Search
February 4, 2025

Posted on

ERCOT Technical Advisory Committee Briefs: Jan. 22, 2025

Stakeholders Sound off on Market Design Framework 

ERCOT’s Technical Advisory Committee held its first meeting of 2025 on Jan. 22, with the biggest chunk of the meeting devoted to discussing the grid operator’s proposed market design framework. 

The framework dates back to August 2024, when ERCOT CEO Pablo Vegas presented it to the Board of Directors. It is made up of very broad guidelines to use as the grid operator develops rules and regulations, said Vice President of Commercial Operations Keith Collins. 

“What we see is that while reliability is the organization’s primary objective, cost should always be considered,” Collins said. “So, I think that hopefully will set us up for some of the discussion debate that will happen about what the meaning of this balance is.” 

ERCOT already had gotten comments from six sets of stakeholders on the document, and Collins invited them to reiterate what they wrote at the TAC meeting. 

“Our comments are meant to be very generally supportive of the framework and the intent behind the framework, because it can be helpful to have this sort of tool to help socialize and coordinate thinking about market design changes,” said Ned Bonskowski of Vistra. 

However, Vistra wanted to make sure the policy framework is not resetting all of the work the Texas legislature and Public Utility Commission have put into the markets since the February 2021 winter storm, or even further back, he added. 

The PUC shelved the performance credit mechanism in December, and ERCOT is working on implementing the real-time co-optimization (RTC) of energy and ancillary services, which means stakeholders have to look for some new policies to improve the system. 

“We want to choose among the best tools that we have available to us and use those tools efficiently,” Bonskowski said. “But we also don’t want to, for instance, give up on trying to just because we may not have the exact perfect tool that we would like to have for a situation. We should not let the perfect be the enemy of the good.” 

The Lower Colorado River Authority’s Blake Holt saw the document as providing some clarity to those who are not in the “stakeholder trenches” regularly, but he had questions on how the document would influence policy implementation at ERCOT. 

“How does ERCOT intend to resolve conflicts between competing attributes and timelines?” Holt said. “For example, [the reliability unit commitment] enhances reliability for the hours utilized. However, excessive use of the tool can lead to wear and tear on a unit and worsen reliability in the future, not to mention the out-of-market action leads to flawed and inefficient price formation.” 

One basic issue the document brought up for many is the tension between affordability and reliability, which is a universal concern in the power industry. 

“We recognize there are tradeoffs between the two, and we currently support the stance of conservative operations and understand that operating more reliability or more reliably comes with increased cost,” Holt said. “We believe the best way to support this increased cost is through markets in which these operational reserves are currently valued and reflected in as procurement.” 

Collins agreed the framework could be useful for people who are not always in stakeholder meetings to use as a way to help wade through the information that is produced at them. 

The city of Eastland’s Mark Dreyfus questioned the purpose of the document, noting that the stakeholder process implements the nitty gritty details of policy. While they are complicated, many people are involved, and ERCOT’s board has the grid operator’s entire staff to explain things to them. 

“Consumers, as a market segment, have always supported competitive markets, because we know that the competitive market — as reflected in the law, interpreted through the commission rules and into the protocols — is the best way to provide reliability at lowest cost to consumers,” Dreyfus said. 

The Texas Advanced Energy Business Alliance’s Doug Pietrucha said his group agrees that markets are the best way to ensure the right balance between reliability and affordability, but it wants to make sure that technology neutrality is a key part of market design. 

“The participation in various services should be based on the attributes that different technologies can provide, and the goal of the service shouldn’t be to be designed around the attributes of any one particular technology,” Pietrucha said. 

Mark Bruce, principal at Cratylus Advisors, questioned the value of the document, noting that policy is determined elsewhere. 

“ERCOT doesn’t get to make high-level, aspirational policy determinations and documents like this,” Bruce said. “All this talk about competitiveness, that issue has been settled since Sept. 1, 1999,” referring to the law that restructured Texas’ utility industry. 

Collins disagreed with that assessment, noting that he has worked around the country in other markets where they do not necessarily wait for FERC for directions. 

“You can blaze a path that that can help the commission determine … a reasonable approach to implementing reliability,” Collins said. “It’s one thing to say you want a reliable market. Well, how do you want a reliable market? How do you want competitive markets? And what we’re seeing here are things that help emphasize how you can achieve that.” 

