During a Central Subregional Planning meeting Tuesday, MISO’s Grant Larson said staff reanalyzed the system without Rush Island’s assistance and again found transient voltage recovery and steady state voltage violations if it is allowed to suspend operations. Larson said Rush Island’s SSR status will have to be renewed for another year Sept. 1 unless stakeholders can suggest generation or transmission alternatives by June 20.
“MISO likes to consider SSRs a last resort,” Larson told attendees, but he said the RTO has “unfortunately” not found any reconfiguration, redispatch or demand-response alternatives to avert another extension.
“Transient voltage recovery violations, that result in cascading outages and instability, cannot be mitigated,” he told stakeholders. He said more than 1,000 MW of load is at risk due to the violations.
MISO restudies system conditions annually to assess the need for SSR agreements.
Larson said transmission upgrades in the area that negate the SSR won’t come online until mid-2024 and 2025. He said the wind, solar and battery storage projects proposed in Illinois and Missouri won’t be available in time either.
While some system upgrades that will be completed by September have improved reliability performance and mitigated a few of the issues since 2022, Larson said, it won’t be enough to allow Rush Island to suspend operations. He also said the SSR’s cost allocation to load won’t be “drastically” different, though some elemental pricing nodes will change.
ERCOT stakeholders on Monday unanimously endorsed a protocol change that requires resources to file exceptional fuel costs that include contractual and pipeline-mandated costs, following negotiations between consumer representatives and a generator.
The Technical Advisory Committee had tabled the nodal protocol revision request (NPRR1177) during its regular May meeting to give the two groups an opportunity to work out their differences. They said their edits allow ERCOT to determine ineligible costs, clarify that exceptional fuel costs are distinct from fuel adders, and codify some of the attestation’s language. (See “Fuel-cost Discussion Tabled,” ERCOT Technical Advisory Committee Briefs: May 23, 2023.)
“I think we’ve landed in a good place,” Eric Goff, a member of TAC’s consumer segment, said during the virtual meeting.
“We’re supportive of the consumer comments,” said Constellation Energy Generation’s Andy Nguyen, the NPRR’s sponsor. “NPRR1177 is a vast improvement to what we have today.”
Constellation modified the attestation’s language to add that fuel costs be “accurate and variable” so that it is based on the resource’s actual dispatch. However, Nguyen said the NPRR still does not address a gap in the protocols where a mitigated resource has no cost recovery mechanism if it is uneconomically dispatched.
The revised version accepts ERCOT’s draft language presented during the May meeting. It also removes from the NPRR the complex task of developing standardized contract language. That has been referred to TAC’s Wholesale Market Subcommittee for additional discussion with the ISO’s staff.
A 2027 sunset date was modified to Jan. 1, 2025, to allow a permanent solution for the standardized contract.
TAC also re-visited NPRR1169, which expands the qualifications for generation resources that may be a firm fuel supply service resource or an alternate.
The Public Utility Commission urged additional discussion of the issue during its May 25 open meeting. The commissioners and ERCOT staff deliberated over safeguards to prevent facilities from being inappropriately disqualified if the qualified scheduling entity serves public needs through a gas distribution company elsewhere in the state.
The two staffs are working to ensure that pipelines providing firm gas supply to generators aren’t curtailed should the gas be designated for residential customers first.
Attorney John Arnold, who represents gas suppliers Kinder Morgan and Enterprise Products before both the PUC and the Railroad Commission, proposed an alternate definition for qualifying pipelines that addresses their deliverability at individual generators instead of systemwide.
TAC’s members declined to add comments to the NPRR, but ERCOT plans to file additional comments for the Board of Director’s consideration during its June 19-20 meeting.
VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee voted 54% to reject manual changes that sought to clarify how the RTO can exercise unilateral power to increase the synchronized reserve requirement, with stakeholders opposed arguing that such action should require a FERC filing and doesn’t address the root cause of underperforming reserve resources.
On May 11, PJM announced that it would be doubling the requirement, but the increase was removed May 16 and replaced with a smaller 30% increase May 19, which PJM Senior Vice President of Operations Mike Bryson said was done to reflect stakeholder feedback regarding the initial increase. (See “PJM Doubles Synchronized Reserve Requirement,” PJM OC Briefs: May 11, 2023.)
The proposed language would have specified that “PJM may schedule additional contingency reserves on a temporary basis in order to meet the largest single contingency, as necessary to account for resource performance” to meet ReliabilityFirst requirements. Senior Vice President of Market Services Stu Bresler said it was hoped stakeholders would be in consensus with PJM but that PJM plans to move forward with implementing the manual changes and the 30% increase unilaterally.
