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November 14, 2024

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FERC’s Clements Gets GETs’ Benefits to Grid

AUSTIN, Texas — FERC Commissioner Allison Clements is no rock star, but observing her appearances during a gathering of federal and state regulators last summer, you might be mistaken.

Heads turned as she entered a large conference room with several of her staffers, taking a front-row seat for a National Association of Regulatory Utility Commissioners’ discussion on grid-enhancing technologies (GETs). Attendees whispered and nodded in Clements’ direction. Some regulators approached her. Others gave her space. 

Asked if the attention makes her feel like she’s in the same orbit with Mick Jagger or Bruce Springsteen, Clements breaks into a smile and turns toward one of her staffers. 

“Well, I like to go see rock stars,” she answered, noting she did catch Western swing band Asleep at the Wheel’s performance the night before. 

Her day job does take precedence, however. From the moment she joined FERC in 2020, Clements has focused her energy on GETs, such as sensors, power flow control devices and analytical tools that maximize the existing transmission grid. She has taken a key role in helping FERC establish the appropriate incentive mechanisms for the technologies’ adoption.  

Clements earnestly watched the discussion during the NARUC summit. Offered a chance to comment, she stressed the importance of financial incentives to help utilities roll out GETs and said it’s important to dispel the “myth” that GETs are rife with risks when deployed. 

“The existence of those risks shouldn’t stop us from starting to require consideration of deployment, and certainly the many cases we’ve heard so far about entities that have used dynamic line ratings to the benefit of customers have found ways to manage those,” she said. (See FERC-state Transmission Task Force Examines Barriers to GETs.)

A more relaxed Allison Clements | © RTO Insider LLC

And then there are the economic benefits. 

“As I spoke with providers of grid-enhancing technologies and learned anecdotally the amount of savings that people were getting … as well as the amount of capacity they were freeing up on the system, it was a no-brainer to me,” Clements said. “The light bulb went on and I said, ‘You can’t stand up as an economic regulator on behalf of customers if you don’t try and squeeze the savings out of the existing system that has already been paid for.’ 

“The cost of these investments are so modest relative to alternatives that they’re an excellent complement to the development of the transmission system,” she added. “They can’t replace the need to modernize our system with new transmission, but certainly they’re an important complement to that investment.” 

During FERC’s July monthly meeting, Clements referred to a Grid Strategies report estimating that congestion cost the country about $20.8 billion in 2022, up $14 billion since 2020. She also mentioned a Brattle Group white paper that says using GETs to unlock additional capacity on the grid would save customers $8.3 billion. 

She says GETs are a topic “that was once relegated to small windowless conference rooms full of energy grid geeks,” but are now “front of mind” in big rooms before the nation’s regulators.  

“GETs will be a win for customers, and states are taking notice,” she said in July. Recalling NARUC’s discussion of the technologies, Clements added, “My team and I had fun brainstorming technology that came after some of the early GETs, like the floppy disk and the Walkman. Today, utilities around the world have proven experience and results. 

“I came away with the sense that the regulators, as a group, are open to more systematic deployment of these GETs solutions and I look forward to working with them.”  

Noting that part of an engineer’s job description is to be conservative when it comes to reliability, Clements said it’s incumbent on regulators to align financial incentives to encourage the risks of using GETs. 

“[Regulators] don’t have to attach a synchrophasor to every line, but to start getting comfortable and educating and understanding their benefits and limitations,” she said. 

Clements cited as an example PPL Electric Utilities and PJM using a dynamic line rating (DLR) solution to resolve congestion on two transmission lines. She said they spent $500,000 on one line and avoided a $12 million reconductoring. PPL and PJM spent several million dollars on the two lines, which have saved more than $23 million annually, exceeding projections. (See Grid-enhancing Technologies Poised for Growth with Federal Funds.) 

FERC has responded with several initiatives to help facilitate GETs’ deployment. In July, the commission approved Order 1023, which reforms interconnection procedures and included language requiring transmission providers to consider advanced power flow control, transmission switching, and static synchronous compensators and VAR (Volt-Amps reactive) in their studies. 

“It’s a great start for grid-enhancing technologies, or as the rule calls them, alternative transmission technologies,” Clements said during FERC’s July meeting. “The rule’s requirement sets only a low bar: ‘evaluation’ of these technologies. I encourage utilities and grid operators to embrace the opportunity this rule provides, learn more about how to grow your consideration and deployment of these grid-enhancing technologies, and share your learning with your neighbors.” 

The commission has opened a DLR inquiry (AD22-5) to examine whether their use would help ensure just and reasonable wholesale rates by improving the accuracy and transparency of line ratings. It also has a proposed rulemaking (RM21-17) that mandates DLRs and advanced power flow control devices be more “fully” considered in regional transmission planning processes. 

“I would love to see all those things get done,” Clements said. “Grid-enhancing technologies happily provide that modest investment cost. The return on investment is a fraction of the time of a traditional infrastructure expenditure. And they’re dynamic, they’re modular, you can move them, you can use them where they work. There’s just a lot of options to make the grid smarter. The numbers are striking. The dollar savings are striking.” 

