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September 6, 2024

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NY Starts Public Review of Cap-and-invest Plans

New York agencies on Thursday kicked off the first in a series of public webinars dedicated to explaining and seeking comment on the state’s proposed emissions-reduction and reporting policy, the cap-and-invest program.

The economywide program is a centerpiece of New York’s clean energy transition and, as proposed, would use money from the auctions of emission allowances to both offset consumer costs associated with the transition and fund clean energy projects needed to achieve the goals set out in the state’s Climate Leadership and Community Protection Act (CLCPA). (See “Cap and Invest,” NY State Reliability Council Executive Committee Briefs: May 12, 2023.)

Hosted by the Department of Environmental Conservation (DEC) and New York State Energy Research and Development Authority (NYSERDA), the meeting covered the current proposed structure of the program, solicited initial public questions, and shared the rulemaking or regulatory considerations on which the agencies want feedback.

The program’s rules and regulations will be written by the DEC in consultation with NYSERDA, which will be responsible for dispersing money collected from auctions to relevant clean economy projects. Roughly a third of those funds will be prioritized for disadvantaged communities to help offset rising energy costs. (See NY Climate Justice Panel Sets Disadvantaged Community Criteria.)

The agencies sought feedback on multiple aspects of the proposal, including the program design, emissions benchmark reporting, compliance verification metrics, applicability of regulations on certain industrial sectors and what other rules should be considered.

The DEC and NYSERDA also want input on how the program’s auctions should be designed and how auction allowances should be allocated to obligated or nonobligated sources.

They also seek comment on what is the applicable threshold to set emissions or operations caps; which industries or other stationary sources, such as large buildings, should report their emissions; and what enforcement mechanisms should be used to track emissions reporting or verification.

Another consideration is how different industries — such as the waste, energy-intensive trade-exposed (EITE) and electricity sectors — should be treated in the program and how the Regional Greenhouse Gas Initiative (RGGI) would fit into New York’s program.

Staff also asked the public to recommend any provisions from existing cap-and-invest programs, such as the one used in Washington state, that could benefit New York’s proposal. (See Wash. Looks to Sell 11M Allowances in 2nd Cap-and-Trade Auction.)

Public feedback can be submitted online or via mail to the DEC’s Bureau of Air Quality Planning at any time, but staff asked that comments or questions relevant to the first webinar be sent by July 1.

Public Questions

The public posed many questions during the webinar.

One attendee asked whether there will be an offsetting criterion as part of the proposal, to which the DEC’s Jonathan Binder responded, “We’re not intending [to have] offsets be a part of this program.”

Another inquired about the difference between obligated and nonobligated entities.

The DEC’s Ona Papageorgiou said, “Obligated entities would be required to purchase or obtain allowances for their emissions, whereas the state will retire allowances for nonobligated entities.”

Papageorgiou also answered a question about whether there was a “floor” to any of the program’s thresholds, saying the agencies are “seeking feedback on thresholds for reporting and compliance.”

Vlad Gutman-Britten of NYSERDA responded to a question about whether allowance trading would be allowed.

“We haven’t made that determination yet, and we are seeking input on whether and to what degree trading should be allowed,” he said.

Another attendee asked if emissions allowances would be strictly for carbon dioxide or the equivalent.

Nathan Putnam of the DEC answered, “These are carbon dioxide equivalent emissions, so the program is going to cover all greenhouse gases in the state of New York, or anything relevant to the CLCPA.”

In an email to NetZero Insider, the DEC said the webinar series “will provide an overview of New York’s potential program and similar programs in other states and jurisdictions designed to reduce greenhouse gas emissions.

“All stakeholder input will be considered as part of program development to ensure the proposed program achieves the core principles of affordability, climate leadership, creating jobs and preserving competitiveness, investing in disadvantaged communities, and funding a sustainable future.”

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Clean Energy Escapes Texas Legislature’s Wrath

With the 88th Texas Legislature’s regular session in the history books Monday, and a 30-day special session already underway, the state’s clean energy industry can breathe a little easier again.

“Members, I hope you enjoyed your summer. I sure did,” House Speaker Dave Phelan (R) said as he gaveled his chamber back to business Tuesday.

The consensus is that the industry, which an Austin-based research firm says reduced wholesale electricity costs in the state by almost $28 billion from 2010 to 2022, fared better than recent gloomy predictions. (See Uncertain Future for Texas’ Renewables Industry.)

“It could have been very, very bad,” Stoic Energy principal Doug Lewin, a close observer of the Legislature, told RTO Insider. “The threats were serious and real, and it’s still not great … the worst stuff, the permitting, the cost allocation … that didn’t pass.”

“While more than a dozen anti-renewable energy bills were filed this session, only a few ended up making it through the process,” said Luke Metzger, executive director of Environment Texas. “Some of the measures that would have been most harmful to renewables … thankfully died.”

For that, Metzger and others can thank a broad coalition of environmentalists, industry organizations and business groups, along with House representatives beholden to their constituents, for preventing the renewable energy sector from being kneecapped.