The response rate from synchronized reserve resources fell by an average of about 20% following the implementation of an overhaul of the reserve market in October that consolidated the Tier 1 and 2 products, according to a previous presentation to the Markets Implementation Committee. Bryson said PJM has a responsibility to procure reserves that can match the largest single contingency the grid faces, and it is working with Independent Market Monitor Joe Bowring to identify other solutions to address the low performance, including possibly referring resources to FERC for tariff violations.
Senior Dispatch Manager Donnie Bielak said the poor performance could be responsible for a potential violation of NERC disturbance control performance standards during the December 2022 winter storm, when PJM took just over the 15-minute window to recover from a drop in the area control error. The response rate has been stronger from former Tier 1 reserve resources, which were online through economic dispatch and able to increase output within 10 minutes, but PJM said their response will fall off in the future as their operations reflect that they are not receiving added compensation for that response above the going LMP.
The 30% increase is composed of 20% to account for the nonperformance, plus a 10% increase for uncertainty around the future response from uncommitted reserve (former Tier 1) resources. The increase amounts to a synchronized reserve reliability requirement of 2,080 MW, an increase of 480 MW. PJM’s Phil D’Antonio said the 200% increase could be brought back if it is determined to be necessary to meet the contingency reserve requirement, but that PJM will not go above that mark.
Old Dominion Electric Cooperative’s Mike Cocco said increasing the amount of reserves procured to account for underperforming resources is an “inelegant solution” and questioned what a long-term solution looks like. D’Antonio said PJM plans to bring a problem statement and issue charge around August.
Gregory Carmean, executive director of the Organization of PJM States Inc., said he believes the change would affect rates and thus requires FERC authorization, to which Bresler said the PJM tariff sets out a formula including synchronizes reserves and authorizes the RTO to set the reserve requirement.
Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned if the response rate could be affected by an interaction between the October market change and PJM’s software, data input or the ancillary service optimizer. He said it doesn’t make sense that reserve resources aren’t responding to LMPs but noncommitted resources are.
“There seems to be a mismatch between what you’re describing and what’s actually going on here,” he said.
Presenting the Monitor’s perspective on the proposed language, Bowring said he doesn’t believe PJM has the authority to make the changes on its own and the focus should be on perfecting supply, rather than increasing demand. Resources providing synchronized reserves have stated to him that they have issues with the supply curve and that they’re not able to provide what they’re being committed and paid for. While he said the must-offer requirement needs to be enforced, which could include FERC referrals, that is not the optimal way of getting the desired performance.
Bowring cited as possible reasons for the low performance the accuracy of PJM’s ramp rates, ambient rates, fuel availability, demand response performance, resources failing to follow dispatch, incorrect eco max and spin max parameters, and discontinuities in the offer curves.
Stakeholders Discuss Way Forward on Circuit Breaker
PJM presented a first read of its proposal to create a “circuit breaker” to limit high prices over an extended period, continuing deliberations on a topic that divided stakeholders and yielded a half dozen proposals before the frontrunners were rejected by the MRC in December. (See “Two Proposals on ‘Circuit Breaker’ Fail,” PJM MRC/MC Briefs: Dec. 21, 2022.)
The proposal unveiled Wednesday was built off PJM’s previous Package F, which was formed in the Energy Price Formation Senior Task Force and would administratively cap LMPs to $2,000 after PJM has been in an RTO-wide operational emergency, defined as a NERC Level 3 energy emergency alert (EEA) event, and shortage price is in effect because of manual load dump or a voltage reduction. The trigger also includes a step in which PJM will evaluate how activating the circuit breaker would affect reliability and will not implement it if any concerns are identified. The circuit breaker would end once PJM is no longer under EEA 2 or 3 conditions and the shortage pricing is no longer in effect.
PJM’s previous proposal did not include an administrative review as part of the price cap trigger, and it would have terminated after a five-day period. Senior Director of Market Design Becky Carroll said the changes were made to ensure the circuit breaker didn’t harm operations and would not end while an emergency was potentially ongoing.
“We really are concerned about creating adverse impacts to system operations, and we don’t want to do that,” she said.
Carroll said the proposal is still in flux, and additional details on components, such as when the circuit breaker would be triggered, could change by the time tariff language is drafted. Bresler said PJM plans to bring the language directly to the Board of Managers without a stakeholder endorsement, as the issue has already been brought through the full stakeholder process without being able to reach consensus.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said the impact of the February 2021 winter storm on ERCOT underscored the need to create a price cap for many advocates, and he encouraged PJM to consider how other regions have reacted. He also said PJM should consider the components in the joint stakeholder package, sponsored by ODEC, Southern Maryland Electric Cooperative and Northern Virginia Electric Cooperative, given that the PJM proposal never advanced to the senior committee level. The joint package and a competing proposal from Calpine were both rejected by the MRC on Dec. 21, while five other proposals did not advance from the EPFSTF. (See “Support for Circuit Breaker Remains Mixed,” PJM MRC Briefs: Oct. 24, 2022.)
