis at the regional entity’s regular Talk with Texas RE event. He cited the Pipedream and Volt Typhoon malware campaigns, which are linked to Russia and China, respectively. (See CISA Highlights China Threat in 2024 Priorities Report.) “Proper training, testing and learning from the gaps in these tests can help meet the purpose of the standard, which is to mitigate the risks to the reliable operation” of the power grid. 

The focus of the webinar was NERC’s reliability standard, CIP-008-6 (Cybersecurity — incident reporting and response planning), which outlines the requirements for utilities to implement in their cybersecurity incident response plans (CSIRP). Georgoulis reminded listeners the standard is meant to ensure “quick and decisive action is taken in the event of a cybersecurity incident” and that having a comprehensive response plan can help entities “mitigate any risks that may arise” from a security compromise. 

Georgoulis said a CSIRP must spell out the process by which entities will identify attempts to compromise their systems, classify what kind of threat is occurring, and respond to incidents appropriately. He noted a potential roadblock to compliance with CIP-008-6 in the fact that NERC did not define “attempts to compromise” in the standard. This means entities must create their own criteria to determine if such attempts have occurred. 

To satisfy this requirement, Georgoulis suggested sample criteria, such as “suspicious or excessive failed login attempts [or] reports of an unsuccessful social engineering attempt.” Attendees also provided examples of criteria their entities use, including security event logs and unexplained spikes in CPU activity. 

Once an entity has concluded an incident is underway, it must determine whether the incident needs to be reported to the Electricity Information Sharing and Analysis Center and the Cybersecurity and Infrastructure Security Agency. In this case, Georgoulis noted NERC does specify the incidents that must be reported are those that compromise or disrupt:  

    • a cyber system that performs one or more reliability tasks of a functional entity; 
    • an electronic security perimeter of a high- or medium-impact grid cyber system; or 
    • an electronic access control or monitoring system of a high-impact grid cyber system. 

Another key requirement of the standard, Georgoulis noted, is to clearly define the roles and responsibilities of the cybersecurity incident response team. He explained that “having an established cybersecurity incident response team with the corresponding roles and titles listed in the plan can minimize any kind of confusion on who needs to do that during a scheduled test or in the event of an actual cybersecurity incident.”  

Finally, Georgoulis reminded entities that simply having a response plan is not enough to satisfy the standard. Entities must test the plan “at least once every 15 calendar months” either through a tabletop or operational exercise based on an actual reportable cybersecurity incident.  

In response to a question from the audience, Georgoulis confirmed that GridEx, the biennial security exercise hosted by NERC and the E-ISAC, might count as an “operational exercise” to satisfy the requirements of the standard, depending on the details of the scenario. He clarified that the GridEx scenario would have to be based on an actual incident and would have to include an applicable system.

Posted on

Interim CEO Fowke Explains AEP Leadership Change

American Electric Power’s leadership on Feb. 27 added further color to its board’s decision the day before to remove Julie Sloat as CEO and replace her with former Xcel Energy CEO Ben Fowke on an interim basis. 

In his scripted remarks to financial analysts during the company’s quarterly conference call, Fowke said the decision was not an easy one, but “in the best interest of AEP and its stakeholders to do so.” 

Julie Sloat | © RTO Insider LLC

Fowke and other AEP executives appeared to indicate they were unhappy with several regulatory outcomes. They pointed to the disallowance of recovering some deferred fuel costs in West Virginia and the probable disallowance of certain capitalized costs associated with a Louisiana power plant as a hit to earnings. 

One analyst pressed Fowke over the earnings presentation’s “leaning” on AEP’s successes and growth rate capital expenditure numbers ($43 billion over five years). “What do you see is broken?” the analyst asked. 

“I don’t think I would use the word ‘broken.’ I think there’s areas where we can do better,” Fowke said. “We also recognize that we can do better on getting constructive regulatory outcomes. So strategically, our priorities remain the same. We’re going to look at the people, the process and the planning that goes into that those constructive outcomes, and we’re going to do it through the lens of what’s important to our local leaders and stakeholders … and then you get into that virtuous circle where invested capital now is good for customers in the community.” 

Fowke said more than once that the leadership decision was made by the full board. “You need the full board to make a decision to remove the CEO,” he said. 

AEP recently increased the board’s size by adding two directors after entering into an agreement with activist investor Icahn Capital. The board also invited Icahn to place a portfolio manager as a nonvoting observer during its meetings.  

“The additional board members came after discussions with the Icahn team and AEP team,” Fowke said. “We actually welcome their perspective. They share the opinion, as we do, that AEP shares are undervalued, and we want to work together to unleash shareholder value.” 

In the Feb. 26 press release announcing the leadership change, AEP said the board had determined after discussions with Sloat that it was “time to identify a new CEO to lead the company’s next chapter.” The company said the decision was not a result of any disagreement with Sloat over AEP’s operations, policies or financial performance and “was not made for cause or related to any ethical or compliance concern.” 

AEP will conduct an external search for its next CEO. Fowke said AEP will be an “attractive destination” and that he expects the candidate list to be a long one. 

“I think it’s going to be great to pick from that talent. Ideally, you get somebody that is a seasoned executive in the utility industry and is well known in the investor community,” he said, adding that it would be ideal if the next CEO has multijurisdictional experience. 

Fowke retired from Xcel in August 2021 after more than a decade as its CEO. He joined the AEP board in February 2022. 

Sloat, a 23-year AEP veteran, replaced Nick Akins as CEO in January 2023.  

The company reported year-end earnings of $2.21 billion ($4.26/share), a drop from 2022’s performance of $2.31 billion ($4.51/share). Fourth-quarter earnings were also down, at $336.2 million ($0.64/share), a drop from the same quarter the year prior of $384.3 million ($0.75/share). 

After saying in its earnings announcement that it made “positive progress” toward the $9.4 billion in regulated renewables in its five-year capital forecast, AEP issued another release about the sale of its 50% interest in New Mexico Renewable Development’s solar assets. The transaction will net the company about $104 million in cash after tax, transaction fees and other adjustments. 

The company’s share price closed at $80.77 on Feb. 26 but shot up to $83.39 in after-hours trading following the CEO change’s announcement. 

It closed at $84.07 on Feb. 27, a 4.1% gain on the day.