Large Load Interconnection Report

In other business, TAC got an update on the number of large loads lined up to connect to the ERCOT grid. 

A combination of new standalone projects and those co-located with generation, net of a few cancellations, has ramped up the queue by 17,481 MW since TAC’s last meeting in November. With some rule changes anticipated, interconnect requests for loads energizing more than two years in the future have gone up significantly in the past two months, according to an ERCOT report. 

ERCOT has added 5,229 MW of large loads from 2022 through 2024, and that could grow to more than 80,500 MW by 2030, the report says. Projects representing more than 14,000 MW are interested in connecting to the grid this year, though most of that — and most of the 80 GW for 2030 — is under ERCOT review or has yet to submit enough information for the grid operator to even start a review. 

Votes on Leadership, Transmission, Rule Changes

The meeting opened up with TAC members voting to give Caitlin Smith of Jupiter Power another year as its chair. 

The committee elected a new vice chair, with Martha Henson of Oncor taking that role over after Collin Martin, also of Oncor, stepped down at its last meeting. (See ERCOT Technical Advisory Committee Briefs: Nov. 20, 2024.) 

TAC voted to recommend three transmission projects from Oncor that are big enough to require approval from the board: 

    • The Forney 345/138-kV Switch Rebuild Project, which costs $103.5 million, to address reliability issues in Kaufman County and will not require a certificate of convenience and necessity (CCN).
    • The Wilmer 345/138-kV Switch Project, which costs $158.2 million, to address reliability issues in Dallas, Kaufman and Ellis counties, which will require a CCN.
    • The Venus Switch to Sam Switch 345-kV Line Project, which costs $118.9 million, to address reliability issues in Ellis and Hill counties and will not require a CCN. 

In addition to the three transmission projects, TAC also voted on many rule changes, but the only one that generated debate was NPRR 1250, which is needed for ERCOT to end its renewable portfolio standard implementation practices. Others were put on a combination ballot and were approved unanimously. 

The legislature passed HB 1500 to end the RPS, which effectively has been moot for more than a decade, as the Texas grid has long had more renewables than was ever required by the standard. ERCOT still will run a voluntary renewable energy credit (REC) trading program but will end the mandatory REC program for RPS compliance. 

Vistra’s Bonskowski abstained from voting for NPRR 1250 because it did not eliminate several compliance provisions, but he noted they’re going to be dealt with in a future rule change. 

Posted on

ISO-NE Details Evaluation Models for Transmission Solicitation

ISO-NE has outlined the transmission and economic models it plans to use to evaluate proposals submitted for the longer-term transmission planning (LTTP) process.

The RTO is developing the first request for proposals for the LTTP process, which is intended to address transmission needs identified in long-term planning studies. FERC approved the new process in July. (See FERC Approves New Pathway for New England Transmission Projects.)

At the direction of the New England States Committee on Electricity (NESCOE), the first LTTP solicitation focuses on increasing the transfer capability at two interfaces in Maine and facilitating the interconnection of at least 1,200 MW of onshore wind in the state. (See ISO-NE to Work on State-backed RFP for Northern Maine Transmission.)

To help qualified transmission project sponsors (QTPS) develop their proposals, ISO-NE will publish transmission and economic models, said Dan Schwarting, manager of transmission planning at ISO-NE. The models will use the same basic structure as those used by ISO-NE to evaluate projects but will use generic information for generator performance to protect confidentiality.

The economic models outlined at the Planning Advisory Committee meeting Jan. 23 will include a capacity expansion model and a production cost model. The capacity expansion model will determine “the amounts and types of generation needed to adequately serve load over multiple years, given emissions constraints and load growth,” Schwarting said. The production cost model will calculate hourly data on generation dispatch, power flow and production cost.

ISO-NE plans to use its version of the models to calculate benefit-to-cost ratios (BCRs) for proposals. These financial benefit calculations will account for production cost and congestion savings, avoided capital costs, avoided transmission investment, reductions of line losses and reductions of unserved energy.

For a project to be selected in the LTTP, the BCR calculation must show that its benefits outweigh its costs. If multiple projects pass this threshold, ISO-NE is not required to select the proposal with the highest BCR and also will consider factors including project scope, permitting challenges and “constructability,” Schwarting said.

If no projects pass the threshold, FERC has approved a “supplemental process” in which one or more states could opt to cover the costs that exceed the threshold.

