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November 18, 2024

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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.”

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NY Green Bank Surpasses $2B in Financing

The NY Green Bank said Wednesday its financial commitments have passed the $2 billion mark and are likely to accelerate with the influx of new federal funding for the clean energy transition.

The fund is the largest green bank in the U.S., both in dollar value and scope of portfolio. It is marking its 10th anniversary this year and, through the end of May, had assisted 123 projects that will either decrease fossil fuel consumption or increase in clean energy production.

NYGB President Andrew Kessler told NetZero Insider on Thursday that the recently added federal funding streams — the Inflation Reduction Act, the CHIPS and Science Act, and the Infrastructure Investment and Jobs Act — are complementary to the work of green banks. The result will be acceleration, not replication, he said.

The fund was formed in 2013 by then-Gov. Andrew Cuomo as a division of the New York State Energy Research and Development Authority. The New York Public Service Commission in late 2013 authorized NYSERDA to use $165.6 million in unallocated funds as seed money for the bank (13-M-0412).

News accounts quoted NYGB’s president at the time, Alfred Griffin, saying the seed money would leverage additional financing that would total $800 million and reduce carbon dioxide emissions by 575,000 tons per year.

NYGB became self-sufficient in July 2017, when revenues began to exceed expenses. In its most recent metrics, through the end of 2022, the fund reported up to $5.6 billion in cumulative capital commitments and calculated that those projects accounted for 439,000 metric tons of carbon dioxide emission reductions in calendar year 2022.

Kessler said NYGB is the largest of its kind for several reasons, not least the 40-person staff and support of Cuomo and his successor, Gov. Kathy Hochul.

But the bank’s value and success have stemmed from its mission as a problem-solver: arranging financing for nontraditional projects or concepts that have trouble qualifying through traditional funding streams.

“Our approach has always been flexibility,” he said. “We are in the gap-filling business.”

This provides a double benefit to New York’s climate change mitigation goals. First, the bank moves a project and its climate benefits closer to realization. Second, it sets a financing model that traditional lenders can follow with similar projects in the future.

“Our mission is to animate private-sector capital,” Kessler said, likening it to a test kitchen.

NYGB looks for a sweet spot in the middle: Projects that do not have a high risk of failure because of technological or financial challenges but are not so mainstream that they could secure capital through traditional funding streams.

The question NYGB asks itself, Kessler said, is: “If we did this transaction, will the guys across the street say, ‘We could have done this. That’s business we missed.’”

The answer to that question, ideally, is “yes.”

Not every project flies. The applications that NYGB rejects often are for projects that cannot deliver a minimum equity percentage or rely too heavily on unproven technology.

NYGB started out heavily focused on solar project financing, particularly community solar, which was an unfamiliar business model when it began expanding across New York. A significant portion of its portfolio is still solar, but building decarbonization, clean transportation and other sectors have gained funding as well.

More recently, the fund has offered financing that allows developers to use their interconnection deposit as equity during the lengthy interconnection process.

And in April, NYGB officially launched a $250 million community decarbonization fund dedicated to projects that will reduce greenhouse gas emissions in disadvantaged communities.

Individually, the 123 projects that NYGB has financed to date can be overshadowed by the major renewable energy generation and transmission projects being developed across the state, some with price tags ranging into the billions. But Kessler said that the many small projects will have a large impact collectively. Just as important, they will have an intangible impact individually, as New Yorkers see them in their communities. Any effective clean energy transition will rely to a significant degree on behavioral changes and buy-in from millions of state residents, and Kessler said everyday familiarity can raise awareness and prompt organic change.

“You can see the energy transition is happening,” Kessler said. “When people see that and take notice … obviously that’s super helpful from a knowledge perspective.”

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FERC Approves PG&E’s Proposal to Spin off Generation

FERC on Wednesday approved Pacific Gas and Electric’s transaction to spin off its non-nuclear generation to a new subsidiary called Pacific Generation (EC23-38).

The firm plans to sell off up to 49.9% of the generation subsidiary so it can raise capital more efficiently than through the sale of additional stock in parent company PG&E.

Pacific Generation will become a certificated, cost-of-service public utility regulated by the California Public Utilities Commission in the same franchise territory as PG&E after the deal closes, providing cost-based generation to customers and selling some power into the CAISO market under a market-based rate tariff the firm will file with FERC.

The generators being spun off include 3,848 MW of hydro, 1,400 MW of natural gas units, 152 MW of solar and 182 MW of storage.

The proposal led to protests from the California Community Choice Association, the Transmission Agency of Northern California (TANC), Northern California Power Agency (NCPA) and Public Citizen. (See Parties Protest PG&E Plan to Spin Off Generation.)

The community choice aggregation association argued that without detailed information on which firm will buy the generation, its impact on vertical market power cannot be determined. FERC sided with PG&E, saying that spinning off the generation to a new subsidiary that does not provide any inputs to electricity products will not lead to vertical market power concerns.

While the utility promised to hold its customers harmless in the transactions, the city of Santa Clara, TANC, Public Citizen and NCPA said that was not enough to ensure that outcome. PG&E should look into less disruptive ways to raise capital, Public Citizen said.

TANC noted that PG&E wants to issue up to $2.1 billion in debt for the new firm, whose assets will value about $3.5 billion. It argued that FERC should require the company to show its accounting treatment and whether the deal would alter PG&E’s equity ratio. The utility provided no information on which costs transmission customers will be held harmless, which makes it impossible to determine whether that will actually happen, TANC said.

FERC determined that the deal would not affect rates. When it comes to wholesale rates, the assets will be bid at market prices, which will not be impacted by the seller’s cost-of-service retail rates.

Pacific Generation has yet to file a request for market-based rate authority; FERC said its approval is based on the new firm getting that authority before the deal closes.

“Failure by Pacific Generation to obtain market-based rate authority as PG&E represents in its application would constitute a material change in circumstances that we rely on in making our findings herein,” FERC said.

The commission also said the protesters failed to show the deal would impact PG&E’s cost of capital or transmission rates. The deal would not impact the firm’s return on equity, its credit rating or its capital structure, so claims to the contrary lack a factual basis, the commission said. It noted, however, that if those change, then that would also represent a material change to the facts relied upon in its approval.

FERC also found the deal would not affect rates, as the new subsidiary and the utility will still be regulated by it on the wholesale side, and the CPUC on the retail side.

Public Citizen argued that the transfer of generation to private equity could impair state oversight, but FERC said that is beyond the scope of the proceeding because it focused on the spinoff, not any later sales.

The deal would not lead to any cross-subsidization issues, where benefits are transferred from captive customers to shareholders, because both the utility and Pacific Generation will be regulated by the CPUC, FERC said.

“A debt issuance by Pacific Generation for the benefit of its utility affiliate, PG&E, is not analogous to a situation where the assets of a franchised public utility with captive customers are used to finance its market-regulated utility affiliates or nonutility affiliates or their activities, which the commission has stated may raise concerns,” FERC said.

Many of the protests argued that FERC should consider the spinoff and the subsequent sale of a minority interest in the generation at the same time, but the commission disagreed, saying expanding the proceeding to cover the second deal would be inappropriate.