After the Senate tacked on language from bills that had yet to make it out of committee as amendments to the must-pass bill reauthorizing the Public Utility Commission (House Bill 1500), the interest groups worked last weekend with legislators to again eliminate or water down the more onerous language.

Out went language from Senate Bill 624 that would have required wind and solar facilities to acquire special permits from the PUC, a requirement thermal generators wouldn’t face. A firming mandate that would have required renewables to pay for other energy sources when wind and solar aren’t producing was pushed back to the end of 2027 and its cost increases tied to generation portfolios, rather than individual units.

“Over at the Legislature, those people are accountable to consumers and voters. They just can’t ignore what consumers want,” said attorney Katie Coleman, who represents Texas Industrial Energy Consumers.

“I think the language that ended up in 1500 is heading in the direction of trying to have some reliability for renewables in their output, but it’s not as punitive as some of the other proposals,” Lewin said. “I think there’s a lot of what they’re calling firming going on in the market anyway. So, kind of pushing that along, but I don’t think it is going to really be that detrimental to the industry.”

Rather than make renewables pay higher ancillary services fees, HB1500 instead requires that a study first be conducted. It would also end Texas’ renewable energy requirement, or portfolio standard. However, the state met that requirement years ago.

HB1500 also adds a $1 billion annual net cap to the performance credit mechanism (PCM), which since PUC Chair Peter Lake pushed it through in January has been criticized by almost everyone connected to the market — except the large generators that would benefit from it. Various studies have pegged the PCM’s cost at between $5 billion and $12.7 billion a year, which ERCOT has said would flow down to consumers. (See Texas PUC Submits Reliability Plan to Legislature.)

Lake said the commission would wait to see what direction the Legislature offered before pursuing the PCM’s implementation. The PUC got that direction with HB1500, which requires ERCOT to complete an updated assessment of the reliability program and submit a report on its costs and benefits to the commission and Legislature.

The bill also includes 14 requirements to be met before the PCM can be implemented, including one that mandates that ERCOT add real-time co-optimization and ancillary services to the market before implementing the PCM. That would push the latter back to 2025 or 2026.

Other HB1500 requirements related to the PCM include:

  • Central procurement of performance credits to prevent market manipulation by affiliated generation and retail companies;
  • Not assigning costs, credit or collateral for the program such that it provides a cost advantage to load-serving entities that own, or whose affiliates own, generation facilities;
  • Establishing a penalty structure providing a net benefit to load for generators that bid into the PCM’s forward market but do not meet the full obligation;
  • Not allowing generators to receive credits that exceed the amount of their bid into the forward market;
  • Removing the bridge solution by the end of the PCM’s first year; and
  • Setting a single ERCOT-wide clearing price that does not differentiate payments or credit values based on locational constraints.

“There really hasn’t been a lot of support for [the PCM] from any group other than actual existing generators and leadership with the PUC and ERCOT,” Coleman said. “We all want more reliability. Always. I think the Legislature wanted to put some pretty strict parameters around the limits of it. That was something that we worked really hard to get done, along with a pretty broad range of groups.”

Hard Sell

Where this leaves the PCM is anyone’s guess.

During a virtual press conference Wednesday, ERCOT CEO Pablo Vegas said the grid operator’s staff are reviewing legislation that passed and analyzing its impact on the grid. He promised to share more details publicly, “like we often do in our in our open board meetings,” once staff understand the bills better.

“We’re not at a place where we’re ready to discuss that in any detail right now,” he said. “But I can tell you that we share the same goal that the Legislature does, which is to continue to support a reliable and stable grid now and long-term into the future. We’ll continue to work closely, too, with the Legislature to enact what they passed this session.”

The ERCOT Board of Directors next meets June 19-20.

“I think it’s going to be a hard sell to come back and say, ‘Hey, we’ve done this analysis and now the PCM is going to cost $2 billion or $3 billion or $4 billion.’ That’s going to be hard, hard argument to make,” Coleman said.

The Legislature also sent SB2627 to Gov. Greg Abbott’s desk. The bill provides $5 billion to $10 billion in government low-interest loans and completion bonuses to builders of new gas plants. However, SB6, which would have ordered the construction of 10 GW of gas-fired generation at a cost of $10 billion to $18 billion, didn’t make it. Texans will get a chance to pass judgment on SB2627 when they vote on it as a constitutional amendment.

Todd Hunter Charles Schwertner (Sen Charles Schwertner via Twitter) FI.jpgTexas Rep. Todd Hunter and Sen. Charles Schwertner celebrate the passage of House Bill 5. | Sen. Charles Schwertner via Twit

Another bill, HB5, a corporate incentive program to boost infrastructure investment, excludes wind and solar development from tax abatements.

“The landmark legislation package passed this evening will ensure our economic miracle continues into the mid-21st century and beyond,” Lt. Gov. Dan Patrick, who controls the Senate, said in a statement after the bills’ passage.

Lewin points out that very little of the legislation addresses the root causes of ERCOT’s capacity shortfalls during the two most recent storms of 2021 and 2022: the failure of gas supplies to show up in frigid temperatures.