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ERCOT Appeals for Conservation as Winter Roars in

With demand projections and available capacity changing by the minute as a winter storm rolled into Texas, ERCOT and state officials spent last week assuaging Texans that the grid will remain standing this week.

Speaking to residents who remember well the devastating February 2021 winter storm that killed hundreds and caused billions in damages when the ERCOT system failed, Texas Gov. Greg Abbott said during a press conference Friday, “I know a lot of people are concerned, ‘Is the power going to stay on?’

“We feel very good about the status of the Texas power grid and ERCOT to be able to effectively and successfully ensure that the power is going to be able to stay on throughout the entirety of this episode,” he added.

The National Weather Service has placed much of the state under a winter weather advisory through Monday, warning of “dangerous” temperatures in the 20s as far south as the Gulf Coast. However, unlike three years ago, little snow or ice is expected.

ERCOT CEO Pablo Vegas said Friday he expects renewable energy to perform as normal, given the lack of precipitation statewide. He said there were no expectations of energy emergencies or conservation calls.

“Things can change and if it does change, we’ll continue to communicate openly over the course of this weekend,” Vegas said.

Sunday evening, things changed. ERCOT issued a conservation appeal for Monday morning due to the freezing temperatures, demand and low reserves. The ISO asked Texans to conserve their electric usage between 6 a.m. and 8 a.m., when solar resources start ramping up and temperatures are forecasted to be below 10 degrees Fahrenheit in North Texas.

ERCOT expects conditions to be similarly tight Tuesday morning. As of 7 p.m. Sunday, the grid operator was projecting a record peak of 86.1 GW, with only 83.8 GW of seasonal available capacity. However, the forecasted curves have changed frequently in the days leading up to the storm’s arrival.

Demand that high is the norm during the summer, having peaked at 85.5 GW in August. ERCOT set its record winter peak of 74.5 GW during the December 2022 winter storm.

The ISO stressed the conservation appeal does not indicate it is experiencing emergency conditions. It said in a press release staff will “remain vigilant and communicate further if conditions change.”

ERCOT also has asked all state and local government agencies to reduce energy use at their facilities until at least 10 a.m. Monday.

The grid operator previously issued a weather watch that went into effect Sunday and expires Wednesday. It said it made the advance notification because of “forecasted significant weather with higher electrical demand and the potential for lower reserves.”

Vegas has said the grid “is as ready and reliable as it has ever been for the winter season.” Legislation passed since the disastrous 2021 winter storm has strengthened the ISO’s weatherization practices — staff have completed nearly 1,800 facility inspections over the past couple of years — and created new ancillary services that can be brought to bear.

SPP Expects Near-record Demand

SPP said it projects to have sufficient capacity to meet anticipated demand this week, despite minimum temperatures in its 14-state Great Plains footprint similar to those observed during the December 2022 storm.

“We have substantial systems and procedures in place and our staff stands ready to mitigate any risks related to maintaining electric reliability,” Senior Vice President of Operations Bruce Rew said in a statement.

With temperatures that could be 30 to 50 degrees below normal, the RTO was expecting load to be as high as 45 GW on Monday and 46 GW on Tuesday. Its all-time winter peak is 47.2 GW, set during Winter Storm Elliott in 2022.

SPP said high pressure building into the Plains behind the cold-weather system may bring a sharp reduction in wind power generation, elevating the risk of outages. The grid operator on Friday issued a conservative operations advisory for its balancing authority area, effective 4 a.m. CT Sunday through 9 p.m. Tuesday.

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NEPOOL Markets Committee Briefs: Jan. 11, 2024

Analysis Group Presents Final Report on Capacity Market

WESTBOROUGH, Mass. — Adopting prompt and seasonal capacity auctions would provide a range of benefits that would help enable New England’s clean energy transition, Todd Schatzki of Analysis Group told the NEPOOL Markets Committee on Jan. 11.

Schatzki presented the consulting firm’s final report on significant potential changes to ISO-NE’s Forward Capacity Market. While the Forward Capacity Auction is currently held more than three years prior to the annual capacity commitment period (CCP), ISO-NE is considering a transition to holding the auction as close as a few months prior to the CCP, as well as dividing the CCP into distinct seasons.

Responding to stakeholder questions based on a draft report the firm presented in December, Schatzki reiterated Analysis Group’s recommendation to adopt a prompt and seasonal market for the 2028/29 CCP. (See Analysis Group Recommends Prompt, Seasonal Capacity Market for ISO-NE.)

A prompt format would provide a “technology-neutral platform for competition among resource types,” Schatzki told the MC. This would benefit new clean energy resources with shorter development timelines compared to new gas plants, which the existing forward market was originally designed to accommodate, he said.

Schatzki added that a prompt, seasonal market would also more accurately forecast load growth from electrification and the effects of counterbalancing state policies intended to reduce demand. He also noted that a seasonal format would also increase incentives for resources that provide winter reliability benefits.

A seasonal market “creates price signals for the development of capacity resources to complement the variable output of resources important to states’ decarbonization efforts, such as solar PV and offshore wind,” Schatzki said.

Responding to stakeholder questions about the merit of holding seasonal auctions simultaneously or sequentially each year, Schatzki said sequential auctions could result in a small percentage of resources obtaining only a capacity supply obligation in one season, creating a risk that these resources would struggle to recover their annual costs.