In February, ISO-NE plans to provide additional modeling details to the PAC, including an outline of its modeling of “representative onshore wind projects in northern Maine,” and the composite load model the RTO will use for stability simulations.

Schwarting said ISO-NE plans to release a draft RFP to NESCOE and the QTPS to solicit feedback prior to publishing the official RFP in March. He said this limited review process would “strike a balance between feedback and timeliness in issuing the RFP.”

Several people asked ISO-NE to expand the opportunity to provide feedback to all stakeholders. Sheila Keane, director of analysis at NESCOE, also expressed an interest in expanding the draft RFP review process.

“As we think about this being the first time through for everyone … it seems like adding in some transparency on the draft RFP might add some value to the process without adding too much time,” Keane said.

After issuing the RFP, ISO-NE plans to give transmission developers six months to submit proposals, followed by a yearlong period for ISO-NE to evaluate and select a proposal. Under this timeline, ISO-NE would likely select a solution by September 2026.

“If it is possible to accelerate this timeline we certainly will,” Schwarting said.

2024 Economic Study

Also at the PAC meeting, ISO-NE presented the final policy scenario results of its 2024 Economic Study, which is intended to evaluate “economic and environmental impacts of New England regional policies, federal policies and various resource technologies on satisfying future resource needs in the region.”

The preliminary results of the policy scenario, presented in November, found the need to add 58 GW of capacity from a range of zero carbon resources including renewables, energy storage and small modular reactors (SMRs).

The study found that carbon constraints will drive capacity expansion from 2033 to 2039, after which both carbon constraints and load growth will drive resource additions.

Overall, the final results indicate New England will need to add a cumulative capacity of 77,176 MW by 2050. Compared to the preliminary results, the increased need for new capacity reflects a reduced SMR buildout, which increases the amount of capacity required from other resources.

As the region decarbonizes, SMRs could help fill an essential firm power role and limit the need to overbuild intermittent renewables. ISO-NE has deemed hydrogen generation, carbon capture and storage, and geothermal generation — other potential low-carbon dispatchable resources — to be infeasible solutions for the region due to geological constraints.

The model found that, in 2050, “without additional revenue incentives, SMRs only operate at a 21% capacity factor, but they successfully provide emission free dispatchable generation in the winter to reduce overall system emissions,” said Elinor Ross of ISO-NE.

The results also indicate that the cost of additional carbon reductions will increase exponentially as the power system nears full decarbonization in the leadup to 2050.

“Hours of high solar and wind generation are easy to decarbonize at a low cost,” said Ross. “The remaining hours left to be decarbonized require energy storage and SMRs, which are more expensive than wind and solar.”

Sensitivity analyses also highlighted the significant cost benefits of land-based wind, which was “consistently the most cost effective resource in a levelized cost analysis,” Ross said.

Reducing the limitations on onshore wind decreased the overall build costs in the model. In the most extreme sensitivity considered by ISO-NE — which allowed the model to build unlimited land-based wind — the model added more than 44 GW of onshore wind, cutting the overall build costs nearly in half relative to the reference case.

ISO-NE is taking feedback on the policy scenario results and requests for additional sensitivity scenarios through the end of February.

Posted on

Trump Says Data Center Power Plants Will be Expedited

President Donald Trump presented the World Economic Forum with his desire to power the U.S. AI revolution: behind-the-meter generation co-located with data centers and built rapidly under his National Energy Emergency executive order. 

This scenario could avoid the yearslong delays of siting and permitting, he said, and would bypass the transmission grid, which he said is aging and vulnerable to attack. 

Trump spoke virtually Jan. 23 to the annual gathering of global leaders and decision-makers in Davos, Switzerland. 

In response to a question from TotalEnergies CEO Patrick Pouyanne about U.S. LNG exports, Trump segued from fast-tracking LNG facilities to fast-tracking new power generation. 

“I’m going to get them the approval,” he said. “Under emergency declaration, I can get the approvals done myself without having to go through years of waiting. And the big problem is we need double the energy we currently have in the United States — can you imagine? — for AI to really be as big as we want to have it.” 

Powering major consumers through on-site generation rather than through the grid is a very old concept, but Trump claimed the idea of doing it with a data center is new. 

Trump, a vociferous critic of renewable energy, said new plants could run on whatever fuel the developers like, but he suggested “good clean coal,” if only as a backup fuel. 