He said a friend asked him after the regular session ended whether the Legislature’s actions meant the grid is fixed.

“No. Not even close,” Lewin said he responded.

“One of the points I’m trying to make leaving this session is that if you don’t focus on the root cause, if all the focus is on renewables, you’re causing problems, which is really where the focus was,” he said. “There was very little focus on the actual problems facing the grid. We’re just going to continue to have a grid that is problematic and leaves us all kind of white-knuckling it through the through the next winter storm.”

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Bill Would Require NV Energy to Examine Market Reliance

A bill to strengthen the integrated resource planning process for Nevada’s electric utilities and require them to look for ways to increase their energy independence has emerged late in the state legislature’s session.

Assemblyman Howard Watts (D) introduced Assembly Bill 524 on May 26, less than two weeks before the 2023 session ends on June 5. The bill was granted a waiver from the usual legislative deadlines.

Watts said the bill is the result of months of discussions with stakeholders who voiced concerns about energy reliability and rising costs to consumers. The bill lines up with Gov. Joe Lombardo’s March executive order calling for the state’s “advancement of energy independence.” (See New Governor Seeks Shift in Nevada Energy Policy.)

One of the key topics of discussion, Watts said, was the concept of the state’s “open position” when it comes to energy supply.

“We have an open position: a level of exposure to the energy market,” Watts said. “By reducing that, we can make sure that we can provide a reliable electricity supply and reduce our exposure to those extremely high energy market costs.”

Watts’ comments came Tuesday during a joint meeting of the Senate and Assembly committees on Growth and Infrastructure. The committees held a hearing on the bill but took no action.

Watts said he has also heard concerns about the integrated resource planning process for electric utilities and the number of amendments filed by NV Energy.

“Amendments have been coming very frequently … some of the projects in amendments are extremely large, and they don’t have the full timeline and the full analysis of the integrated resource plan itself,” Watts said.

Since approval of its 2021 integrated resource plan (IRP), NV Energy has filed four amendments to the plan. The fourth included a proposal for a 400 MW gas-fired peaker plant that NV Energy said was needed to maintain reliability in the face of extreme weather and variable resources. The Public Utilities Commission of Nevada (PUCN) approved the Silverhawk peaker in March on an expedited timeline intended to get the new plant running by 2024. (See Nev. Regulators OK Controversial Gas-fired Peaker.)

Under current law, electric utilities in Nevada must file an IRP every three years. AB 524 would change the requirement to every three years or “more often if necessary.” The bill would direct the PUCN to develop requirements regarding the filing of amendments to an approved IRP.

Currently, an IRP must include scenarios showing how different sets of resources could meet projected energy demand. AB 524 would require the utility to evaluate a scenario “that provides for the construction or acquisition of energy resources through contract or ownership to be placed into service to close an open position utilizing dedicated energy resources in this state and dedicated energy resources delivered through firm transmission.”

The bill doesn’t say that the scenario designed to close an open position must be the one the utility moves forward with. Watts said the wording in the bill, which doesn’t dictate a particular outcome, was a compromise.

‘Dire State’

NV Energy opposes the bill, saying it doesn’t go far enough.

Tony Sanchez, NV Energy’s executive vice president of business development and external relations, called for a strong policy statement from the legislature “indicating that the open position that we currently have … needs to be closed and closed quickly,”

“Because the West is in a dire state of energy emergency,” Sanchez said.

Janet Wells, NV Energy’s vice president of regulatory affairs, called the utility’s reliance on the open market “both risky and costly.”

Wells said that while NV Energy can generate power for about $50/MWh, it paid more than $150/MWh on average in the open market in summer 2021 and even more in 2022. About 30% of the utility’s summer energy comes from the open market, Sanchez said.

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ERCOT Monitor Recommends New Market Design in Report

The ERCOT Independent Market Monitor’s annual market report on the Texas grid released Wednesday recommends resurrecting a multi-interval, real-time design similar to those used in other markets and re-evaluating and prioritizing it for future implementation.

The Monitor notes that real-time markets rely primarily on online and quick-start resources. It says a real-time market efficiently dispatches online resources and sets nodal prices that reflect energy’s marginal value of energy at every location, but that ERCOT lacks the software and processes to facilitate efficient commitment and decommitment of peaking resources that can start within 30 minutes.

“This is a concern because suboptimal dispatch of these resources raises the overall costs of satisfying the system’s needs, can distort the real-time energy prices and affects reliability,” the Monitor says in its 2022 State of the Market report. “For these reasons, other markets have implemented this type of look-ahead process to optimize short-term commitments of peaking resources.”

The Monitor says the value of access to and optimally using fast-starting dispatchable resources will only grow as do ERCOT’s more intermittent wind and solar resources. A multi-interval dispatch model can meet these increasing ramp requirements by recognizing system needs further into the future and beginning to move dispatchable resources to optimally satisfy, it says.

