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June 16, 2024

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Rosner, See Clear Senate to Fill out FERC

The U.S. Senate on June 12 confirmed two of President Joe Biden’s three nominees, David Rosner and Lindsay See, to FERC and is poised to take a final vote on Judy Chang on June 13. 

The votes mean FERC will be back to its full complement of five commissioners when the nominees take office, avoiding the loss of a quorum when Commissioner Allison Clements leaves at the end of the month. 

“When it comes to fairly assessing all interests, five heads are better than one,” Energy and Natural Resources Committee Chair Joe Manchin (I-W.Va.) said on the Senate floor. “Bringing together five different people, with five different life experiences and perspectives, helps ensure that all affected interests will be heard and fairly considered and assessed.” 

Rosner, a FERC staffer who has been detailed to Manchin’s committee for the last couple of years, was approved 67-27. He fills the seat left open by former Commissioner Richard Glick, who chaired the commission when Biden took office until the end of 2022. His term will end June 30, 2027. 

Most of the votes against Rosner came from Republicans, but he also lost support from Sens. Ed Markey (D-Mass.), Bernie Sanders (I-Vt.) and Elizabeth Warren (D-Mass.), with environmental group Friends of the Earth opposing his nomination. 

“Lame duck Manchin is being allowed to dictate the future of FERC from beyond his political grave,” said Lukas Ross, deputy director of Friends of the Earth’s climate program, referring to the senator’s decision not to run for re-election. “This dirty deal preserves the status quo by entrenching a pro-fossil gas majority. A paid cheerleader for the LNG boom like David Rosner has no business as a Democratic nominee.” 

Before his time at FERC, Rosner worked at the Bipartisan Policy Center, whose energy program director, Sasha Mackler, said he was well qualified for the commission. 

“David has a tremendously deep knowledge of U.S. energy policy, as well as a keen appreciation for the complexities of the interactions between consumers, households, businesses, energy providers and other key stakeholders, including state governments,” Mackler said. “It is hard to imagine a more qualified nominee, or one with a higher level of integrity and dedication to public service.” 

See, the solicitor general of West Virginia, was approved 83-12. She takes the place of former Commissioner James Danly, who left at the end of last year. Her term ends June 30, 2028.  

She received support from every Republican except both of Missouri’s senators, Josh Hawley and Eric Schmitt. Hawley, who voted against all three nominees at the ENR Committee, had criticized her response to his questions about the Grain Belt Express transmission project. (See Senate Energy Committee Advances Biden’s FERC Nominees.) 

The Senate also voted to invoke cloture on the nomination of Judy Chang, former undersecretary of energy and climate solutions in the Massachusetts Executive Office of Energy and Environmental Affairs, 63-31, setting up a final vote for the next day. Chang would replace Clements after the latter leaves, and her term would end June 30, 2029. 

“While I may not agree with each of the nominees on all the items all the time, all of them are well qualified,” ENR Ranking Member John Barrasso (R-Wyo.) said. 

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CAISO Board Approves Interconnection Enhancements Proposal

CAISO’s Board of Governors on June 12 unanimously approved the ISO’s Interconnection Process Enhancements proposal, the product of more than a year of stakeholder engagement and rigorous troubleshooting.  

Intended to complement — but not replace — CAISO’s FERC Order 2023 compliance filing, the final proposal is designed to streamline the interconnection process in response to the “unprecedented volume” of requests the ISO received last year by reducing the amount the number of projects it will have to study. (See Stakeholders Seek Clarity on CAISO Interconnection Process Plan.)  

During the June 12 board meeting, Danielle Osborn Mills, CAISO principal of infrastructure policy development, presented slides showing that Cluster 15 in April 2023 vastly exceeded expectations and the interconnection queue now contains roughly three times the capacity needed to achieve California’s 2045 requirements.  

“I cannot overstate the importance of this initiative and the challenges our team and stakeholders faced in developing these transformative changes to our interconnection process,” Neil Millar, CAISO vice president of transmission planning and infrastructure development, said at the meeting.  

“The fundamental transformation we are seeking to implement is to shift more meaningful project development and procurement engagement to earlier stages in the interconnection study process,” Millar said. “While these changes will be disruptive and uncomfortable, they are necessary so that the ISO can deliver meaningful study results more quickly and phase out the habit of using the ISO interconnection process to simply screen potential sites.”  