David “Scarp” Scarpignato said that under the status quo, the scarcity adder gives a buffer over the inflexibility of incorporating fuel costs into offers, which wouldn’t be possible under the uplift provided by the circuit breaker based on those offers. Most generator offers don’t fully represent fuel costs because of how that would administratively burden resource owners, he said. The circuit breaker could create a disparity between the pricing run and the dispatch run, creating a challenging reliability situation for PJM if it’s not sending the proposal signals for generators on how to operate.
The board called for the continuation of the process of creating a circuit breaker in a March 10 letter and asked that a proposal be brought to it by July.
PJM, Monitor Review IROL-CIP Proposals
PJM’s Darrell Frogg presented a first read of the RTO’s proposal to create a cost-recovery mechanism for investments required under NERC’s interconnection reliability operating limits (IROLs) under its Critical Infrastructure Protection (CIP) standards. The proposal was endorsed by the Operating Committee on March 9, receiving 89% support, while the Monitor’s proposal receive 11%. (See PJM OC Briefs: March 9, 2023.)
The proposal would function similarly to PJM’s existing black start cost-recovery mechanism, with generators submitting costs to the RTO and Monitor to review and reviews collected through charges to market participants. Supporters speaking during the OC argued that having a facility declared critical by NERC and required to make reliability upgrades is outside of their control, can carry significant costs and is unpredictable.
The MRC is slated to consider voting on the proposal during its June meeting. Assuming stakeholder endorsement, PJM plans to file a Federal Power Act (FPA) Section 205 filing around August.
Members Committee
PJM Launches Webpage for Tracking Resource Adequacy Concerns
PJM Vice President of State and Member Services Asim Haque told the Members Committee the RTO is planning to launch stakeholder processes on many of the issues discussed during a panel on reliability at its annual meeting.
A page on the RTO’s website has been created to track ongoing studies and detail how it plans to address future reliability and resource adequacy. (See “Panel Discusses Future Reliability Landscape,” PJM CEO, Panelists Address Reliability During Annual Meeting.)
Haque discussed the three timelines the overarching concerns fall into: the immediate need to support resource performance, the near-term need to ensure resource adequacy, and the upcoming concern for maintaining and attracting essential reliability services.
Public Power Decries Override of MC Endorsement on CP
Representing the PJM Public Power Coalition, Customized Energy Solutions’ Carl Johnson said it’s concerning that the PJM board has opted to disregard stakeholders’ endorsement of a proposal to revise the Capacity Performance (CP) construct to reduce the penalties generators face for not meeting their obligations during emergencies.
The MC voted May 4 to endorse a proposal redefining the penalty rate and annual stop-loss limit as being derived from the Base Residual Auction clearing prices, rather than the net cost of new entry, as well as tightening the circumstances under which PJM can declare a performance assessment interval (PAI). Later that month, the board announced that it would only be including changes to the PAI trigger in a FERC filing. (See PJM Board Rejects Lowering Capacity Performance Penalties.)
Johnson expressed his displeasure that PJM chose pieces of a larger package supported by stakeholders to present to FERC, particularly as work continues in the Critical Issue Fast Path process to create proposals overhauling the capacity market.
“It puts groups like mine in a really difficult position when we’re looking to build consensus on a proposal in the future,” he said.
American Municipal Power’s Lynn Horning said there’s open space for stakeholders to consider rules and more specificity around when packages can be partially advanced to FERC.
Avangrid Renewables’ Kevin Kilgallen said the proposal would have injected uncertainty into delivery years for which capacity auctions had already been run. The language would have been effective through the 2024/25 delivery year.
“To change the product definition without there being an urgent need to do so … between the auction and the delivery year, we thought that’s very bad policy, and it adds another level of uncertainty,” he said.
PJM CEO Manu Asthana said staff and the board don’t take the decision to override stakeholders lightly, but the RTO holds the authority to make changes under FPA Section 205 and has an obligation to make filings it believes will uphold reliability.
“I don’t want to keep doing this, but I think it’s a two-way street: We recognize where the stakeholders have … rights, and we give deference as much as we can,” he said, noting that stakeholders hold the rights to make changes related to the Operating Agreement.
The Department of Energy on Monday released two draft requests for proposals aimed at building out a U.S. supply chain for the specialized uranium fuel needed for the next generation of advanced nuclear reactors that it is also helping to build.
The RFPs will allow DOE to acquire high-assay, low-enriched uranium (HALEU), which it will then distribute or sell to companies that are part of its HALEU Consortium of industry stakeholders, to be used “for civilian domestic research, development, demonstration and commercial use.”
HALEU has higher levels of the radioactive U-235 isotope — up to 20% versus the 3-5% low-enriched uranium used in commercial reactors now in operation — allowing for smaller and more efficient reactors that may not need to be refueled as often and produce less nuclear waste.