ERCOT evaluated the model’s potential benefits in 2017 but decided not to move forward because the costs were greater than the projected benefits, according to the IMM. “Much has changed since” then, it says, pointing to a higher level of renewable resources available to the grid operator.

“We believe benefits will be much higher in the future, and this capability will become essential for managing the growing renewable fleet,” the Monitor says.

The proposal is one of five new recommendations added to eight holdovers. Other new suggestions include:

  • instituting a 100% claw-back of excess market revenues for reliability unit commitments, as the incentives for self-committing resources have changed “dramatically” with the increased frequency of RUC instructions under ERCOT’s more conservative operations posture;
  • allowing transmission reconfigurations for economic benefits, instead of just for reliability;
  • changing the linear ramp period for emergency response service summer deployments to three, down from the current 4.5-hour parameter that artificially inflates the reliability deployment price adder; and
  • modifying the lookback period for operating reserve demand curve mean and standard deviation calculations to a rolling five-year period, which would have saved more than $160 million last year.

The IMM also says real-time co-optimization (RTC), which was postponed after the February 2021 winter storm, should be prioritized, “given its promise to improve pricing during supply shortages” and to better use the existing generation fleet. The grid operator is expected to restart the RTC project this summer, with a new potential go-live of 2026.

The market report finds ERCOT’s markets performed “competitively” and “little evidence” that suppliers exercised market power, with one exception: It says the nonspinning reserve market became less competitive as higher procurements caused large suppliers “to frequently be pivotal,” raising the reserve product’s costs from $385 million to $480 million from August 2021 through December 2022.

ERCOT’s average load grew 9.5% from 2021 and average real-time prices fell to roughly $75/MWh in 2022, down more than 50% from 2021 ($167.88/MWh), almost entirely because of the February storm’s effects. Prices reflected a real-time energy value of $32.2 billion last year.

New Grid Notifications Added

ERCOT on Wednesday rolled out a new notification system it said will provide “clear and reliable” communications with the public and greater transparency on grid operations.

The Texas Advisory and Notification System (TXANS) provides another means for the public to follow ERCOT operations and grid conditions that do not indicate emergency conditions are expected. It introduces two new notifications before NERC-mandated energy emergency alerts (EEAs): an ERCOT weather watch and a voluntary conservation notice.

The weather watch will be issued when possible severe weather and high demand is forecasted in three to five days. It is intended to alert the public to plan ahead in reducing their energy use during higher-demand periods.

Pablo Vegas (ERCOT) Content.jpgERCOT CEO Pablo Vegas | ERCOT

“This earlier lookahead gives the public notification of possible higher demand due to forecasted conditions,” ERCOT CEO Pablo Vegas said during a virtual press conference. “We’re then asking Texans to keep an ear out for more information should conditions change.”

The voluntary conservation notice will be issued when higher demand and lower energy supply are forecast. It will ask Texans to voluntarily conserve power, if it’s safe to do so. ERCOT will also request that local government agencies implement programs that reduce energy use at their facilities.

TXANS notifications will not replace EEA notices.

“All of the new notices that we are releasing at this point … are times when the grid is in stable and normal conditions and that they’re not in an emergency,” Vegas said. “We want to just help people be aware and informed on what’s going on. We want to be more transparent; we want to be more open and get people more comfortable with hearing from us under conditions that are not emergency conditions.”

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PJM Capacity Auction Weeks away with No Answer on Delay

PJM is weeks away from the scheduled date for the 2025/26 Base Residual Auction (BRA) without an order from FERC on whether it will be permitted to delay the auction (ER23-1609).

The RTO on April 11 asked FERC for permission to indefinitely postpone the auction, currently scheduled for June 14, to allow it to implement market rule changes now under stakeholder consideration through the Critical Issue Fast Path (CIFP) process. The following three auctions would also be delayed under the proposal, with the schedule returning to its normal three-year advance time frame for the 2029/30 BRA in May 2026.

Under Federal Power Act Section 205, if FERC does not issue an order within 60 days, the filing will go into effect by operation of law. That period ends on June 10, the date on which PJM asked that the changes go into effect. The RTO had said that if the commission does not approve the filing prior to June 10, it will proceed with the auction as scheduled.

PJM had requested expedited consideration with the hope of receiving an order by May 19, which the RTO said would allow it to provide market participants with advanced notice of any delay to the auction and allow them to focus their efforts on the CIFP process.

The filing did not include exact auction dates for the four delayed auctions to give PJM flexibility to incorporate any changes arising from the CIFP process, but it did include an illustrative timeline. Under that timeline, the 2025/26 BRA would be held in June 2024, and the following three auctions would be held every six months after.

Steve Lieberman, American Municipal Power’s vice president of transmission and regulatory affairs, said market participants are having to make decisions about their offers with little clarity about what the future of the auction holds, making it difficult to properly manage where they should focus their time and resources.

“I think we’re all in a tough place here, and it would be good to get some direction one way or another from FERC,” he said. “Nobody in our markets likes uncertainty.”