Responding to stakeholder feedback, CAISO staff made one key change to the final proposal not included in prior drafts: a requirement for load-serving entities (LSEs) to opt in to the point allocation process and publicly post both contact information for the department or individual responsible for the process and selection criteria for allocating capacity.  

The change is intended to “increase the transparency and rigor of the load-serving entity allocation process,” Mills said. The prioritization of LSE interest in the scoring and point allocation process has been a significant area of concern for stakeholders. 

Scoring Criteria Concerns

While the proposal received broad support during the board meeting, many stakeholders expressed concern about moving forward with the final proposal. 

“One of the biggest concerns is the lack of allocation to the non-load-serving entities,” said Melissa Alfano, senior director of energy markets and counsel at the Solar Energy Industries Association. “There is the ability for the LSEs to withhold some things and strategically push forward less efficient projects.” 

Other stakeholders echoed Alfano’s concerns.  

“The scoring criteria are rooted in significant potential for a lack of transparency, unjust discrimination against non-LSE developers with viable projects and infringement upon principles of open access,” said Ryan Millard, senior director of West region regulatory and political affairs at NextEra Energy Resources. Other stakeholders “also highlighted instances of LSEs seeking concessions from developers in exchange for early points allocation which demonstrates a clear risk of exploitation.”  

He gave an example of a recent instance in which an LSE indicated to NextEra that it issues a request for proposals that includes Cluster 15 projects and would require developers to grant the LSE a right-of-first offer and submit a $5/kW deposit to secure LSE point allocation.  

“To put that into context for you, if you were to apply this to a 300-MW storage project, that’s a $1.5 million deposit that we would need to post 10 years before expected [commercial operation date] just to enter the queue. That’s untenable, even for some of the largest Western developers,” Millard said. “While we appreciate CAISO’s desire not to propose a prescriptive [request for information] process for LSEs, the absence of minimum standards introduces too much potential inequity.”  

Mills responded that the setting of standards falls under the jurisdiction of the California Public Utilities Commission (CPUC) and individual local regulatory authorities, not the ISO. Additionally, she emphasized that the ISO would continue to monitor the LSE allocation process after implementation and that the CPUC will exercise oversight over the procurement process, “scrutinizing utility-owned contracts against other contracts” to make sure they were selected fairly and transparently.  

“We did not want to do anything that was going to open the floodgates to only utility-owned generation, but at the same time, [we] didn’t want to do anything that was going to discourage or prevent it either,” Mills said.  

CAISO CEO Elliot Mainzer also weighed in.  

“We all know that any system of rules that you set up, including the existing system, can be subject to untoward behavior,” he said. “We know that there are risks here, and we have taken steps both within our tariff and in direct consultation with the leadership of the state and other local regulatory authorities to make sure that their processes are monitored carefully to make sure that we do not see untoward behavior or manipulation of the rules.”  

The ISO said it intends to file the changes with FERC in July and hopes to begin study of Cluster 15 projects in October.  

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FERC Approves EDAM Tx Revenue Recovery Plan

FERC on June 11 approved CAISO tariff revisions that will allow transmission owners to recover transmission revenue shortfalls attributed to transitioning their assets into the ISO’s Extended Day-Ahead Market (EDAM) (ER24-1746). 

CAISO’s initial proposal for the “access charge” was the only provision in the EDAM tariff the commission rejected when it approved the market’s design and rules in December. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM.) 

In the December order, FERC found the ISO failed to justify the reasons behind the three components constituting the access charge, but Commissioner Allison Clements at the time emphasized that the rejection came “without prejudice” and encouraged the ISO to work with its stakeholders and file a revised proposal. 

In the revised filing, CAISO explained that while participation in the EDAM will not alter a transmission owner’s (TO) transmission revenue requirement, it could cause the owner to lose out on transmission sales it could’ve made absent that participation, thereby reducing revenues. 

“CAISO explains that stakeholders have raised concerns that these changes in transmission owners’ revenues due to transmission owner participation in EDAM may result in unexpected downstream cost shifts for ratepayers,” the commission said in the June 11 order. 

The ISO said those cost shifts could be most pronounced upon launch of the EDAM and each time a new entity joins the market. 

3 Components

Like the initial proposal for the access charge, the revised plan consists of three components.  

Under the first component, TOs may include revenue shortfalls related to the transition from bilateral market transmission service to day-ahead market service. Those shortfalls could stem from EDAM transfers displacing revenues expected from sales of short-duration non-firm and firm point-to-point transmission service. 