Trump’s comments come as the U.S. power sector scrambles to meet what is expected to be a huge increase in power demand from reindustrialization, data center expansion and societal electrification. 

Some experts are skeptical the demand will increase as much as the largest projections indicate, but some increase appears inevitable: artificial intelligence is a heavy power draw, and Trump is pushing to make the U.S. a leader in AI. 

The newest projection of AI data center power needs was offered the same day as Trump spoke, when Goldman Sachs Research estimated the facilities’ power consumption would increase more than 160% from 2023 levels by 2030. 

There has been keen interest in powering data centers with nuclear power, thanks to its near-constant output and near-zero emissions. 

But Goldman Sachs Research concludes it would be impossible to meet the near-term needs entirely with nuclear. To do so would require 85 to 90 GW of new capacity by 2030, and only a small fraction of that amount is expected to be online by then. 

Relying instead on fossil generation would ratchet up greenhouse gas emissions, the report’s authors write. 

Instead, they suggest a mix of fossil, renewable, storage and nuclear power in the short term. 

“Our conversations with renewable developers indicate that wind and solar could serve roughly 80% of a data center’s power demand if paired with storage, but some sort of baseload generation is needed to meet the 24/7 demand,” said Jim Schneider, a digital infrastructure analyst at Goldman Sachs Research. 

The authors also note that future innovations could help reduce Big Data’s power needs — from 2015 to 2019, data center workload nearly tripled but electricity consumption was flat, due to increased energy efficiency.  

They conclude: “Since 2020, efficiency gains have decelerated, but the team expects more innovations to help lower the power intensity of data centers in future.” 

Posted on

Trump Energy, Interior Cabinet Picks Easily Pass Committee Votes

The Senate Energy and Natural Resources Committee on Jan. 23 sent the nominations of Douglas Burgum to be interior secretary and Chris Wright to be energy secretary to the floor in bipartisan votes. 

“At their nomination hearings last week, the nominees proved that they’re committed to implementing President Trump’s plan to unleash American energy by ending the policies of climate alarmism and extremism, prepared to streamline permitting and rescind regulations that impose needless burdens on energy production and consequently the American people,” ENR Chair Mike Lee (R-Utah) said at the committee’s meeting. 

Burgum cleared the committee by an 18-to-2 vote, while Wright secured a 15-to-5 vote as more Democrats voted against him. (See Trump DOE Nominee Seeks to Assuage Senate Democrats.) 

The committee votes yesterday come just a week after Burgum testified before the committee, and eight days after Wright did. (See Burgum Criticizes ‘FERC Queues’ for Too Many Renewables.) 

Lee said he hoped the two nominations would move quickly to a vote by the full Senate, and leadership has been pushing through Trump’s cabinet nominees, having already secured a unanimous confirmation vote for Secretary of State Marco Rubio on Jan. 20. 

Sen. Ron Wyden (D-Ore.), the ranking member on the Senate Finance Committee, explained he opposed both nominees because of Trump’s opposition to clean energy tax credits that both the Finance and ENR committees had worked. 

“Rolling back this law is unilaterally disarming America in the face of China,” Wyden said. “Because President Trump states he wants to beat the Chinese while seeming to prefer policies that undermine America’s greatest advantages, I cannot support nominees that will carry out these policies.” 

Sen. Maria Cantwell (D-Wash.) said she opposed Wright for more local concerns — cleaning up the old plutonium producing site in Hanford, Wash. Wright said cleaning up the site was a top priority, but Cantwell said his commitment to the Tri-Party Agreement that has governed the cleanup for decades was “unsatisfactory.” 

“We get roughly about $2 billion a year in the national budget to clean up Hanford, and we have every energy secretary really pushed by [the White House Office of Management and Budget] to basically try to do cleanup on the short,” Cantwell said. “So, I hope maybe between now and the floor, I might get a stronger commitment on the Tri-Party Agreement.” 

Posted on

NYISO Begins Capacity Market Structure Review

NYISO on Jan. 22 laid out the timeline for its Capacity Market Structure Review project, which will take up the better part of 2025. 

Speaking to the Installed Capacity Working Group, Brendan Long, market design specialist for NYISO, said the objectives of the review include identifying current market structures “that will help facilitate New York’s evolving grid consistent with policy goals” and exploring potential alternatives. The ISO will solicit feedback from the group throughout the year with the goal of producing a final report in the fourth quarter. 