Two advanced reactors being developed with more than $3 billion in DOE funding — TerraPower’s Natrium reactor and X-energy’s Xe-100 reactor — will need HALEU, but the U.S. currently does not have the ability to produce the special fuel at scale. The only commercial facility producing HALEU is in Russia, and with the outbreak of the war in Ukraine, U.S. companies like TerraPower have had to look for other sources of the fuel.
The lack of a domestic HALEU supply could delay completion of the Natrium reactor in Wyoming by two years, according to a December announcement from TerraPower CEO Chris Levesque. When the DOE originally selected TerraPower and X-energy for the demonstration projects in 2020, the advanced reactors were supposed to be online in seven years.
“We must jump-start a commercial-scale, domestic supply chain for HALEU,” said Kathryn Huff, DOE’s assistant secretary for nuclear energy. “Spurring the nation’s capability to produce HALEU will set the stage for larger, commercial scale production. This will bring us closer to deploying advanced nuclear technologies in communities across the country.”
“This is … a really important first step in getting this market going,” said Patrick White, project manager at the Nuclear Innovation Alliance. The need to build out the HALEU supply chain “is something we’ve known about for years, but we just haven’t had the right economic conditions.”
The war in Ukraine, coupled with $700 million in the Inflation Reduction Act earmarked for U.S. production of HALEU have provided some of the momentum.
According to the DOE announcement, more than 40 metric tons of HALEU may be needed by 2030, with additional amounts required each year, to meet President Joe Biden’s goal of decarbonizing the U.S. electric power system by 2035.
At present, the only facility licensed to produce HALEU in the U.S. is a DOE-funded demonstration project at a Centrus Energy facility in Piketon, Ohio, which is on schedule to begin production at the end of this year, according to Lindsey Geisler, director of corporate communications.
Incentivizing the Market
The existing U.S. commercial nuclear fleet of 92 reactors provides 20% of all the electric power in the country and 50% of zero-emission electricity. While still controversial for some, maintaining and expanding nuclear capacity is part of Biden’s and DOE’s clean energy agenda.
DOE is dividing its efforts to build the HALEU supply chain into two key and complementary initiatives. The first of the two RFPs is focused on the enrichment process, taking mined and milled uranium and stepping up its enrichment from the 0.7% of U-235 that occurs in nature to between 5% and 20%, White said.
The process involves putting the milled uranium, called yellow cake, through a series of centrifuges that gradually step up the enrichment level, he said.
U-235 is a “fissile” isotope of uranium, which means it can sustain the kind of nuclear chain reaction needed to power a commercial reactor and produce electricity. Weapons-grade uranium is about 90% U-235.
The second RFP seeks companies for a process called “deconversion,” which takes the stepped-up uranium and puts it through a chemical process that turns it into a pure metal or other solid feedstock that can then be turned into the fuel that can power a reactor.
“The availability of HALEU is a bit of a chicken-and-egg problem,” White said. “It’s hard to set up an industry and make significant capital investments if you don’t know what the long-term demand is, and it’s hard to have long-term demand if you don’t know what your supply is.
“And so, by the U.S. DOE coming in and guaranteeing purchases for these first amounts of HALEU, it can hopefully incentivize private companies to stand up their production capabilities and then allowing private companies to start buying what comes off the line,” he said.
The release of the draft RFPs on Monday began a month-long comment period ending on July 6.
DOE is also launching an environmental review of the proposed HALEU supply chain buildout in compliance with the National Environmental Policy Act. A notice of intent for the review was published Monday in the Federal Register.
White noted that the environmental review could slow down the supply chain buildout. In particular, the RFP focused on enrichment only allows for initial planning, permitting and licensing until the environmental review is completed.
The RFPs also limit DOE’s ability to award contracts related to the $700 million for HALEU authorized in the IRA, but both White and Geisler said additional funding will be needed.
“The Inflation Reduction Act represents a strong initial down payment, but there is broad agreement in the industry that additional funding will be required to establish the domestic HALEU supply chain necessary to commercialize the next generation of advanced reactors,” Geisler said in an email to NetZero Insider.
With long lead times for building out each part of the supply chain, “getting this process started and making sure it keeps moving is really critical,” White said. “Let’s get through the draft solicitation process, provide feedback that allows DOE to quickly iterate and then move forward with it because the last thing we want is for this RFP process to take another six months or a year.”
ISO-NE wholesale market costs were down 23% for the winter of 2023 compared to 2022, said the RTO’s Internal Market Monitor (IMM) at the Markets Committee meeting on Tuesday. The decrease was driven by a 29% drop in energy costs, which was largely a result of the 37% decrease in natural gas prices compared to the previous winter.
While wholesale costs declined, capacity market costs increased by 18%, or nearly $100 million, due to the supplemental payments to the Mystic 8 and 9 generators — the main customers of the Everett LNG import terminal — which totaled $213.5 million.