“CAISO explains that EDAM transmission owners will first calculate their recoverable transmission service revenue based on the annual average of revenues associated with qualifying eligible short-duration transmission products,” the order notes. “The transmission service revenue shortfalls recoverable under the EDAM access charge’s first component will consist of the difference between the actual short-term transmission service revenues recovered and the three-year pre-EDAM average short-term transmission service revenues.” 

The second component of the EDAM access charge will permit TOs to recover a portion of the costs not reflected in the three-year “lookback” associated with the first component. This will include revenue shortfalls “from foregone sales of non-firm and short-term firm transmission service over certain new network upgrades and associated with the release of transmission capacity resulting from the expiration of EDAM legacy contracts,” the order noted. 

Under this component, a TO’s access charge can include only lost revenues associated with new network upgrades that have been approved by FERC or a local regulatory authority and that function as available transmission in EDAM. 

“CAISO explains that eligible new network upgrades are those that increase transfer capability between EDAM BAAs or between the CAISO BAA and an EDAM BAA, are in service and are energized after the EDAM Entity begins participation in the day-ahead market,” the commission wrote. The ISO also clarified that a TO cannot roll all its eligible new network upgrade costs or expiring legacy transmission contract costs into the EDAM access charge, but only an applicable percentage.   

The third component of the access charge allows an EDAM TO to recover shortfalls “associated with wheeling through an EDAM BAA or the CAISO BAA in excess of the total net EDAM transfer of the BAA,” with costs based on the transmission used to wheel energy completely through a TO’s system.   

“CAISO further states that in periods where this excess occurs, the EDAM Entity, on behalf of the EDAM transmission owner, will be compensated for the transmission use that supports the excess wheeling at the EDAM transmission owner’s non-firm hourly point-to-point transmission rate or the CAISO participating transmission owner will be compensated for excess wheeling through transmission use at the applicable wheeling access charge transmission rate,” the commission said. 

‘Effective Indefinitely’

Under the rules, CAISO will calculate an access charge rate for each EDAM entity based on the entity’s gross load. 

“CAISO proposes to calculate the rate using the aggregate projected annual transmission revenue shortfalls for each of the three EDAM access charge components of all other EDAM transmission owners, pro-rated to each EDAM BAA by its gross load ratio. As such, CAISO states no EDAM entity will be assessed its own projected recoverable revenue shortfalls,” the order said. 

The order notes that while CAISO views the EDAM access charge as a temporary measure, it expects the mechanism to “be a necessity for the foreseeable future” and remain “effective indefinitely” as more participants integrate into the market over time.  

Coming little more than a week after NV Energy confirmed its intent to join EDAM over SPP’s Markets+, FERC’s approval of the access charge marks another accomplishment for the CAISO market — and one that could draw additional commitments. 

In a March 21 letter to CAISO COO Mark Rothleder signaling its intent to join EDAM, Idaho Power cited the need for a “transmission revenue recovery mechanism” as a key concern the ISO needed to address before the utility could formally commit to the market. 

In addition to NV Energy and Idaho Power, the EDAM has won solid commitments from Balancing Authority of Northern California, Los Angeles Department of Water and Power, and Portland General Electric, while PacifiCorp in April became the first entity to fully commit to signing an implementation agreement with the market. 

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NYISO Board/MC Briefs: June 11, 2024

Emily Chen, an analyst with FERC’s Office of Energy Market Regulation, gave a briefing on Orders 1920 and 1977 to members of the NYISO Management Committee on June 11 during a joint meeting with the ISO’s Board of Directors. 

“We’ve had a busy year, and a busy May with two commission meetings, as I’m sure you’re well aware of,” Chen said. (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) 

Order 1920 requires transmission planners to use a 20-year horizon to identify long-term needs and the facilities to meet them. Long-term planning must occur at least once every five years using at least three plausible scenarios with the best available data and incorporating factors such as retirements, policy goals and corporate commitments. 

“We also require that you consider at least seven benefits to evaluate these regional proposals, including production, cost savings, or mitigation of extreme weather and unexpected system conditions,” Chen said. 

She noted that the order had been published in the Federal Register just that day, and it will go into effect Aug. 12. 

The rule also requires transmission providers to propose a default method of cost allocation to pay for long-term regional facilities and to hold a six-month engagement period before submitting their compliance filings. 