In contrast, holding the auctions simultaneously could enable generators to dictate annual revenue requirements that need to be recovered through one or multiple seasons.

Analysis Group declined to recommend either design. It noted that holding the auctions simultaneously “offers many conceptual advantages, but the auction structure decision requires a thorough and careful assessment.”

The firm made some changes to the methodology of the quantitative analysis for the final report, finding that alternatives to the FCM resulted in lower prices in eight out of nine scenarios, by 8% on average. A prompt and seasonal market showed the most significant price reductions, with payments projected to be 12% lower — equal to more than $200 million annually — relative to the FCM.

ISO-NE is planning to make a recommendation on whether to move to a prompt and seasonal market at the MC’s meeting next month, with a vote by the committee on whether to further delay FCA 19 projected to occur in March.

Resource Capacity Accreditation Impact Analysis

Throughout the three-day MC meeting, NEPOOL discussed several aspects of ISO-NE’s ongoing Resource Capacity Accreditation (RCA) project, which would bring major changes in how the RTO calculates the capacity value of several resource classes.

Dane Schiro of ISO-NE presented the RTO’s updated impact analysis framework, which is intended to “provide quantitative insights into the RCA design.”

The analysis will provide information on how the RCA changes would affect accreditation values and capacity supply obligations for different resource types, as well as metrics related to capacity market prices and loss-of-load expectations. ISO-NE performed an initial version of the impact analysis in April 2023 before a software issue derailed the project for several months.

In a change from the initial impact analysis methodology, gas resources will now be studied at the fleet level instead of at the individual level, while the risk assessment for oil resources will include a two-week inventory limit.

The analysis will use a base case that employs the resource mix associated with the upcoming FCA 18 and the load forecast for FCA 19. Imports will be based on the level cleared in FCA 13, which represents the median amount from the past five auctions.

The first phase of the analysis will focus on resource accreditation in the base case, while the second phase will look at different sensitivity scenarios, including changes to the amount of fossil fuel resources replaced by renewables and an increased winter peak load. The third phase is intended to give quantitative insight on auction results, including demand curves, clearing prices and LOLE.

Marginal Reliability Impact Calculations

As a part of the ongoing RCA project, Steven Otto of ISO-NE detailed the RTO’s proposed approach to calculating the marginal reliability impact (MRI) and qualified MRI capacity (QMRIC) values for different resource classes.

MRI aims to quantify how small changes to a given resource’s output would affect grid reliability. MRI is an input to QMRIC, which represents a resource’s overall accredited capacity.

MRIs will be calculated for two seasonal periods: a June-September summer period and an October-May winter period. Seasonal MRI values for existing thermal resources “will be driven by their equivalent forced outage rate on demand excluding events out of management control,” ISO-NE said.

For new thermal resources, MRI values will be calculated based on the averages associated with their resource class. MRI values for new storage and large wind and solar resources will be created by modeling the marginal addition of a proxy resource. Small existing intermittent resources with a nameplate capacity of less than 10 MW will be combined into aggregations for their MRI assessments.

Gas Accreditation

Prior to the MC meeting, ISO-NE issued a memo detailing several potential methodologies for accounting for gas system constraints in the RCA updates. The current accreditation approach does not account for gas system constraints when determining a resource’s capacity value.

The RTO is recommending a derating approach for gas resources, which “decreases the accredited capacity of all gas resources so that their total accredited capacity equals the gas constraint,” ISO-NE wrote.

ISO-NE also discussed the possibility of a “market constraint approach,” which would not decrease the accreditation of gas resources based on a lack of firm fuel commitments, but instead would “decrease the amount of gas capacity procured in the winter … and would pay that capacity a lower price.”

“The market constraint approach achieves the same level of reliability as current rules, but at least cost,” ISO-NE said. “The awards determined by the market constraint are cost minimizing: No other set of awards could achieve the same level of reliability at lower social costs.”

ISO-NE proposed to conduct additional analysis into implementing a market constraint approach, while adding that the derating approach would be easier to quickly implement and makes sense as a “as a reasonable transition mechanism.”

“Overall, the market constraint approach is preferred but is not implementable for FCA 19 or a one-year delayed auction timeline and likely requires a seasonal market construct,” the RTO wrote.

ISO-NE also included the possibility of an “MRI=0 approach,” which would not award any accredited capacity to gas resources that lack firm fuel arrangements. The RTO wrote that this approach “would not procure a socially optimal quantity of gas capacity, nor would it pay the gas capacity an appropriate price.”

Tom Kaslow, vice president at FirstLight Power Resources, presented to the MC on the company’s concern that ISO-NE’s proposed approach would not provide adequate incentives for firm gas contracts.

Kaslow told RTO Insider that ISO-NE’s proposal to determine the maximum reliability contribution from gas resources based on the expected available gas supply could “undermine the forward contracting for firm gas supply access that would assure that the future year assumed gas supply is realized.”

“While there is a history of a certain level of available gas supply to gas-fired generators, without advance contracting, circumstances can change, as evidenced by the possible retirement of the Everett Marine Terminal,” Kaslow added.