Just like the rest of the U.S., demand for electricity is growing exponentially in New York. The review was called for by stakeholders and the ISO last year to determine whether the capacity market provides adequate resources efficiently and effectively. 

According to its schedule, NYISO will propose a priority list of key areas of the market for potential enhancement by the end of the first quarter, propose an initial set of “high-level solutions” in the second quarter and “further analyze and refine” the recommendations in the third. 

In response to stakeholder questions, Long said that considering reactive power compensation was on the table and that the review would include evaluating how the market ensures transmission security. The ISO also will consider long-duration energy storage compensation structures. 

“It’s absolutely something we’ll consider, and we’ll whittle down further as the project progresses,” Long said.  

One stakeholder pointed out the project came about because market participants were frustrated with the capacity market; they asked whether identifying the sources of frustration was a priority for the review. Long said NYISO is “definitely going to keep our ears open” for stakeholder feedback and it will play a major role in the direction of the study. 

“I think that it’s important that part of this project is an articulation of why the current structure is not working,” Chris Casey, of the Natural Resources Defense Council, said in agreement with the previous stakeholder. “I think it’s important to zoom in on that to know how to fix it. It’s more than just collecting the frustrations of the stakeholders. We need to identify and articulate the reasons why this market might not be producing efficient results anymore.” 

NYISO’s structures needed to be harmonized with the state’s programs, he said. “I don’t think we should come out of this with a structure that pretends that certain revenue sources don’t exist or is otherwise blind to state programs because I think that ultimately produces results that are inefficient and costing customers more than they need to pay.” 

Doreen Saia, chair of the Energy and Natural Resources Practice at Greenberg Traurig, echoed Casey’s point, saying any capacity market changes needed to take state policy into consideration. 

Saia also asked the ISO to keep in mind the market structure has been in place for more than a quarter-century and stakeholders would require “adequate meeting time” to discuss potential changes. This comment came after a November and December in which stakeholders had grown frustrated with ISO projects they saw as rushed or incomplete. (See Large Consumers Vent Frustrations with NYISO’s Proposed SCR Changes and Winter of NYISO Stakeholders’ Discontent over ‘Complete’ Projects.) 

Several stakeholders, including Casey, urged the ISO to avoid incrementalism and seriously consider the fundamental structure of the market. They said changes, like new types of resources, might be coming in 10 to 20 years and any new market structures had to be flexible enough to accommodate them. 

“Fundamental changes to the structure, at least looking into them, are in the scope of this project,” Long said. “It might not necessarily be prioritized in our list of key areas, but I wanted to clarify that it will definitely be something we’re open to hearing feedback.” 

Posted on

6th Circuit Rules Against Michigan Local Clearing Requirement

A federal appeals court has brought Michigan’s practice of requiring some amount of locally generated electricity to a standstill, finding that the Michigan Public Service Commission violated the Commerce Clause when designing local clearing requirements.

The 6th U.S. Circuit Court of Appeals decided in a Jan. 16 order that Michigan’s local clearing requirement — which requires load-serving entities and alternative energy suppliers alike in the lower peninsula to procure an increasing percentage of their total capacity from within MISO’s Zone 7 — is discriminatory and “impermissibly interferes with interstate commerce” (23-1280). The appeals court reversed and remanded a district court’s earlier finding that the requirement does not discriminate against interstate commerce.

MISO’s Zone 7 encompasses the lower peninsula, while the upper peninsula and a portion of Wisconsin are in Zone 2. Michigan relies on MISO’s local clearing requirements to establish its own but adds the condition that some capacity comes from in-zone sources.

Energy Michigan, composed of a group of the state’s alternative energy suppliers and the Association of Businesses Advocating Tariff Equity (ABATE), an association of industrial and manufacturing entities that use the alternative suppliers, originally sued the Michigan Public Service Commission for its 2017 order establishing the local clearing requirements (U-18197).

“Can the state of Michigan require someone selling a product in Michigan to procure that product from the state? Or, phrased in the language of the coin’s other side, can Michigan bar in-state retailers from obtaining their merchandise from outside the state? On these issues, negative Commerce Clause jurisprudence is straightforward. Whether the product at issue is milk, or coal-based electricity, the Commerce Clause prohibits such state restrictions unless they clear strict scrutiny’s high bar,” the court said, drawing on past cases.

The court said the Michigan PSC couldn’t make a law that “overtly blocks the flow of interstate commerce at a state’s borders.”