Order 1977 updates the process FERC uses when it is called upon to exercise its siting authority to include a Landowner Bill of Rights and a codified Applicant Code of Conduct for applicants to demonstrate good faith effort to engage with landowners in the permitting process. It also directs applicants to develop engagement plans to environmental justice communities and federally recognized tribes. The order was published May 29 and is effective July 29. 

Project Prioritization Process

Kevin Pytel, director of product and project management for NYISO, presented the proposed internal project prioritization for 2025 and outlined changes to the process since last year. 

“This process is not perfect, we know that, and we try to make it better every year,” Pytel said. 

NYISO had 53 proposed market projects this year; of those, eight were continuing projects. They include implementing five-minute transaction scheduling and ancillary service shortage pricing. 

The primary changes were to how NYISO handles “continuing” projects, which are those that were approved in a prior year that have progressed to the functional requirements specification, software design, development completion or deployment stages.  

Stakeholders had requested that the ISO revise the timeline for stakeholders to decide whether to continue with a project; they now have until June, pushed back from March.  

“The hope is that by moving this back three months, we will have a more healthy discussion and be able to come to a resolution quicker on which projects should be considered ‘continuing,’” Pytel said. 

The ISO also shifted the stakeholder scoring survey from June to July, which it said will allow it to develop a project set for budgeting purposes by early August. 

The Budget and Priorities Working Group will decide on the continuing projects at its meeting June 24; NYISO will also provide its own project scores at the meeting. The survey will be distributed July 3, with a deadline of July 14. The ISO will present the results to the working group July 31. 

NYISO’s internally facing enterprise projects that do not involve market rule changes are not subject to stakeholder approval. 

Rate Schedule 1 Allocation of the NYISO Budget

Chris Russell, senior manager of customer settlements for NYISO, reminded the committee of an upcoming vote to determine whether a new cost-of-service study should be conducted to evaluate the Rate Schedule 1 allocation between withdrawals and injections. 

Rate Schedule 1 is used by the ISO to collect its operating costs from members. The 2024 rate is $1.281/MWh, with 72% from withdrawals and 28% from injections. 

The current allocation was set by the committee in July 2011. It was originally scheduled to be effective for January 2012 to December 2016, but in 2016, the committee voted to decline conducting a study and has done so annually every third quarter through 2023.  

Russell said market participants have indicated that a study is necessary in the future because of the evolving market. Last year, the committee voted to waive the study by an overwhelming majority of 91.22%. (See NYISO Management Committee Briefs: July 26, 2023.) 

The vote will take place at the committee’s July 31 meeting. 

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SPP Board Adds Final OK to JTIQ Cost Framework

SPP’s Board of Directors added its approval June 12 to a proposed tariff revision that establishes a cost-allocation framework for projects in the Joint Targeted Interconnection Queue (JTIQ) with MISO. 

The revision request (RR620) addresses chronic transmission issues on the RTO’s seam with MISO related to generator interconnection requests and implements cost-allocation policies already approved by SPP’s state regulators. It also memorializes and defines how the JTIQ process will be implemented and applied once executed. 

Combined with earlier endorsements from stakeholders June 7 and state regulators June 10, RR620’s approval ends a process that began nearly four years ago after repeated fruitless attempts to find interregional projects both RTOs could agree on. 

SPP CFO David Kelley, who has assumed new responsibilities since the work began, told the board, “This feels like we are near the end of a really long marathon. It’s been a good journey.” 

The trek began with a thawing of relations between the two RTOs and their CEOs and, Kelley said, “a challenge to both SPP and MISO staff to go and work out a solution to problems that were shared by both RTOs.” 

The grid operators have identified five projects along their seam that can help unlock new generation and resolve congestion issues in the absence of interregional projects.

After being awarded a $464 million grant from the U.S. Department of Energy, the RTOs revised their original direct-billing approach for JTIQ projects to one that assigns 100% of the portfolio’s engineering and construction costs for interconnection requests that meet certain criteria. Those costs are estimated at between $1.6 billion and $1.8 billion before applying the DOE funds. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects, DOE Announces $3.46B for Grid Resilience, Improvement Projects.) 

“The more complicated piece of this would be associated with the funding and the handling of money from interconnection customers in both RTOs, as well as the transmission owners in both RTOs,” Kelley said. “That’s something that has never been done before, and it took a significant amount of time to figure those things out.” 

The Members Committee’s advisory vote passed 17-2, with two abstentions. EDP Renewables and the Advanced Power Alliance (APA) both voted against the measure. 