The company is asking ISO-NE and NEPOOL for additional analysis into how the different approaches to accounting for gas system constraints would impact incentives for firm fuel contracts.

Committee Votes

The MC voted to support an update to ISO-NE’s compliance with Order 2222 that would make distributed energy resource aggregations responsible for submitting their own metering data to ISO-NE.

FERC clarified in October that this metering information could “come from or flow through distribution utilities.” (See FERC Responds to ISO-NE Rehearing Request on Order 2222.) ISO-NE’s current proposal would allow a DERA “to designate itself, a party acting on its behalf or the host participant to be the assigned meter reader.”

The committee also voted to recommend updating the forward reserve offer cap to $7,200/MW-month and delay the publication of forward reserve auction offer data for 12 months to address market power concerns.

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NJ Grid-scale Solar Projects Face BPU Scrutiny

The New Jersey Board of Public Utilities rejected one project and supported another in the state’s new grid-scale solar program Jan. 10. In a separate move, the board agreed on a consultant to prepare the groundwork for its fourth offshore wind solicitation, expected to begin early this year.  

The two solar cases were seeking approval under the Competitive Solicitation Incentive (CSI) program, which the BPU launched last year. Despite the agency’s hopes it eventually will be a major part of the state’s solar sector, it has yet to endorse any CSI projects.  

The BPU in spring 2023 opened the first solicitation under the CSI program, which handles projects greater than 5 MW. But the agency in July rejected all of the applications, saying the bids were too high. The agency is accepting applications under a second solicitation, which opened Nov. 27 and closes Feb. 29. (See NJ Rejects Solar Bids as Too Expensive.) 

In each of the two proposals discussed Wednesday, the developer is seeking to build a solar farm on land that is preserved under New Jersey law, and so usually is off-limits to solar projects. The developers asked the BPU to grant waivers that would allow the projects to move ahead. 

The board rejected the waiver request by Nexamp Solar, which is seeking to build a 10-MW floating solar project on two islands, each 10 acres in size, on the Wanaque Reservoir. The reservoir is in the Highlands Preservation Area, which is part of the Appalachians and stretches about 60 miles through New Jersey and provides a large chunk of the state with drinking water. 

Commissioner Zenon Christodoulou, speaking after the vote, said it was a “difficult” decision. 

“What we’re trying to do is try and get as much renewable energy out there,” he said. But the developer had not met the CSI rules, he explained, and urged other developers to “please be a little bit more precise with their filings and [be] on time,” in their submissions. 

Open Space or Built Land

CSI rules allow a waiver if the project is sited on a “built environment,” rather than pristine land. The developer argued that the reservoir fit the description because the project won’t be built on open space, but a water body. In addition, the developer argued that the CSI rules favor solar developments on “previously existing impervious surfaces,” and the reservoir fit that description because it was built in the 1920s with a floor on a “bedrock resistant to filtration,” according to the board order.

BPU staff said that to receive a waiver, any applicant had to meet several criteria under CSI rules, including showing the project is in the public interest, which Nexamp Solar did. But during the two- to three-year application process the project failed to provide sufficient information to the state Highlands Council and New Jersey Department of Environmental Protection (DEP) when asked, said Laura Scatena-Amissah, a BPU research scientist. 

“This failure to address the specific concerns of the relevant administrative agencies outweighs general statements about environmental or community benefits,” she said. 

In the second case, the board approved a waiver request by NextGrid Inc., which is seeking to build a 5.2-MW solar farm and battery storage facility under the CSI program in Manchester Township on 18.4 acres of a former landfill. The project would be sited in the Pinelands Management Area, a 295,000-acre area of forest and wilderness in South Jersey. 

Although the Pinelands Comprehensive Management Plan allows solar projects in that area only in “very limited circumstances,” the developer’s interaction with state agencies — including the Pinelands Commission, which oversees the area — suggested the waiver should be granted, according to the BPU order. 

Aside from the economic benefits to the area and the generation of renewable energy, the project would help cap and close the landfill and would help an overburdened community, BPU staff said. The project also has the support of the DEP and Pinelands Commission, and so a waiver is warranted, the order said. 

Fourth OSW Solicitation Work

In a separate move, the BPU agreed to extend the contract of a consultant working on the state’s third OSW solicitation, in part so the same company could start work on the state’s fourth search for OSW project proposals. 

Although the BPU is evaluating four proposals submitted in the third OSW solicitation, Gov. Phil Murphy (D) on Nov. 29 said the agency should prepare to launch a fourth solicitation early this year. 

His statement followed the announcement by Danish developer Ørsted on Nov. 1 that it would abandon the state’s first OSW project, the 1,100-MW Ocean Wind 1, and a second project in the state, the 1,148-MW Ocean Wind 2, because the developer no longer believed they were financially viable. (See Ørsted Cancels Ocean Wind, Suspends Skipjack.) The decision puts back by at least two years the date by which the state expects to have an OSW project up and running. 

Murphy, in a release announcing his acceleration of the program, said he did so in “recognition of the strong future of New Jersey’s offshore wind industry. 