Comments submitted to the commission on the filing were split, with opponents arguing that a delay would disrupt state procurement auctions and undermine the goal of giving confidence to generation owners about their potential revenues. Opponents also said that the filing was based on speculation that the CIFP process will yield a proposal ultimately accepted by FERC. They argued that the proposal was overly broad by not including the specific dates to which PJM would delay the auctions.

“In theory and practice, it’s clear that shortening the lead time between the auction and the delivery year helps incumbent resources and muddies the market signal needed to incent new generation,” the Organization of PJM States Inc. protested.

Supporters argued that delaying the auction would allow the changes to the capacity market to be implemented with the aim of improving the accuracy of the price sent by the auction.

“While P3 has not traditionally supported delaying important [capacity] auctions, given the need to conduct future capacity market auctions under just and reasonable rules, P3 supports PJM’s filing as an unfortunate necessity,” the PJM Power Providers (P3) Group said in its comments. “The commission’s approval of the PJM filing will allow PJM to address the capacity market concerns and reliability issues in PJM so that auctions for the delivery years 2025/26 and beyond will appropriately send price signals to capacity resources to remain on, retire from or enter the market.”

PJM defended its filing by stating the impact of December 2022’s Winter Storm Elliott and reliability concerns found in its February “Energy Transition in PJM” white paper highlight the need to send price signals that will encourage the generation needed for resource adequacy through 2030.

“While PJM does not take any delay of the capacity auctions lightly, on balance, a limited delay of the upcoming [Reliability Pricing Model] auctions is necessary and appropriate at this time given the region’s recent experience with Winter Storm Elliott and the imminent reliability concerns identified in the Energy Transition ‘4R’ white paper,” PJM said in a May 10 reply comment. “This delay is necessary because sending the correct capacity market price signal is better than continuing to establish inaccurate price signals in an attempt to rush the auction and establish a clearing price for the capacity auction as early as possible.”

The Sierra Club and Citizens Utility Board commented that although they do not have an opinion, they believe the white paper had a flawed outlook on resource adequacy over the coming years. In an affidavit, economist James Wilson argued that it ignored the price signals that future capacity auctions would send as resources retire to construct new generation.

“The [white paper’s] model fails to account for the core feature of the PJM capacity market intended to anticipate and address future potential shortfalls: the capacity market price as determined by PJM’s sloping demand curve,” the comments state.

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ISO-NE Increases Peak Load Forecasts

HOLYOKE, Mass. — ISO-NE has upped its predictions for summer and winter peak loads over the next 10 years, staff told the NEPOOL Power Supply Planning Committee on Wednesday.

The updated forecasts are part of ISO-NE’s annual Capacity, Energy, Loads and Transmission (CELT) report, which projects electricity demand over the next 10 years. They are used by the RTO to help with transmission planning, determining resource adequacy requirements, evaluating the reliability and performance of the grid, and coordinating maintenance.

The most significant changes for this year’s projections related to updates in the methodology of forecasting electrification across the region, with major increases in the projected demand from electrified heating and transportation compared to the 2022 report.

The RTO boosted its projection for winter transportation demand for 2031 from 1,497 MW to 2,820 MW, while the summer projection increased from 1,082 to 1,927. The 2031 winter heating demand projection increased from 1,831 MW to 2,521 MW.

Projected increase in demand (ISO-NE) Content.jpgThe projected increase in demand from electrified heating and transportation. | ISO-NE

 

For the heating projection, this year’s report looked at electrification within the commercial building sector, which was not included in last year’s, based on extensive data from the National Renewable Energy Laboratory.

The transportation demand increase reflects the myriad new federal, state and local policies aimed at spurring the transition to electric vehicles. The figure was based on input from state regulatory agencies to assess the extent to which nonmandated electric vehicle targets will be met. The modeling assumes all state EV adoption mandates will be met.

The RTO also adjusted its projections to better account for the effect of cold weather on EVs.

“Energy and demand impacts of personal [light-duty vehicles] were revised to more dynamically incorporate the impacts of weather,” said Victoria Rojo, lead data scientist of load forecasting and system planning for ISO-NE.

Peak demand is calculated using historical weather data for the winter and summer weeks with the highest typical demand. The RTO calculates a gross load forecast — which does not account for the impacts of energy efficiency programs or behind-the-meter solar — as well as a net load forecast, which subtracts these factors from the gross load.

ISO-NE increased its winter gross peak demand for 2031 by about 7% compared to the previous report and increased its summer projection by about 2%. The winter net peak projection for 2031 is approximately 10% higher than the 2031 projection from the previous report, while the summer net peak projection is about 5% higher than that from the previous report.

ISO-NE now projects net summer peak demand to increase to 26,505 MW in 2031, compared to the 24,605 MW the RTO projects for this summer. For net winter peak demand, ISO-NE projects 25,133 MW in 2031, compared to 20,269 MW for this winter.

The data indicate that winter peak load will grow faster than summer peak load and that winter peak load could pass summer peak load in the coming years.

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Michigan County Approves Moratorium on Major Renewable Projects

Michigan’s Clinton County will impose a one-year moratorium on new, large-scale renewable energy projects to give it time to update its planning ordinance.