EDP’s David Mindham said that while his independent power producer sector supports transmission buildout and the JTIQ projects, the process itself represents a failure of planning in the two regions. He said a lack of coordinated assumptions and models has led to a “dysfunctional planning system that is broken.” 

“Generators want this transmission to be built … and we’re willing to pay for it,” Mindham said. “But in order to do that, the entities paying for this transmission are being asked to compromise on a lot of other issues and a lot of additional things that have bad precedent nationally for us, and we just can’t support that today.” 

Kelley reassured Mindham and the APA’s Steve Gaw that the framework’s structure is specific to the projects in the current portfolio and that their objections could be considered for the next round. 

“We fully understand that should there be another round of [JTIQ projects], we’re going to have these conversations and justify either something different or something else that is viable going forward,” Kelley said. 

The Regional State Committee unanimously approved the tariff revision June 10, and the Markets and Operations Policy Committee endorsed it June 7 with 89% approval. 

SPP will coordinate the FERC filing with MISO once its neighbor gains approval of its tariff revision. It will seek board approval of the JTIQ portfolio if the commission accepts the tariff change and updates to its joint operating agreement with MISO. 

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Xcel Wins FERC Waiver of MISO Interconnection Rules on Coal-to-Solar Plan

FERC has authorized an exception to MISO’s interconnection rights transfer process, allowing two Xcel Energy subsidiaries to cooperate on a replacement of a coal-fired plant with a solar farm.  

FERC said Xcel’s Northern States Wisconsin is free to substitute about 650 MW of new solar and potential storage facilities for Northern States Minnesota’s 591-MW Allen S. King Power Plant, which is scheduled to be powered down in 2028. The project would use the King plant’s point of interconnection (ER24-1719).  

Xcel requested the waiver of MISO’s ordinary interconnection rules because it plans to hand over MISO interconnection permissions from one Northern States Power affiliate to another. The King plant is near the Minnesota-Wisconsin state line. 

Ordinarily, MISO’s generating facility replacement rules prevent owners of retiring generator from transferring their facilities and interconnection rights to someone else from a year before they submit a replacement request up until the replacement generation reached commercial operation.  

Xcel plans to be coal-free no later than 2034 and said this transfer is a piece of the puzzle. It said pursuing an expedited process using a different interconnection customer under MISO’s generator replacement process is preferable to submitting the project for study in the interconnection queue, which takes years to complete.  

Xcel said it investigated alternatives to Northern States Wisconsin developing the solar facilities, including having Northern States Minnesota lead the project. However, it said Northern States Minnesota would be considered an out-of-state developer on the project, which requires approval from the Public Service Commission of Wisconsin.  

FERC said its approval was based in part on the fact that Xcel first explored alternatives and concluded they would “present tariff obstacles or other significant complexities and challenges.”  

The commission said the transfer doesn’t introduce queue-jumping concerns because the waiver encompasses “two wholly owned subsidiaries that operate a single integrated system” and doesn’t involve “unaffiliated entities outside of the interconnection queue.”  

The waiver, however, elicited a caution from Commissioner Allison Clements, who said the order exemplifies the “increasingly strained reasoning underpinning the transferability restrictions in MISO’s (and other transmission providers’) generator replacement rules.” She called for a “fulsome evaluation” of generator replacement rules because of their “piecemeal proliferation” across the country.  

“I concur because the effect of granting this waiver is that a brownfield site of existing generation on the transmission system can be expeditiously reused. I believe that outcome is consistent with the purpose of MISO’s generator replacement rules, and I acknowledge that fast-tracking the interconnection of new generation at previously studied sites may yield efficiencies and cost savings,” Clements nevertheless wrote in a concurrence to the order.  

But Clements suggested MISO’s transfer restrictions today may show undue preference to owners of existing generation. She said at this point, it appears MISO’s transfer rules require only the party assuming interconnection rights to be an affiliate of the original owner to bypass the queue and the cost responsibility of the original network upgrades.  

MISO’s generator replacement requests are poised to increase as members turn off the lights at their aging, baseload plants.  

Clements ended by urging the commission to take a fresh look at generator replacement processes and their “nonsensical transferability restrictions” that FERC “must contort around to permit rational commercial arrangements.”  

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Renewable Developers Oppose Proposed ERCOT IBR Rule

Several renewable energy developers have indicated they will oppose ERCOT stakeholders’ approval of a controversial rule change for inverter-based resources (IBRs) when the issue goes to a vote before the Board of Directors later this month.