ISO-NE entered into an agreement in 2022 with Constellation Mystic Power to keep the generators operating through May 2024. The RTO justified the agreement to bolster fuel security in the region, but the agreement has been subject to intense criticism from a range of stakeholders.
“The net costs passed through the agreement so far have been astronomical: more than $436 million over the first ten months of the two-year term,” per a May FERC filing on behalf of a group of New England consumer-owned utilities (ER18-1639). “Most of those costs have resulted from [Constellation] buying — and then selling at a loss, burning uneconomically, or otherwise disposing of — fuel that Mystic did not need.”
The IMM noted in its presentation that relatively high winter temperatures led to lower average and peak loads for 2023. The average load was down by about 4% compared to the winter of 2022.
The region did experience two major cold snaps Dec. 24-27 and Feb. 3-4. On Dec. 24, the region faced its first pay-for-performance (PfP) capacity scarcity conditions since 2018, due to a combination of factors including low temperatures, a reduction in net imports, and several gas and dual-fuel generation plants failing to supply power.
“Most resources that tripped were older generators that run infrequently,” said Kathryn Lynch of the IMM. Lynch said these resources totaled approximately 2,180 MW of capacity.
The IMM said PfP credits and charges totaled $35.9 million during the scarcity conditions, with most charges incurred by gas and dual-fuel generators, while most credits went to imports, nuclear and pumped storage.
Generation from oil spiked during the two periods of extreme cold weather, making up 20-26% of generation during these stretches. Overall, oil generation decreased relative to 2022 and made up a small fraction of overall generation.
Technical Difficulties
ISO-NE said it has paused discussions on its Resource Capacity Accreditation (RCA) project due to a software error related to how it models LNG inputs for gas generation plants.
“The software significantly restricted LNG available to the gas resources,” said Tongxin Zheng of ISO-NE.
The RTO is developing the RCA modeling to project the reliability and availability of energy resources, and it will use the modeling to determine the amount of capacity a resource could receive in the Forward Capacity Market.
“The preliminary evaluation after correcting the software effectively results in negligible reliability risk in the model for winter under FCA 16 assumptions,” Zheng said. “Further evaluation is needed to determine whether the winter risk level in the initial results containing the error [nearly complete elimination of LNG in the software] is reasonable.”
The RTO previously hoped to implement the RCA modeling for the 19th Forward Capacity Auction, which is scheduled for 2025 and will determine capacity obligations for 2028/2029. Zheng said the software will impact the project schedule.
“ISO is reviewing its options and plans to share further information with stakeholders ahead of the June NEPOOL Participants Committee meeting,” Zheng said.
The Nevada Legislature wrapped up its 2023 regular session by passing bills related to integrated resource planning for electric and gas utilities, along with a bill creating a zero-emission truck incentive program.
Assembly Bill 524 passed on a 20-1 Senate floor vote just hours before the legislature adjourned at 11:59 p.m. on Monday.
Assemblyman Howard Watts (D) introduced the bill with the goal of reducing electric utilities’ reliance on the open energy market to acquire sufficient supply. That in turn might improve electric reliability and reduce consumer costs, he said.
The bill would require utilities to include in their integrated resource plans a scenario in which they acquire enough energy resources to close their open position. Although that scenario must be evaluated, it wouldn’t necessarily be the one chosen. (See Bill Would Require NV Energy to Examine Market Reliance.)
NV Energy opposed the bill, saying the legislature should go further by calling for utilities to quickly close their open positions.
AB 524, which previously passed unanimously in the Assembly, now goes to Gov. Joe Lombardo for a signature. In a March executive order, Lombardo called for the state’s “advancement of energy independence.”
The state’s legislature meets every other year in a 120-day session. Although the regular session has ended, Lombardo is expected to call a special session on unresolved budget issues.
The 2023 legislature also passed Senate Bill 281 by Sen. Rochelle Nguyen (D).
The bill would require natural gas utilities to file a plan every three years, similar to the IRPs filed by electric utilities. The bill aims to improve the transparency of gas utility planning. (See Nev. Bill Would Require Gas Company Efficiency, GHG Plans.)
The Senate and Assembly both unanimously passed the bill, which was backed by Southwest Gas.
Zero-emission Truck Incentive
Another bill introduced by Watts this year was AB 184, which directs the Nevada Division of Environmental Protection to work with the state Department of Transportation to establish a Clean Trucks and Buses Incentive Program.
The incentives would be funded through the federal Carbon Reduction Program, part of the Infrastructure Investment and Jobs Act.
Nevada will receive an estimated $57 million over five years through the federal program. Of that, 35% is flexible funding that could be applied to the incentive program, Watts said during a hearing this month before the Senate Natural Resources Committee. No state funding would go toward the incentives.