The moratorium, approved by the county commission Tuesday in a 6-1 vote, affects 11 townships that use the county’s planning ordinance. Five townships that have their own planning ordinances — including the larger townships of DeWitt and Bath — are unaffected, said county Commissioner Val Vail-Shirey. Also unaffected will be any proposals for individual renewable energy projects on homes or businesses.  

Vail-Shirey said she hoped a 19-member citizens advisory committee, created in the resolution approving the moratorium, would be able to complete work on changes to the county’s planning ordinance by the year’s end. The committee may hold its first meeting as soon as June 15.

The moratorium should not be viewed as an attempt to block large renewable projects but as a way to update the county’s ordinance to deal with issues regarding larger renewable projects, Vail-Shirey said in an interview.

Commission Chair Bob Showers also said he was not opposed to solar arrays but that the county, which is north of Lansing, needed more time to look at utility-level wind and solar projects, since more of them could be expected in future years.

There are no active projects under discussion now, though commissioners have said a company has indicated interest in a 1,000-acre solar project.

The moratorium will take effect once the county posts notice of the action. A Clinton County spokesperson said the notice should be posted this weekend.

Vail-Shirey said discussions on a moratorium arose after the county approved its last large renewable project earlier this year. That effort required many amendments, which led Vail-Shirey and others to decide a broader look at the planning ordinance was needed.

The 19-member committee will include representatives from all 11 townships relying on the county’s ordinance, as well as two county commission members and six citizen representatives. The only commissioner voting no on the moratorium, John Andrews, has said the committee should have equal numbers of renewable energy supporters and opponents.

Vail-Shirey said she intends to have discussions with Michigan’s utilities, academics, agricultural interests and businesses, as well as local citizens before the advisory committee makes any recommendations to alter the county planning ordinance.

Vail-Shirey said the committee will meet in public and that she hoped it would develop a draft proposal by September.

Before the commission voted on the proposal, a spokesperson for CMS Energy (NYSE: CMS) said the utility would work with the county but that the moratorium could be a detriment to discussions the utility is having with landowners on possible projects.  

Any changes made in the county’s planning ordinance should respect the rights of farmers who see solar as a “viable economic opportunity” along with continuing the county’s agricultural character, the company said.

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Robb Warns of ‘Serious Disruptions’ from Grid Transition

Testifying before the Senate Energy and Natural Resources Committee on Thursday, NERC CEO Jim Robb warned that operating the electric grid “ever closer to the edge” by relying on weather-dependent renewables will likely lead to “more frequent and more serious disruptions.”

Thursday’s hearing focused on the reliability and resiliency of electric service in North America, and attendees often pointed to NERC’s Long-Term Reliability Assessment, released last year, to illustrate their concerns.

The LTRA described most of the continent as at either high or elevated risk of energy shortfalls over the next decade, explicitly tying the shortages to the replacement of conventional generation with variable resources such as wind and solar power. (See NERC Warns of Ongoing Extreme Weather Risks.)

In light of the report, members took frequent potshots at the EPA’s recently proposed CO2 emission standards for power plants, which some industry groups have criticized for potentially accelerating the retirement of coal power plants without equally reliable replacements. (See Regan: New EPA Standards Designed to not Jeopardize Grid Reliability.)

Republicans, including ranking member John Barrasso (R-Wyo.), also decried what he called the Biden administration’s “reckless policies” that “are creating a reliability crisis.”

Chair Joe Manchin (D-W.Va.) attempted to draw Robb on the subject, asking him “how frustrating is it to you, being the head of NERC, knowing that you’re giving, basically, only the facts — you’re not picking winners or losers, you’re not getting involved in … the fight that goes on [over climate policy], basically just dealing with the facts of how you’re supposed to deliver the power, and no one pays attention?”

Robb’s reply was succinct: “It’s frustrating.”

Manchin brought up the SPUR Act, a bill introduced by Barrasso that would require NERC to comment on proposed EPA regulations and require the agency to “address NERC’s comments before [issuing] a final rule.” He framed the proposal as a way to force the EPA to account for the real-world impacts of its decisions.

“NERC and FERC [are] doing their job, but there’s no teeth to it whatsoever,” Manchin said. “Somehow you have to have reliability … be the first and foremost … to protect [people’s] livelihoods and lives.”

Robb’s fellow witness Manu Asthana, CEO of PJM, called the SPUR Act “a great idea,” adding that, “I think, actually, we can go further.” In his opening statement, Asthana agreed with Robb that the “rapid rate” of dispatchable generation retirement, with replacement renewable generation coming online more slowly than anticipated, has the potential to cause “increasing resource adequacy risk.”

King Says Transition Coming Late

Some committee members pushed back against the idea of slowing down the transition to renewable energy. Sen. Angus King (I-Maine) drew attention to the “irony and paradox” of witnesses and committee members calling the grid transformation “premature” and demanding the retention of conventional generation. Pointing out that the American Society of Civil Engineers attributes severe weather as the primary cause of customer outages, he argued that the reliability risks are as bad as they are because coal and natural gas generation was retained too long in the first place.