Invenergy Energy Management, NextEra Energy Resources, Southern Power, Avangrid Renewables and Clearway Renew — the ad hoc “joint commenters” who have argued against the change — on June 10 filed a recommendation to oppose, urging the board to reject the revision to the Nodal Operating Guide (NOGRR245) during its June 17-18 meetings.

ERCOT’s Technical Advisory Committee endorsed the rule change June 7 after months of trading and reviewing comments with staff. It would impose voltage ride-through requirements on IBRs, aligning ERCOT’s protocols with NERC reliability guidelines and the most relevant parts of the Institute of Electrical and Electronics Engineers’ standard for IBRs interconnecting with the grid. (See ERCOT TAC Endorses Rule for Inverter-based Resources.)

The committee inserted gray-box language with potential modifications that wouldn’t become effective until March 2025. The language would enable entities to meet the applicable ride-through requirements when they have not yet added a “technically feasible” change. The revisions are aimed at those entities for which upgrade costs are less than 40% of the full, in-kind replacement cost of a plant’s inverters or turbines and converters.

The joint commenters agreed there is a sense of urgency to impose the standards and make them effective for IBRs. However, they urged the board to ensure that the ride-through standards “do not have the unintended consequences of harming reliability by eliminating existing generation and harming future investment in infrastructure in the ERCOT market.”

The commenters said TAC attempted to defer issues around hardware changes by placing them in the gray-box language, but that the action did not accomplish anything.

“The gray box simply indicates that hardware changes contemplated by ERCOT would be required unless a new NOGRR modifies such requirement before the gray box becomes effective,” the commenters wrote. They asked that the language be deleted and that required hardware modifications for existing IBRs be bifurcated from the NOGRR and addressed after further study of the reliability need for the requirements.

NOGRR245’s TAC-approved version has “fatal flaws,” they said. “It imposes arbitrary costs on existing generation [IBRs] and unlawfully gives ERCOT … authority to indefinitely shutter existing operational IBRs.”

‘Unresolved Issues’

“While I appreciate that both the joint commenters and TAC wanted to decouple hardware changes from everything else, there are still a lot of unresolved issues,” Eric Goff, representing the commenters, said in an email to RTO Insider.

During the June 7 conference call, Goff recommended that TAC members vote against the motion. He said that while the main intention is in “good spirit,” the six to nine months allowed to work on hardware issues won’t solve any problems.

“That’s due to the [Public Utility Commission of Texas’] procedural rules,” he told TAC. “If the joint commenters believe that the proposals here are not lawful or bad policy, we have 35 days to appeal an ERCOT action. We would be forced to appeal this or lose the right to appeal it, so it would result in this issue not getting six to nine months of time in the ERCOT stakeholder process, but rather in a contested case with the commission.”

Goff also said the NOGRR includes “inappropriate” changes to technical requirements that have yet to be approved.

The joint commenters face long odds in seeing the board reject NOGRR245. ENGIE’s Bob Helton pointed out during the TAC call that striking the gray-box language would lose ERCOT’s support for the change.

“I would assume that means [ERCOT] is going to challenge that at the board. I’ve got a pretty good idea of where we would end up. … The board would likely go with ERCOT on the appeal,” Helton said.

The ERCOT board remanded the NOGRR back to TAC in April, directing that the language — approved by the committee over staff’s objections — be modified to address staff’s reliability concerns. (See ERCOT Board of Directors Briefs: April 22-23, 2024.)

A pair of IBR-related voltage disturbances in West Texas in 2021 and 2022, dubbed the “Odessa disturbances,” added urgency to eventually passing the measures. (See NERC Repeats IBR Warnings After Second Odessa Event.)

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NE Generators Propose Financial Assurance Changes

Representatives of the New England Power Generators Association (NEPGA) and Competitive Power Ventures (CPV) offered amendments to ISO-NE’s proposed changes to the financial assurance provisions for the Forward Capacity Market at a joint meeting of the NEPOOL Markets Committee and Budget and Finance Subcommittee on June 11.  

ISO-NE has raised concerns that its financial assurance policy — intended to ensure that generators can pay penalties associated with failing to meet their capacity supply obligations (CSOs) — does not adequately protect against the risks of generators defaulting. 

To address these concerns, the RTO has proposed to rely on a “corporate liquidity assessment” to evaluate whether generators will be required to provide additional financial assurance. 