“New Jersey can — and will — continue to remain a burgeoning offshore wind development hub that attracts new projects and their accompanying economic and environmental benefits for generations to come,” he said. 

The BPU is evaluating four proposals submitted in the third OSW solicitation and is expected to announce in the first quarter which — if any — proposals are selected for development. The solicitation is expected to award capacity up to 4 GW or more, with a completion date of between 2027 and 2029. 

The BPU OSW schedule calls for the fourth solicitation to begin in the first quarter of this year, with projects awarded a year later and completed by 2032. The schedule sets a preliminary capacity award of 1.2 GW in the solicitation. 

Consultant Levitan & Associates Inc. (LAI), of Boston, is working for the BPU on the third solicitation, work that includes evaluating the four applicants, BPU staffer Kira Lawrence told the board. She said the agency needs to extend the consultant’s contract to do further work on the third and fourth solicitations. 

“In order for staff to comply with the governor’s direction, the consultant is needed to begin work as soon as possible,” she said. LAI has been the board’s consultant for all three previous solicitations and has experience with providing the necessary services and knowledge of the board’s processes, she added.

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DOT to Fund EV Chargers in Remote, Disadvantaged Communities

The Department of Transportation has rolled out the first round of funding for EV chargers to be located in remote, tribal and low- and moderate-income communities across the nation, with $623 million from the Infrastructure Investment and Jobs Act going to 47 projects in 22 states and Puerto Rico, according to a Jan. 11 announcement.

The funding will put a total of 7,500 EV chargers in a range of locations, from multifamily housing developments in New Jersey and Maryland to public libraries in California to remote villages like Haines, Alaska (2023 population: 1,951), which currently has no chargers.

The North Central Texas Council of Governments will get $70 million for up to five hydrogen fueling stations for medium- and heavy-duty freight trucks at sites in Dallas-Fort Worth, Houston, Austin and San Antonio, according to the announcement.

The awards are the first being made from the Charging and Fueling Infrastructure (CFI) Discretionary Grant Program, which received $2.5 billion from the Infrastructure Investment and Jobs Act. The program is the competitive counterpart of the IIJA’s $5 billion National Electric Vehicle Infrastructure (NEVI) program, which provides all states with yearly, formula-based allocations to put EV chargers on major interstate and state highways.

The first NEVI chargers went into operation in Ohio and New York at the end of 2023.

CFI is aimed at filling in the gaps at the local level, working with organizations that might not qualify for NEVI or other funding, in line with President Joe Biden’s Justice40 initiative, which is intended to ensure that 40% of the benefits of all federal funding go to disadvantaged communities.

According to DOT, more than 70% of the projects receiving funds will be in disadvantaged communities. The projects also must comply with DOT’s technical standards for federally funded chargers, which require that all charging stations have at least four ports and that direct current fast chargers be at least 150 kWh. Public chargers must be available 24/7 and accept all major credit or debit cards.

“From my time working at the local level, I know that finding electric vehicle charging in a community is different from finding charging along highways,” Deputy Secretary of Transportation Polly Trottenberg said in the announcement. The CFI-funded projects “will provide Americans with convenient, straightforward charging options in their communities.”

Energy Secretary Jennifer Granholm hailed the awards as “bringing an accessible, made-in-America charging network into thousands of communities while cutting the carbon pollution that is driving the climate crisis.”

“Every community across the nation deserves access to convenient and reliable clean transportation,” she said.

Expanding the U.S. charging network is widely seen as critical for building consumer confidence in and sales of EVs. The DOT estimates more than 4 million electric cars, SUVs and pickup trucks are on the road in the U.S., while the number of charging points has grown 70% since Biden took office. Private investments in the EV and charger supply chain have grown by more than $155 billion, according to administration figures.

The DOT has yet to announce when it will open applications for the next round of CFI funding.

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NERC Urges Preparedness Ahead of Weekend Storms

NERC is urging electric stakeholders to take preparations ahead of a winter storm system that the National Weather Service expects to “hammer much of the eastern half of the” U.S. this weekend and next week. 

In a statement earlier this week, the ERO said the coming weather “has the potential to create significant challenges, especially in major metropolitan areas.” Predictions by the NWS include blizzard conditions with 6-12 inches of snow from eastern Nebraska to central Michigan, and potentially more than a foot of snow in northern lower Michigan.  

Much of Montana and North Dakota is expected to see temperatures fall below zero degrees Fahrenheit Jan. 12, with single-digit temperatures likely in the Central Plains, Iowa and Minnesota. These conditions will likely persist “well beyond the end of the week,” the NWS said. 

Additionally, high winds are expected in the Deep South and Southeast U.S. with the possibility of tornadoes. While rainfall totals are expected to be relatively light compared to earlier this week, parts of the Mid-Atlantic and Northeast, already saturated by heavy rain, may experience floods. NWS is also forecasting “unsettled weather conditions” in the West, with the Oregon Cascades, along with the coasts of Oregon and northwestern California, predicted to receive several feet of snow. 

In a video posted Tuesday, NERC CEO Jim Robb said that “while forecasts do not indicate that this polar air mass will dip as far south as it did during Winter Storm Uri in 2021, the concerning pattern shows a much colder and broader area of impact.” He asked industry to “take this upcoming weather system extremely seriously and be prepared for extreme temperatures and wind chills.” 