“We’re talking about outages that are caused predominantly by severe weather, which is a result of climate change,” King said. “So, the question is — [is the transition] premature? We should have been making this transition years ago, and we’re trying to make it in a hurry, because we are in a crisis situation.”

Robb acknowledged that the question of balancing the related harms of retaining carbon-emitting generation and moving to intermittent renewables is “a very tough policy problem,” but he stopped short of offering a solution, calling it a “question of balance that policymakers need to figure out.”

King pressed Robb for a timeframe in which older generation could be retired, but Robb would only say it should not be done until suitable replacements — such as renewable facilities with sufficient storage capacity to ride out significant grid disturbances — are available.

“The question is how fast can we develop the battery or the storage technology, whatever it is … versus the contribution to the severe weather events” of thermal generation, King said. “We’re talking [in] this hearing as if the only risk is lack of capacity, when in reality the risk is severe weather events.”

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Long-duration Energy Storage Seen as Key to Future Grid

Long-duration energy storage has emerged as key to enabling the continued growth of renewable energy. It also could help address the backlog of new transmission projects both in the U.S. and globally, say industry and Department of Energy experts. 

But there’s no consensus about the best way to store massive amounts of energy for more than a few hours or days, whether the technology is pumped storage, mechanical weights, compressed air or massive batteries. The 2030 DOE minimum storage target is at least 10 hours for utility-scale storage. (See DOE Targets 90% Cut in Cost of Long-duration Storage.)

“Given that there are so many different technologies that are being developed, it’s the government’s hope that we can try these out geographically as much as we can,” said Anna Siefken, a senior adviser in the Office of Technology Transitions at DOE, during a webinar with energy industry experts Wednesday presented by Madrid-based ATA Insights.

“We are not picking winners here. We’re trying to raise the floor, raise it so that everyone can participate in this market. But that does [require] off-takers. It takes people who are willing to go in on the risk, and the federal government is trying its best through any number of different programs to de-risk the technologies as much as possible,” she added.

Siefken also referred viewers to DOE’s Long Duration Energy Storage Report issued in March, one of a series of reports detailing the agency’s efforts to work with industry to commercialize clean energy technologies, particularly as an industrial strategy. (See DOE Reports Highlight 3 Technologies to Decarbonize U.S. Economy.)

“We’ve done clean hydrogen, advanced nuclear, carbon management and long duration energy storage, which is again why we’re here today.

“We were looking domestically at what are the barriers and challenges to commercialization of different technologies, and we wanted to create a credible fact base as well … [and] a language so that we can talk together about what we want to do, with long duration energy storage, in particular, for that report,” she said of the Liftoff Reports.

“We are pushing forward on clean energy technologies in a way that has not happened in the United States, ever. This is a moment in time. It’s very important. What we’re doing is trying to accelerate as many technologies forward as possible,” Siefken said.

Long Duration Storage Webinar (ATA Insights) Content.jpgClockwise from top left: Neva Espinoza, EPRI; Emily Fisher, Edison Electric Institute; Cristina Galan, ATA Insights; Julia Souder, Long Duration Storage Council; and Anna Siefken, DOE Office of Technology Transitions | ATA Insights

 

Julia Souder, CEO of the Long Duration Energy Storage Council, headquartered in Brussels, said backed-up transmission interconnection project queues have become a global crisis and developing effective and relatively inexpensive long-duration storage technologies could help while regulators work through the backlogs both in the U.S. and around the world.

Emily Fisher, general counsel for the Edison Electric Institute, agreed with Souder.

“One of the things that long-duration energy storage could do is defer some necessary investments in the transmission and distribution system. Not permanently, but they could create some flexibility in the transmission system that doesn’t currently exist. And that might help us get through some of our current backlog [while] trying to get more things interconnected to the grid, at least in the US,” she said.

The Storage Council was formed at COP26 “to initiate this $4 trillion marketplace and bring this diversity of thermal, mechanical, electrochemical and chemical technologies to the marketplace,” Souder said. “We have diverse technologies, and our membership spans over 20 countries and over 60 members. We’ve been growing because of … the diversity of long-duration storage, as well as the huge market opportunities.” She said the Storage Council has projected the world will need as much as 8 terawatts (8,000 GW) of long-duration energy storage by 2040.

Siefken said DOE favors working internationally on storage technologies.

“There are any number of challenges that we’ve identified domestically that are similar or have already been solved internationally. And there are a number of countries that have reached out to us directly that want to work on long-duration energy storage,” she said.

Neva Espinoza, vice president of energy supply and low carbon resources at the Electric Power Research Institute, said what’s important at this point is to encourage the development of many different storage technologies because those that are emerging are markedly different, varying from mechanical to chemical, from thermo to thermo-chemical.

“Each of those very specific technology options is unique from another in terms of the materials it uses, in terms of regional resources that may be required to best utilize that technology, in terms of how it integrates [with the grid].”