The incentives would be for the purchase of a zero-emission medium- or heavy-duty truck, including a battery electric or hydrogen fuel cell vehicle. Base incentive amounts would range from $20,000 for a Class 2b truck to $175,000 for a Class 8 truck.
Increases to the base incentive would also be available in some cases. For example, a small business could receive a 20% increase to the base incentive, and a disadvantaged small business, such as one owned by a minority, woman or veteran, would be eligible for a 5% increase. A truck buyer could combine up to two base incentive increases.
Independent truck operators would be eligible for a 33% increase to the base incentive amount, but they wouldn’t be able to add on the small business increase.
The incentives would be available to businesses, nonprofits, and state and local government agencies. Watts said the idea was to bring the cost of a zero-emission truck in line with that of its diesel counterpart.
Andrew MacKay, executive director of the Nevada Franchised Auto Dealers Association, said zero-emission trucks are cost-prohibitive for most independent truck operators and small operators.
“This bill’s transformative,” MacKay said during the committee hearing. “It’s going to put these people in a position … of being able to afford these vehicles.”
Another bill by Watts adds new requirements for state automobile fleets. AB 262 requires the state to give preference to vehicles that minimize emissions and give consideration to the lifetime cost of the vehicle when making purchasing decisions, “to the extent practicable.”
Lombardo signed the bill on Monday.
Ben Prochazka, executive director of the Electrification Coalition, said Tuesday that electric vehicles are typically less expensive to operate than those with internal combustion engines.
“AB 262 will save Nevada’s taxpayers money and signal that the state is demonstrating leadership as the U.S. rapidly accelerates toward transportation electrification,” Prochazka said in a statement.
Yucca Bill Fails
Bills that failed during the 2023 legislative session include Senate Joint Resolution 4, introduced by state Sen. James Ohrenschall (D). SJR 4 would have urged the federal government to use Yucca Mountain for the development and storage of renewable energy. The site, about 100 miles from Las Vegas, has been eyed as a disposal site for the nation’s high-level radioactive waste. (See Nevada Resolution Seeks to Bring Renewables to Yucca Mountain.)
But SJR 4 missed the deadline for passage from its first committee, Senate Natural Resources.
SouthCoast Wind Energy is moving to end its offshore wind power purchase agreements with three Massachusetts electric distribution companies.
The company said it will continue developing the project in federal waters south of Martha’s Vineyard while the parties seek a solution, but that the terms of the PPAs they negotiated in 2020 and amended in 2022 are untenable, given rising costs.
SouthCoast, formerly Mayflower Wind Energy, is a joint venture of Shell New Energies and Ocean Winds North America. It holds an offshore wind lease area with the potential for up to 2,400 MW of power generation and was to supply 1,200 MW to Eversource Energy, National Grid and Unitil.
In October, SouthCoast asked the Massachusetts Department of Public Utilities to suspend the PPA proceedings for a month so the parties could consider recent economic changes — including inflation, interest rates and material shortages — that made the PPAs financially untenable.
Around the same time, Avangrid made a similar request for the 1,200 MW of PPAs with the same three utilities for output from the Commonwealth Wind project it is developing.
The utilities declined to negotiate, and the DPU rejected the requests.
Avangrid dug in its heels and moved to terminate the PPAs, setting in motion a process that landed in Suffolk County Supreme Judicial Court four months ago. The company says it remains committed to Commonwealth and would like to rebid the project in Massachusetts’ next offshore wind solicitation.
SouthCoast backed down after the DPU rejection, at least publicly. It maintained that the financials were untenable but said it would work toward a solution. Apparently, it did not find one.
As of press time, there still were no official filings posted by the DPU, but SouthCoast CEO Francis Slingsby on Friday submitted testimony to the Rhode Island Energy Facility Siting Board, which is considering SouthCoast’s request to run one of the project’s export cables underwater and underground through Rhode Island on its way to Massachusetts. Slingsby argued that the board should not suspend its consideration of the transmission line application until new PPAs are in place because doing so would delay or jeopardize the project.
Even as it seeks better financial terms, SouthCoast has secured interconnection queue positions for the offshore wind farm and continues preparatory work, with more than 75 full-time employees on the job and a roughly $100 million development budget for 2023, Slingsby said. He expects the U.S. Bureau of Ocean Energy Management to issue a Record of Decision on the project in December.
But SouthCoast cannot attract financing with the existing PPAs, he said, because they are low-priced and have no indexation. The latest Massachusetts offshore wind solicitation addresses those concerns by allowing for inflation-indexed pricing, Slingsby said. SouthCoast plans to compete in that and/or other future rounds of bidding in New England, he said.
In a statement SouthCoast said it is open to solutions other than terminating the PPAs. But even after factoring in the cost of termination, any resulting penalties and lost tax incentives, terminating the PPAs is a better option than proceeding with them as written, it said.
Economic Headwinds
This latest development will not help Massachusetts reach its statutory goal: 5,600 MW of offshore wind online by 2027.