NERC said stakeholders will need to pay “prudent attention throughout the long holiday weekend” to winterization and fuel supplies. The ERO encouraged generator owners and operators, reliability coordinators, balancing authorities, transmission operators and fuel suppliers to evaluate energy adequacy, and load-serving entities to “review their demand projections to ensure the highest levels of reliability.” 

NERC’s release mentioned the ERO’s “comprehensive approach” to preparing for and mitigating the impacts of severe weather events, including the new cold weather standards EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations) approved by FERC last February. (See FERC Orders New Reliability Standards in Response to Uri.) 

Work on additional cold weather standards continues at NERC: The organization’s Board of Trustees voted in October to send EOP-011-4 and TOP-002-5 (Operations planning) to FERC for approval. NERC’s board also warned last month that it is prepared to unilaterally approve the proposed standard EOP-012-2 — which FERC ordered the ERO to submit for approval by February 2024 — if it fails its next ballot round this month. (See NERC Board May Force Action on Cold Weather Standard.) 

NERC warned in its 2023 Winter Reliability Assessment that much of North America faces elevated or high risk of energy shortfalls during extreme weather conditions this winter. A common theme in multiple regions was that generation has not kept pace with demand growth, with the added concern in New England that using natural gas for both home heating and electric generation could place unsustainable burdens on the gas delivery infrastructure. (See NERC: Grid Risks Widespread in Winter Months.) 

This week’s statement also mentioned NERC’s 2023 Long-Term Reliability Assessment, which advised that “integrated planning and effective coordination [are] imperative” in light of the growing interdependence between North America’s gas infrastructure and electric grid and the risks posed to both systems by extreme cold temperatures. 

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Stakeholders Ask MISO to Share New Order 2222 Go-live Date ASAP

MISO stakeholders this week pushed MISO to publish sooner rather than later a new deadline for accepting aggregators of distributed resources into its markets.

MISO hopes to file for a new implementation date and clear up other aspects of its Order 2222 compliance with FERC by May 10. While the RTO plans to discuss several aspects of its revamped compliance multiple times between now and early spring, it plans to devote only one final April 11 meeting of its DER Task Force to discussing the new target date. After that, it will present a final, reworked Order 2222 compliance proposal to the MISO Market Subcommittee at its April 18 meeting.

In October, FERC told MISO it had to achieve a more timely Order 2222 compliance, striking down the RTO’s originally proposed plan to accept aggregators’ offers beginning in the first quarter of 2030. (See FERC: MISO’s 2030 Finish Date on Order 2222 Compliance not Soon Enough.)

Clean Grid Alliance’s Rhonda Peters asked MISO not to wait to hold discussions on its new implementation until spring.

“The implementation date is a topic of great importance to many stakeholders,” she said during a Jan. 11 teleconference of MISO’s DER Task Force.

MISO’s Marc Keyser said landing on a new implementation date will be relatively “straightforward” when compared to the other outstanding Order 2222 compliance directives FERC ordered MISO to resolve.

“Multinodal aggregations are a pretty complex topic…we think we’ll need multiple discussions there,” Keyser said.

However, Sierra Club’s Justin Vickers said the implementation date is a “big deal.”

“I think not being able to talk about that until the very end will affect how we will discuss other issues,” he said, adding it would be “prudent” for MISO to share its revised go-live date with stakeholders expeditiously.

Organization of MISO States Executive Director Marcus Hawkins said MISO’s 2030 finish date was revealed belatedly in its first round of compliance work, which led OMS to reassess MISO’s compliance plan. OMS last year filed comments with FERC that a 2030 implementation date was too gradual.

Advanced Energy Management Alliance’s DeWayne Todd asked MISO to consider a staged implementation to the order, where it works in DER aggregators’ participation as it’s able.

Otherwise with the Order 2222 compliance edits, MISO is reaching out to its stakeholders for advice on how it should best coordinate with regulators, distribution companies and aggregators to solve FERC’s directive to establish cybersecurity and customer data privacy protections for meter data management.

The RTO also is seeking stakeholder reactions on how it should set up dispute resolution when disagreements arise between aggregators, LSEs, distribution companies and/or regulators over meter data or settlements. MISO is proposing that it become involved and review an aggregator’s participation in its markets when its settlements are successfully disputed more than 10% of the time by an LSE and the financial impacts of successful disputes exceed $7,500 for an individual dispute or average at least $100,000 across all successful disputes.

MISO will hold two workshops with distribution companies on Order 2222 compliance: a Jan. 22 teleconference to discuss a 60-day timeline and process for reliability reviews to monitor DER aggregations’ impact on the distribution system and a Feb. 27 teleconference to hash out operational coordination.

MISO also plans to discuss how it might handle DER aggregations across multiple pricing nodes at DER Task Force meetings beginning in February.

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DOE Seeks Proposals to Build out HALEU Supply Chain

The U.S. Department of Energy is putting $500 million from the Inflation Reduction Act into the buildout of a domestic supply chain for the high-assay, low-enriched uranium (HALEU) needed to deploy and power advanced nuclear reactors, according to a request for proposals released Jan. 9. 