The Michigan PSC argued that it didn’t discriminate because the order’s language doesn’t mention state boundaries, only MISO’s local resource zones. The court called that “not much of a step” because Zone 7 geographically corresponds with Michigan’s lower peninsula.

Michigan regulators also argued that the clearing requirement’s purpose is to promote resource adequacy, not to protect domestic industry. Energy Michigan and ABATE took a different view of the law, arguing that it’s meant to favor utilities in the marketplace and drive out alternative energy suppliers, which are more likely to sell out-of-state electricity. Michigan allows up to 10% of retail electricity sales to be purchased from alternative electric suppliers.

However, the court said the aim of the requirement is irrelevant.

“Even the most benign purpose … cannot save a facially discriminatory law from strict scrutiny,” it said. The court added it judged the percentage requirement the same way it would a requirement dictating 100% of peak demand be procured from Michigan “or even an entire ban on electricity supply derived outside the state’s borders.”

Finally, the Michigan PSC argued that the Federal Power Act authorized it to enact the local requirement, pointing to a section that removes facilities used for electricity generation from federal jurisdiction. The court responded that “it is difficult to see how this provision authorizes, let alone unambiguously so,” Michigan to discriminate against interstate commerce.

Circuit Judge Danny Boggs dissented from the ruling, saying the case deserves some nuance and is “clearly” beyond the scope of the Commerce Clause because of the players involved. He said the district court erred in its conclusion that public utilities and alternative electric suppliers are similarly situated entities simply because they offer the same commodity.

Boggs argued that unlike the state’s utilities, unregulated alternative electric suppliers typically contract with industrial manufacturers and mid-size commercial customers and aren’t under an obligation to serve.

“At bottom, eliminating the local clearing requirement would do nothing to further the Commerce Clause’s ‘fundamental objective of preserving a national market for competition,’ and it would undermine the reliability of the state’s grid. The majority of Michigan’s retail electricity market remains in the hands of the public utilities, who have an unshakable obligation to serve that vital market,” Boggs wrote.

Boggs said MISO’s local resource zones are not only based on state boundaries but also drawn according to results of MISO’s loss of load expectation studies, “the relative strength of transmission interconnections,” the electrical boundaries of local balancing authorities and the seams between RTOs.

“Declining to give full weight to the judgment of state and local regulators on a matter of state and local concern is a fraught exercise, particularly considering the intricate area of energy regulation at play here,” Boggs wrote. “Geographic proximity to generation improves grid reliability, and without the requirement to secure in-state capacity, Michigan would be at risk of falling short of federal reliability standards.”

Posted on

Study Models West Coast OSW Transmission Options

A new report by two national laboratories finds that offshore wind could be generating as much as 33 GW of electricity for the western United States by 2050 and looks at how best to bring that power ashore. 

The “West Coast Offshore Wind Transmission Study” also points out the region will need as much as 400 GW of new capacity by 2050, and that the floating infrastructure needed for the deep water off the West Coast presents engineering challenges. 

Another, more immediate problem is not mentioned in the report: politics. The report was published Jan. 15, just five days before President Trump slapped an executive order of indefinite duration and as-yet indeterminate impact on offshore wind development in U.S. waters. (See Critics Slam Trump’s Freeze on New OSW Leases.) 

Teams of researchers at the Pacific Northwest National Laboratory and National Renewable Energy Laboratory spent two years preparing the study. 

They focused on a 9,265-square-mile region off northern California and southern Oregon where the wind is strongest (22 mph average), the water depth is tenable (4,265 feet maximum) and there is minimal overlap with protected zones, tribal communities and other potential conflicts. 

They studied two transmission models: 

A radial structure, where each wind farm is connected to one point on the coast, would be simpler to build but less versatile in operation, they found. 

A backbone structure, in which wind farms are connected to each other at sea as well as to points of interconnection on land, would carry a higher upfront cost but would allow cheaper energy to be moved more efficiently across regions. 

The researchers found that starting with a radial structure and expanding it into a backbone structure would present the best cost-benefit mix and result in savings that could equal $25 billion in 2024 dollars — mostly because it would allow grid regions to better share lower-cost energy such as hydropower and solar power. 

Lead author Travis Douville, PNNL’s wind systems integration portfolio manager, said such an addition of offshore wind power also would boost resilience in the coastal region, as there are not many generators along the coast. 