Gov. Maura Healey last month announced the draft of the state’s fourth offshore wind solicitation would seek proposals totaling up to 3,600 MW of generation capacity.
That — combined with the 800-MW Vineyard Wind 1 now under construction and SouthCoast — would reach the desired number of megawatts, if not the deadline.
Without SouthCoast or Commonwealth, Massachusetts falls short.
A spokesperson for Healey’s Executive Office of Energy and Environmental Affairs on Tuesday said, “We encourage all parties to find clarity on the next steps before the fourth offshore wind solicitation becomes active.”
The U.S. is late to the offshore wind sector: 32 years after the first commercial offshore wind farm went online in Denmark, U.S. waters host just 42 of the 63,200 MW of offshore generation installed worldwide.
As the public and private sectors try to create an industry almost from scratch, costs and logistics are proving to be challenges. The Northeast coast is the early focal point of development efforts, and the projects and proposals there are feeling the brunt of headwinds facing the industry.
Besides SouthCoast and Commonwealth, recent examples include:
Rhode Island’s latest offshore wind solicitation attracted just one proposal, and the wording of Rhode Island Energy’s public response indicated it might be expensive.
Avangrid has said it would ask Connecticut for a PPA adjustment on its Park City Wind project.
Ørsted has said it would take a $365 million cost impairment on its Sunrise Wind project in New York and has said returns on its Ocean Wind 1 project in New Jersey were not what it had hoped for.
On a brighter note, Avangrid has said Vineyard Wind 1 locked in supply contracts before the economic headwinds rose, averting a financial crunch.
The Electric Power Research Institute told NetZero Insider the financial problems experienced by SouthCoast and other projects are not unique to them or to the offshore wind industry but are exacerbated by the newness of the sector in the U.S.
“Offtake agreements are negotiated when the project is in the relatively early stages of permitting, with a five- to seven-year lag before permits are approved and an eventual final investment decision is made,” Offshore R&D Lead Curtiss Fox said via email Tuesday. “With the continuous and dramatic cost declines for offshore wind over the past decade, it would be reasonable to assume those would continue with some limited risk. However, the implications of economy-wide inflation seen over the past two years have changed those underlying assumptions.”
Fox said last year’s Inflation Reduction Act will likely boost momentum in the U.S. offshore wind industry and expand its supply chain, but the rest of the world will be attempting to do the same thing at the same time.
“The global demand for offshore wind continues to expand dramatically, with Europe alone looking to expand capacity in the North Sea to 120 GW by 2030, up from nearly 28 GW today, and to reach 300 GW by 2050,” he said. “With the initial tranche of U.S. projects heavily leveraging EU supply chain capacity, the U.S. may not be able to rely on global excess capacity and will need to continue investments into offshore wind manufacturing, vessels and port infrastructure to achieve a sustainable offshore wind industry.”
[This story has been corrected. A previous version incorrectly identified the developer of the Commonwealth Wind project.]
FERC on Monday authorized settlement judge procedures to resolve about a dozen complaints that generators filed against PJM’s assessment of penalties for underperformance during the December 2022 winter storm, also known as Elliott (EL23-53, et al.).
“Given PJM’s interest in finding a resolution to the issues raised in these proceedings — along with parties’ general collective willingness to engage in settlement procedures — we find that these procedures are a reasonable first step,” FERC said. “The commission has previously found that providing parties the opportunity to enter into a mutually acceptable settlement of highly contested and complex issues is superior to years of ongoing litigation which, as PJM notes, could be disruptive to the market.”
PJM requested settlement judge procedures in April, maintaining that it had properly followed its emergency procedures and that all penalties were valid. But the RTO also said there is value to seeking rapid resolution rather than engaging in years of litigation that could negatively impact market participants beyond the penalties themselves. (See PJM Seeks Settlement over Elliott Nonperformance Penalties.)
“The capacity market also is designed in large measure to signal the need for new capacity resource investment, and the expectations of the financial and investment community accordingly are an important backdrop to the operation of this market,” PJM said. “Timely, consensual resolution of these disputes thus could, potentially, help support the long-term health of the resource adequacy construct in the PJM region.”
By folding the protests under a global proceeding, PJM argued that it could promote consistency in settlement outcomes, if possible.
The RTO applauded the order Tuesday as providing a possible pathway for resolving the complaints.
“PJM appreciates the commission’s order establishing global settlement judge procedures to pursue a potential resolution of disputed nonperformance charges and the related complaints arising from Winter Storm Elliott,” PJM said.
Separately in May, PJM urged the commission to reject the complaints, arguing that its Capacity Performance rules were clear and that the RTO followed its tariff. (See PJM Urges FERC to Deny Winter Storm Complaints.)