HALEU is uranium that is enriched 5 to 20% with U-235, the isotope needed to sustain a chain reaction that can produce energy, versus low-enriched uranium (LEU) that is enriched only up to 5% and is used in the existing light-water reactors in the U.S. The higher enrichment levels allow for reactors with “smaller and more versatile designs with the highest standards of safety, security and nonproliferation,” according to the RFP announcement. 

The RFP is the second of two focusing on the key processes involved in HALEU production: mining, milling, enrichment and deconversion, which is the process of converting enriched uranium into usable fuel. The previous RFP, issued in November, will provide funding for deconversion facilities, while the current request will offer contracts for enrichment, which will include mining and milling. 

Focusing on the domestic enrichment part of the process, DOE will award one or more contracts that will run for at least 10 years, with a minimum order valued at $2 million. While the RFP says that mining and milling activities may occur in North America at large or in “allied or partner” nations, actual enrichment and storage of the HALEU must be located in the U.S. 

Also, the RFP specifically notes that any HALEU produced under these DOE contracts must not “negatively impact the existing baseline uranium production capacity currently supplying the U.S. domestic nuclear industry.” 

Proposals are due March 8. 

“Nuclear energy currently provides almost half of the nation’s carbon-free power, and it will continue to play a significant part in transitioning to a clean energy future,” Energy Secretary Jennifer Granholm said in the RFP announcement. “A robust HALEU supply chain” will strengthen “our national and energy security.” 

At present, the only commercial source of HALEU is a state-owned company in Russia, and lack of a domestic supply threatens DOE’s Advanced Reactor Demonstration Program, which is supporting the development of two advanced reactors with $2.5 billion in funding from the Infrastructure Investment and Jobs Act. 

Both projects will need HALEU, and the lack of a domestic supply has already been cited as potentially causing a two-year delay in the completion of one, the Natrium reactor being developed by the Bill Gates-founded TerraPower. 

A DOE-funded demonstration project in Ohio began producing small amounts of HALEU in October, but the department estimates that the U.S. could need up to 40 metric tons by 2030, with more than that required each subsequent year. 

The RFP is one more piece of the U.S. commitment to reviving the domestic nuclear industry and ending its dependence on Russian uranium in the wake of the war in Ukraine. At the 28th Climate Change Conference of the Parties (COP28) in December, the U.S. and more than 20 other countries pledged to triple nuclear power around the world by 2050. 

In a second COP28 announcement, the U.S. joined Canada, France, Japan and the U.K. in plans to mobilize $4.2 billion in public and private funds over the next three years “to establish a resilient global uranium supply market free from Russian influence and the potential to be subject to political leverage by other countries.” 

The announcement also encouraged “nuclear electricity generating utilities or direct nuclear energy industrial end-users of like-minded nations to develop [a] long-term supply strategy that signals and provides confidence to the industry to make the relevant investment to increase their capacity.” 

Building Confidence

However, building private sector confidence in the emerging HALEU market may take more than DOE’s initial $500 million commitment, according to a recent analysis from the nonprofit Nuclear Innovation Alliance (NIA). 

A successful buildout may require between $1.5 billion and $2.9 billion, said co-author Patrick White, NIA’s research director. 

“The $500 million is a really, really good down payment,” he said. “But if you want to create a market signal [that] the federal government could support or help ensure that there’d be sufficient demand — let’s say 10 metric tons per year for a period of 10 years … that’s where you start getting appropriation needs on the order of a couple of billion dollars.” 

One key to establishing a domestic supply chain while driving down costs might be leveraging existing, commercially produced LEU as feedstock for HALEU. “Use of lower-cost LEU enrichment services as part of the HALEU production process significantly reduces the overall cost of HALEU,” the report says. 

White argues that using LEU as HALEU feedstock could be done without affecting the fuel supply for the existing U.S. nuclear fleet, especially if mined and milled uranium can be obtained from other North American or partner nations, as allowed in the RFP. 

He also said that smart program structuring could “both protect the taxpayer and lower the total amount of money [needed] upfront.” A revolving fund, for example, could allow the government to “purchase HALEU and use that as kind of a guaranteed market signal and then sell [it] back to companies that are going to need it,” he said. That revenue could then be used to purchase more HALEU. 

White sees the RFP providing DOE with a flexible framework “so they can work with different companies out there to determine what’s going to be the best pathway forward to really kind of get new … capacity brought online.” 

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Newsom Budget Would Trim Calif. Climate Spending

California Gov. Gavin Newsom (D) on Jan. 10 proposed a fiscal 2024/25 budget that further shrinks the $54 billion California Climate Commitment to $48.3 billion, while spreading the climate spending over seven years rather than five.

At the same time, the state’s climate efforts will be bolstered by $10 billion of federal funding, Newsom said during a press conference. “That’s helped supplement some of the modest cuts we’re making in this space,” he said.

The proposed budget would maintain about $6.6 billion of the $7.9 billion of energy investments included in the state’s 2022 budget act. That money is intended to fund critical grid reliability projects and speed the state’s transition to clean energy.

The governor’s release of a proposed budget in January is just the first step in the budget process. The governor and legislature will spend several months haggling over the budget before it is finalized.