The proposed amendments presented at the meeting focused on ways to reduce pool-wide default risks, with the hope that reducing the overall risks would enable ISO-NE to ease the financial assurance requirements for generators. 

NEPGA’s Bruce Anderson said allowing generators to sell monthly CSOs closer to each period would help mitigate the risk of equipment failures leading to unmet obligations. He noted that the last opportunity to sell CSOs is more than a month in advance of each monthly period. 

“Allowing for bilateral trading closer in time to the relevant month will decrease the risk of default for a market participant that may not be able to perform,” Anderson said.  

NEPGA has also proposed to increase the payback period for Pay-for-Performance penalties, saying this would similarly reduce the overall risk of defaults. He highlighted recently approved tariff changes at PJM “allowing for longer payoff periods of up to nine months.” 

CPV’s Joel Gordon echoed the potential of increasing the opportunities for generators to sell their obligations. He said ISO-NE could consider a rule to enable it to terminate a CSO if a generator defaults on a penalty, or it could create a special status for defaulting generators. 

“There are market design solutions that would significantly reduce the potential exposure that should be explored,” Gordon said, emphasizing the need to “address the underlying cause first.” 

ISO-NE said it plans to respond to the proposals in July and is targeting an initial vote on the finance assurance changes in August. 

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Bill Gates’ TerraPower Breaks Ground on Advanced Nuclear Plant

TerraPower on June 11 broke ground on its Natrium reactor demonstration project in Wyoming, making it the first advanced reactor to enter construction. 

TerraPower was founded by billionaire Bill Gates and the project is supported by a long-term contract with PacifiCorp, which is part of fellow billionaire Warren Buffett’s Berkshire Hathaway business empire. 

“I’m proud of all the partners and people who helped get the most advanced nuclear project in the world built in Kemmerer, Wyoming,” Gates said in a statement. “I believe that TerraPower’s next-generation nuclear energy will power the future of our nation — and the world.” 

Construction is expected to take five years and at its peak will employ 1,600 workers. Once the plant is operational, TerraPower expects it will support 250 permanent employees.  

The Natrium reactor will be a fully functioning commercial power plant, which is being built at the site of a retiring coal-fired power plant in Kemmerer. 

The 345-MW reactor uses sodium-cooling technology with a molten salt-based energy storage system that can boost its overall output to 500 MW when needed, which is enough to power 400,000 homes. The energy storage capability allows the project to help balance with renewable power, which has long been an issue with conventional nuclear plants that that lack ramping flexibility. 

The company’s construction permit application is still pending at the Nuclear Regulatory Commission, but it was able to start construction on non-nuclear facilities while nuclear construction awaits regulatory approval. 

The NRC announced last week that it was advancing its consideration of the project and noted that if it approves construction, TerraPower would have to submit another application to actually operate the power plant. 

“This is a challenging yet exciting time in the energy industry,” PacifiCorp CEO Cindy Crane said in a statement. “In an era of rapid change, the need for reliable, affordable and dispatchable energy will remain a constant. Innovative technologies like the Natrium project will enhance our ability to serve our customers, meet growing demand, and ensure a reliable and resilient energy future.” 

Engineering firm Bechtel is building the facility, and company President Craig Albert said in a statement that the project will launch a new approach to nuclear construction that is meant to be safer, cleaner and faster. The company has built 150 nuclear plants around the world over the past 70 years. 

“Working together, the combination of advanced technology and streamlined constructability has the potential to diversify the U.S. power generation industry,” Alber said. “The option of deploying smaller advanced nuclear plants that can work in concert with other clean energy sources will help speed our progress toward net-zero emissions.” 

Constellation’s Dominguez Comments on State of the Industry

Speaking on a Reuters webinar June 10, Joseph Dominguez, CEO of Constellation Energy, which owns and operates one of the largest nuclear fleets in the country, said it’s still an open question which technology will dominate the future of the industry. Dominguez said the existing fleet of reactors could run until 2060 or beyond, but that would require major investments and Constellation is also focused on expanding nuclear production. 

“We are expanding the output of our plants,” Dominguez said. “As we change over equipment, we tend to get better materials, better efficiencies and all sorts of things, generators, pumps, everything that allows us to increase the output of the machines and put on the grid almost immediately, at least in power terms — over a handful of years, new firm, clean energy. And then we’re also investigating the next generation of small modular reactors or large-scale nuclear plants.” 