“With careful planning and coordination across multiple points in time, we can solve the question of how offshore wind generation and transmission could be developed on the West Coast for maximum benefit,” he said. 

Posted on

Chelan PUD Commits to SPP Markets+ Phase 2 Funding

SPP’s Markets+ notched another in a string of successes Jan. 22 when the Chelan County Public Utility District in Washington said it will pay its $1 million to $2 million share of funding for the market’s Phase 2 implementation stage.

The announcement by the Wenatchee-based publicly owned utility (POU) came just a day after the biggest Markets+ funder, Powerex, committed to joining the market and providing its funding share, estimated to be about $34.8 million. (See Powerex Commits to Funding, Joining SPP’s Markets+.)

Powerex’s move followed FERC’s Jan. 16 approval of the Markets+ tariff, which opens the door for other such moves by backers of the market. (See SPP Markets+ Tariff Wins FERC Approval.)

Chelan spokesperson Rachel Hansen said the PUD’s announcement covered only funding for Phase 2 and did not constitute a commitment to participating in the market.

“Joining the market will be a separate decision,” Hansen told RTO Insider in an email.

In a statement accompanying the announcement, Chelan General Manager Kirk Hudson echoed a point the Bonneville Power Administration has made in defending its intention to contribute its own $25 million share of Markets+ funding before a participation commitment: that the investment is necessary to ensure that Western utilities have a viable alternative to CAISO’s Extended Day-Ahead Market (EDAM).

“It’s in our customer-owners’ interest to ensure that a day-ahead and real-time market option exists that features independent governance, encourages investment in resource adequacy and appropriately values hydropower,” Hudson said.

And like BPA, Hudson referred to the fact that Northwest utilities inevitably will face a need to participate in an organized day-ahead market.

“The success of wholesale power markets is critical to keeping rates low for Chelan PUD’s customer-owners. All around us, we see changes to the region’s electric system that will affect how utilities buy and sell power, including a shift to organized electricity markets,” he said.

Chelan is not a participant in CAISO’s real-time Western Energy Imbalance Market.

According to a spreadsheet posted on SPP’s website Oct. 24, 2024, Chelan would be responsible for funding 0.7% of the estimated $150 million cost for Phase 2, based on the most likely Markets+ footprint scenario. SPP has told RTO Insider that it’s using a funding mechanism similar to that of Phase 1 to calculate each participant’s share of the Phase 2 implementation costs.

As competition between Markets+ and EDAM has ramped up over the past year and a half, Chelan has been solidly aligned with the majority of BPA’s base of POU “preference” customers who have urged the agency to join Markets+ and asked federal officials to respect its independence in making a day-ahead market decision. (See Public Utilities Urge DOE to Respect BPA’s Day-ahead Decision Process.)

And along with Powerex and a handful of other utilities in the Northwest and Southwest, Chelan has been a consistent contributor to the series of “issue alerts” published by Markets+ backers that have favorably compared features of the SPP market with those of the EDAM.

Despite its status as a BPA preference customer, Chelan manages its own balancing authority area in Central Washington, operates 300 miles of transmission and controls a combined nameplate capacity of 2,037 MW from the Rocky Reach, Rock Island and Lake Chelan hydroelectric dams.

The utility serves about 49,000 customers in a territory covering nearly 3,000 square miles.

Posted on

Cold Weather Standard Set for Posting

NERC’s Standards Committee is on track to post a revised cold weather standard for formal comment slightly ahead of schedule Jan. 27, the ERO’s director of standards development, Jamie Calderon, said during the group’s monthly conference call. 

The Board of Trustees directed the committee to develop a revision to EOP-012-2 (Extreme cold weather preparedness and operations) at a special meeting Jan. 10, invoking Section 321 of NERC’s Rules of Procedure to bypass the ERO’s normal stakeholder approval process for the second time. The revised standard must be submitted to FERC by March 27, according to a deadline set by the commission last year. (See NERC Board Invokes Section 321 Authority for Cold Weather Standard.) 

Committee Chair Todd Bennett, of Associated Electric Cooperative Inc., told attendees that a small group of volunteers from the SC, industry and NERC staff has been working on the new standard since the board’s decision. Under the rules invoked by the board, the SC itself must work with stakeholders and NERC staff to prepare a standard that satisfies FERC’s order and post it for a 45-day public comment period no later than Jan. 29. 