When asked by moderator Cristina Galan to explain what she meant by a “demonstration project,” Espinoza replied: “I’m specifically referring to building actual projects, integrating them into systems and operating them for relatively extended periods of time to really understand the true risk … and start the learning curve. And we need to learn from every single project as we build it.”

She added that such projects could be built on the former sites of fossil fuel power plants that already have the necessary grid connections, as well as a labor force.

Fisher, of the Edison Electric Institute, cautioned that the industry cannot know when any of the nascent technologies will become available, though she said she is convinced the engineering will be done and long-term storage will be developed.

“I believe that will happen in time. I think what we need to do is be preparing [for] the ecosystem issues that can tend to slow things down that have nothing to do with design,” she said.

“But I’m more worried about the dumb things that could get in the way, like regulatory regimes that weren’t built for [this] purpose and don’t really understand how to how to address long-duration energy storage.”

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WEIM Wins FERC OK for Resource Sufficiency Changes

FERC on Wednesday approved CAISO’s proposed changes to the Western Energy Imbalance Market’s resource sufficiency evaluation (RSE), including a provision to allow energy transfers to members who fail to meet resource obligations ahead of a trading interval (ER23-1534).

The package of changes was part of a second round of RSE-related tariff revisions, which were approved by the CAISO Board of Governors and WEIM Governing Body in December. (See CAISO, WEIM Boards Back Reliability Enhancements.)

The RSE test is designed to ensure that each WEIM participant enters a trading hour with enough capacity and ramping capability to cover its own needs and to prevent participants from “leaning” on the market to meet internal demand. A balancing authority area (BAA) that fails the test before an operating hour is prohibited from receiving WEIM transfers during that interval.

But meeting that requirement has become a challenge for some participants as the West faces a worsening shortage of generating resources and declining liquidity in the regional bilateral electricity market that typically helps provide short-term resource sufficiency — which stakeholders attribute to the expansion of the WEIM itself.

The RSE consists of four tests that measure feasibility, balancing, capacity and flexibility. The rule changes approved Wednesday relate to the capacity test, which determines whether a WEIM participant has provided sufficient incremental bid-in capacity to meet the imbalance among load, intertie and generation base schedules.

The first rule change will allow CAISO to establish a process by which participants that fail the RSE can obtain “energy assistance” transfers from within the WEIM. Any BAA that receives such assistance will be subject to a surcharge on top of the cleared price for energy assistance transfers.

“The EIM assistance energy transfer surcharge is an after-the-fact charge designed to provide an alternative incentive for WEIM balancing authority areas to meet their resource sufficiency obligations during tight supply conditions while making additional supply available to other balancing authorities in the WEIM,” FERC noted in its order.  

CAISO plans to align the surcharge with the level of its soft ($1,000/MWh) or hard ($2,000/MWh) energy bid caps, depending on system conditions. It says energy assistance transfers will be voluntary for both the provider and recipient.

In approving the tariff revision, FERC concluded that CAISO’s plan “provides increased flexibility to WEIM participants and can help WEIM balancing authority areas to meet their resource sufficiency obligations during tight supply conditions.

“We also find the proposal allows CAISO to optimally dispatch supply and provide access to resources that were not otherwise available,” it said.

The rule change had particularly strong backing from WEIM member NV Energy. The Nevada-based utility faces increasingly critical shortages of resources during summer and has been seeking a legislative remedy to address the issue. (See Bill Would Require NV Energy to Examine Market Reliance.)

In a December letter to the CAISO and WEIM boards, Lindsey Schlekeway, NV Energy’s market policy manager, noted that her company had asked the ISO to develop a mechanism to make excess supply available to a “distressed EIM entity at an appropriate scarcity price” and said “it is of critical importance not to delay the implementation of this reliability enhancement past the summer of 2023 for grid reliability.”

Asymmetry Addressed

CAISO’s second and third RSE rule revisions focus specifically on the ISO itself.

The second change will allow the grid operator to exclude from its own RSE calculation any real-time “lower priority” energy exports out of its BAA. Those exports are currently included in the calculation even though the ISO can freely curtail them to meet its own load obligations. At the same time, real-time WEIM transfers into the ISO are not factored into the RSE, representing an asymmetry in treatment of transfers, CAISO argued. Inclusion of curtailable exports has caused CAISO to fail RSE tests that it would have otherwise passed, the ISO said.

FERC said CAISO’s proposal “helps mitigate this asymmetry and will improve the ability of the resource sufficiency test to more accurately reflect actual system conditions during periods of potential resource insufficiency.”

The third rule change pertains to scheduling priority rules and E-Tag requirements for lower priority exports, with CAISO clarifying how it will interpret its scheduling priority tariff provisions to ensure that it can manually curtail lower priority exports in real-time to meet its own supply obligations.

“We find that these clarifications are consistent with CAISO’s existing authority to apply the scheduling priorities and help provide better transparency for market participants,” FERC wrote. “Further, we find that these clarifications could help operators identify lower priority exports and priority exports for scheduling and manual curtailment purposes.”