Newsom’s budget proposes $291.5 billion in spending, including about $208.7 billion from the state’s general fund. It grapples with an expected shortfall of $37.9 billion, following a $31.7 billion shortfall for fiscal 2023/24.

The governor attributed the deficits to wide swings in state tax revenue from capital gains. Before the recent budget shortfalls, the state had two years of surpluses totaling about $176 billion. Now, he said, the state is “going back to what we have traditionally seen … after a period of unprecedented distortion.”

Another issue, Newsom said, is that last year’s extension of tax-filing deadlines to November, because of severe winter storms, masked the full extent of the state’s revenue decrease. “Now that the receipts are in, we must bring our books back into balance,” Newsom said in a budget message. Newsom’s projection of a $37.9 billion deficit differs from the state Legislative Analyst’s Office prediction last month of a $68 billion deficit.

The California Climate Commitment received $54 billion in funding through the budget acts of 2021 and 2022. But the 2023/24 state budget cut the investment to $51 billion, while sparing $10 billion for electric vehicle infrastructure and incentives. (See Newsom Expresses ‘Sense of Urgency’ on Energy Buildout.)

The fiscal 2024/25 proposal maintains the $10 billion for EV programs but spreads it out over seven years rather than five.

The budget proposal includes $2.9 billion in cuts to climate programs and $1.9 billion in spending shifted to future years. An additional $1.8 billion in spending will be shifted from the general fund to other funds, mainly the greenhouse gas reduction fund (GGRF), which is money from the state’s cap-and-trade program.

As a result, some programs set to receive GGRF money will see a delay in funding. That includes $45 million earmarked for equity programs such as the Clean Cars 4 All electric vehicle incentive and $120 million for ZEV fueling infrastructure grants.

The governor’s budget proposes cuts to some programs, such as a $40 million reduction to the Carbon Removal Innovation program at the California Energy Commission. That would leave $35 million for the program. Similarly, $22 million would be cut from the CEC’s Industrial Decarbonization Program, leaving $68 million.

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SERC, Duke Agree to $40K Penalty for Reliability Violations

Duke Energy will pay $40,000 to SERC Reliability for violations of NERC reliability standards at multiple renewable energy generators, according to two agreements reached between the utility and the regional entity last year.

NERC submitted the settlements to FERC on Nov. 30 in its final spreadsheet Notice of Penalty of 2023 (NP24-3). On Dec. 29, the commission said in a filing that it would not further review the agreements, leaving the penalties intact.

SERC sorted the Duke settlements into two overall violations, each carrying a $20,000 penalty. The first involved infringements of MOD-032-1 (Data for power system modeling and analysis) at eight Duke facilities:

    • Conetoe II Solar in North Carolina;
    • Cimarron Windpower II and Ironwood Windpower in Kansas;
    • Frontier Windpower I and II in Oklahoma;
    • North Allegheny Wind in Pennsylvania;
    • North Rosamond Solar in California; and
    • Top of the World Windpower in Wyoming.

Because the issues span the footprints of multiple regional entities, SERC will split the penalty with the Midwest Reliability Organization, ReliabilityFirst and WECC based on net energy load.

According to the settlement, Duke discovered while gathering evidence for an upcoming audit that the facilities in question had not submitted modeling data to their transmission planners and planning coordinators in some of the previous years, as required by the standard. Most of the facilities were missing their steady-state, dynamics and short-circuit data; Frontier 2 was missing only its dynamics data, SERC said.

After learning of the failure to submit the data, Duke conducted an extent-of-condition review across its other business areas. (The initial discoveries were all in the Duke Energy Renewables division.) No other MOD-032-1 infringements were discovered.

SERC and the other regions classified the violations as a minimal risk to grid reliability, noting that failing to submit required data “could have resulted in inaccurate data being used in planning models and studies” but adding that in nearly all cases, there were no changes in the relevant data during the period of noncompliance. The facilities’ mitigating activities included submitting the missing data; defining the roles and responsibilities of all those involved in producing and submitting MOD-032-1 data; and implementing a tool to track upcoming modeling requirements.

The second Duke settlement involved violations of MOD-025-2 (Verification and data reporting of generator real and reactive power capability and synchronous condenser reactive power capability). Conetoe II Solar also was involved in these infringements, along with the Los Vientos and Notrees wind facilities in Texas; SERC will split the fines with the Texas Reliability Entity.

Once again, Duke discovered the MOD-025-2 violations while gathering evidence for an upcoming audit. The facilities had failed to submit information when they performed their five-year staged verification of real and reactive power capabilities in 2021.

The REs determined that the root cause of the infringement was “an inadequate fleetwide compliance management approach to MOD-025-2.” According to the settlement, the staff responsible for overseeing compliance activities lacked training, and the utility’s MOD-025-2 procedure lacked clearly defined roles and responsibilities for all groups involved in producing and submitting the data.

Mitigating activities by the facilities included defining the responsibilities involved in the MOD-025-2 procedure and implementing an organizational approach for model data evidence that defines how the evidence is to be structured and named. The company also trained the impacted groups on updates to the procedure “to ensure new processes are understood and implemented.”