Some firm clean power is going to be necessary to reach net-zero goals, and nuclear faces competition from other technologies, including natural gas-fired generation with carbon capture and storage, which Constellation is also looking into, he added. 

While the company recently bought NRG’s share of the South Texas Project, Dominguez said other opportunities to buy existing nuclear plants are not on the table because their owners recognize the value of those assets, focusing Constellation on organic growth through capacity uprates, the possibility of restarting its Three Mile Island plant in Pennsylvania, and eventually the potential for building new plants. 

“Over the last 10 years, [the industry] only brought on two nuclear units,” Dominguez said, referring to Southern Company’s Plant Vogtle expansion. “And some reports indicate that those have been as much as $20 billion apiece to build. So, the ability to restart a unit at a fraction of those costs, to create an environment where you can do all the state-of-the-art upgrades to the unit to allow it to be able to run for decades more — that’s an incredibly valuable opportunity for America.” 

The theory with small modular reactors is that much of the equipment would be manufactured at a central facility and then transported to the power plant’s location, which is how the industry builds gas-fired and renewable power plants, Dominguez said. 

“The way we think about it right now is we’ve got to see these technologies evolve, we’ve got to see folks prove out the competency,” he added. “I think they’ll do that in the next five or six years. And then we’ll select the technologies that best suit our needs, and our customers’ needs.” 

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DTE to Replace Historic Coal Plant with Batteries

DTE Energy said it will build a large battery energy storage system on the site of a coal-fired plant it is demolishing near Detroit. 

With a capacity of 220 MW and 880 MWh, the Trenton Channel Energy Center is expected to be the largest standalone battery storage site in the Great Lakes region when completed in 2026. 

Company officials said the project will bring the state closer to the MI Healthy Climate Plan goals outlined by Michigan Gov. Gretchen Whitmer (D), who joined them for a ceremonial groundbreaking at the riverfront site June 10.  

“DTE’s new Trenton Channel Energy Center will help us strengthen our grid and produce more clean power when it’s less costly and store it for later when we need it,” she said in a prepared statement. 

DTE CEO Jerry Norcia said in a news release the new battery facility will support the utility’s CleanVision Integrated Resource Plan and help move the state closer to its energy storage target. It is the largest of several energy storage projects DTE has in development. 

A rendering shows the battery energy storage system planned to replace the Trenton Channel plant. | DTE Energy

Public Act 235 sets a goal of 2.5 GW of storage installed by 2030.  

DTE said the Inflation Reduction Act is providing an important financial boost for the Trenton Channel project — $140 million in tax incentives. 

The original Trenton Channel Power Plant dated to 1924, and a companion plant running at higher steam conditions was built in 1950. The “low-side” plant was decommissioned in the 1970s, and its boiler house was demolished.  

The “high-side” plant remained in operation, but in later years, activists and regulators targeted it because of its emissions. 

Its last operational generating unit was retired in 2022. The Sierra Club framed the retirement of Trenton Channel (and the St. Clair and River Rouge coal plants) as the result of a Clean Air Act enforcement case; DTE framed them as a long-planned part of its net-zero initiative, which includes the phaseout of coal by 2032. (See DTE, Activists Announce Agreement to Exit Coal by 2032.) 

DTE’s annual fuel mix report compares its own statistics with the five-state regional average and shows mixed results for 2022, the last year in which Trenton Channel and St. Clair were fired up. 

DTE has relied on coal for 54.16% of its generation vs. 41.8% for the region; its nitrogen oxide emissions per MWh of power generated were 50% higher than the region, and its sulfur dioxide emissions per MWh were 128% higher. 

But DTE also generated 13.1% of its electricity with renewable sources — mostly wind — compared with a regional average of just 6.8%. DTE’s carbon dioxide emissions per MWh were 13.5% higher than the regional average. 

Demolition of the Trenton Channel Power Plant has begun.  

The dual 563-foot smokestacks — local landmarks known as The Witches’ Socks or The Candy Canes for their red and white bands — were brought down with explosives March 15, and the boiler house is scheduled to meet the same fate at sunrise June 21. 

The plant was not only a landmark for generations of area residents, but also a literal and figurative powerhouse for the area’s economy, with a nameplate capacity as high as 1,060 MW, plus a sizeable workforce and local tax impact. 

DTE said the battery plant will generate tax revenue for the community to continue the coal plant’s legacy.