Calderon said the drafting team is finished with its revisions; at this point, the standard is undergoing a final legal and administrative review. She emphasized that NERC is “committed to reviewing all comments” received during the comment period, which will end around March 13. After the comments have been reviewed, the board plans to hold a special call to review the standard and any comments that the team considers relevant before FERC’s deadline. 

In response to a question from Sean Bodkin of Dominion Energy, Calderon confirmed NERC will not hold another formal ballot for the standard. The ERO already has held two formal ballot rounds for EOP-012-3, but each time the standard failed to receive more than a 45% segment-weighted favorable vote — far below the two-thirds majority needed for approval. 

Trustee Sue Kelly, the board’s liaison to the SC, praised the team for taking their time to work on the standard. 

“I was reminded of Shakespeare’s [quote] … ‘We few, we happy few, we band of brothers’ — and sisters — who spent all the time working on this together,” Kelly said. “And we on the board just wanted to say thank you very much for all your efforts.” 

GO/GOP Definitions Project Approved

The only standards action taken by the committee on the conference call, other than the update on the cold weather standard, was to approve a proposal to authorize drafting new definitions for generator owners and operators. 

The proposal was in a standard authorization request (SAR) submitted by the team for Project 2024-01 (Rules of Procedure Definitions Alignment — Generator owner and generator operator). NERC Manager of Standards Development Alison Oswald explained the projected is intended “to align the NERC Glossary of Terms’ definitions for [GO] and [GOP] with those that are contained in the Rules of Procedure registry criteria.”  

Oswald explained the SAR already has been posted for a 45-day formal comment period and received “supportive” comments from industry stakeholders. SC members unanimously approved the SAR, which now will be assigned to the Project 2024-01 team. 

Posted on

FERC Approves CAISO’s SWIP-North Development Agreement

FERC on Jan. 21 approved an agreement between CAISO and LS Power to develop a transmission line that would deliver Idaho wind power into California and could help secure Idaho Power’s participation in the ISO’s Extended Day-Ahead-Market.

The commission’s order covers the Southwest Intertie Project-North (SWIP-North), a 285-mile, 500-kV line being developed by LS Power subsidiary Great Basin Transmission at an estimated cost of $1 billion (ER25-543).

The project, which will be jointly funded by CAISO and Idaho Power, will span northern Nevada and southern Idaho and link up with NV Energy’s One Nevada (ON) line to the south, providing 2,070 MW of transfer capacity southbound and 1,920 MW northbound.

The development agreement memorializes CAISO’s previous agreement to fund about 77% of the project, equal to Great Basin’s ownership share, in exchange for operational control of the company’s entitlements on the line, which will equate to 1,117.5 MW of southbound capacity and 1,072.5 MW of northbound capacity, with the balance in both directions being allocated to NV Energy.

In addition to facilitating transfers into California, the line offers Idaho wind power resources access to wholesale electricity markets in the Desert Southwest through the Desert Link line connected to the southern end of the ON line.

CAISO’s Board of Governors approved the development agreement during an October 2024 meeting despite opposition from some Idaho residents concerned about the path of the line. (See CAISO Board Approves Moving Forward with SWIP-N Transmission Line.)

In its filing with FERC, CAISO said it needed to pursue SWIP-North to support the California Public Utilities Commission’s resource planning portfolio calling for California load-serving entities to procure 1,000 MW of wind generation from Idaho. The ISO noted the proposed line is the only active project that would help fulfill that objective, making it the most timely and cost effective option. The project is expected to commence operation in 2028.

CAISO also said SWIP-North would provide additional economic benefits, such as improving California’s resource diversity and increasing the ability to reduce congestion costs on the parallel California-Oregon Intertie. The line also will assist California in reducing renewable energy curtailments and exporting its solar surpluses.

CAISO’s pursuit of the line likely has played a key role in Idaho Power’s leaning in favor of joining CAISO’s Extended Day-Ahead Market (EDAM) rather than SPP’s Markets+. (See CAISO’s EDAM Scores Key Wins in Contested Northwest.)

And last year, Ryan Atkins, NV Energy’s vice president of resource optimization and resource planning, pointed to SWIP-North and the EDAM’s growing transmission footprint when explaining the utility’s reason for choosing the CAISO market in comments to the Public Utility Commission of Nevada. (See Market Footprint Critical for EDAM Decision, NV Energy Says.)