FERC left the scope of the settlement proceedings open to all issues that have been raised in the complaints, which include arguments that PJM was not permitted to fulfill non-firm exports during performance assessment intervals, generators not dispatched or scheduled were penalized, and PJM’s forecast was incorrect and played a role in the cause of the emergency.
The order provides 10 days for the chief judge to appoint a settlement judge for the proceeding, with parties able to submit recommendations in that time. If the settlement judge reports that progress is not being made toward an agreement after 60 days, the chief judge may refer the complaints back to FERC; if a resolution appears possible, an extension of up to 30 days could be granted.
Constellation and Vistra had both filed protests to PJM’s request for the proceedings, arguing that the RTO’s filing was “premature and incomplete” and that each complaint should be decided on its own merits. If the commission granted PJM’s request, Vistra pushed for it to require that all interested parties be able to participate; specify that bonus payments remain due to generators that exceeded their obligations; and establish a legal framework regarding the filed-rate doctrine, PJM’s scheduling decisions, and the proper interpretations of PJM’s tariff and manuals.
“PJM’s motion for settlement judge procedures seeks to move resolution of the complaints in these proceedings behind closed doors and facilitate an opaque result that would most likely weaken the existing Capacity Performance framework. As noted, Vistra believes the best path forward is one that avoids settlement judge procedures altogether by the commission ruling on the merits of each complaint,” Vistra wrote.
FERC recently approved SPP’s tariff revisions to its transmission planning process that establish new study processes for transmission-owning members (ER23-567).
The commission in its May 26 order found the changes to be just and reasonable and not unduly discriminatory or preferential. It accepted them effective Feb. 6, as SPP requested. It said SPP’s proposal increases transparency into staff’s review of transmission owner (TO) projects and helps ensure those projects receive the “appropriate cost allocation.”
The grid operator’s revisions allow it to evaluate TO projects’ reliability impacts before their inclusion into the integrated transmission planning process and confirm that they are eligible for zonal cost allocation. Zonal reliability upgrades identified by a TO will only be eligible for zonal cost allocation if SPP can confirm they relieve a zonal planning criteria violation and conform to applicable facility design criteria.
If the projects don’t meet the criteria, they will be designated as sponsored upgrades and their costs directly assigned to the sponsoring TO.
Commissioners Allison Clements and Mark Christie jointly concurred with the decision, writing that SPP’s proposed revision is “consistent with existing precedent” and improves the status quo. However, they said the filing raised a much bigger concern about the need to ensure any future transmission development is cost effective, as expressed during a technical conference in October. (See FERC Tech Conference Highlights Regulatory Gaps on Transmission Oversight.)
“It is our hope that the commission addresses these issues in that proceeding, and we additionally encourage SPP to make further improvements to its process,” the commissioners said, noting that the RTO’s planning process “appears to have significant room for further improvement.”
Storage As Tx Assets
In a separate order issued May 26, FERC accepted SPP’s proposal to treat electric storage resources as transmission assets (ER22-2344).
The commission said the grid operator’s proposal to define storage as a transmission-only asset (SATOA) and add language addressing cost allocation and recovery, transmission planning, interconnection, market participation and market monitoring issues is just and reasonable and not unduly discriminatory or preferential.
SPP’s proposed framework results in the SATOAs’ selection only when they perform a transmission function. Under the RTO’s definition, the asset must be under SPP’s operational control and connected to the system as a transmission facility solely to support the system. It also must be identified or selected in planning processes as the preferred solution to resolve transmission issues.
SATOAs’ participation in the markets is limited to only charging from, and discharging to, the transmission system as necessary to provide the services for which it was issued a notification to construct. FERC said that under those circumstances, SATOAs are properly characterized as transmission assets and the costs of a SATOA are appropriately recoverable through transmission rates.
“Because the operation of a SATOA would be limited to serving a transmission function, it is appropriate that a SATOA recover costs in the same manner as existing transmission facilities in the same transmission project category,” the commission wrote. “In addition, cost allocation for a SATOA is appropriately limited to the cost of the maximum capacity needed to address the identified transmission issue and is prorated on that basis if a SATOA of higher capacity is constructed.”
The American Clean Power Association and the Advanced Power Alliance led clean energy entities in requesting that FERC require SPP to add a restriction in its tariff on the use of SATOAs so they can be used only to address “non-routine” reliability transmission issues. They contended that the RTO’s proposed tariff language could permit SATOAs to be used for more routine transmission issues within each resource’s voltage parameters.
The commission declined clean energy’s request, noting that the proposal restricts a SATOA from resolving a transmission need for which a market solution exists. FERC said SPP will only evaluate a storage solution as a potential SATOA to address an identified transmission issue if it has unique characteristics or circumstances to meet transmission system performance requirements that are not available at comparable costs from other proposed solutions.
VALLEY FORGE, Pa. — PJM last week wrapped up the second phase of its Critical Issue Fast Path (CIFP) process to address resource adequacy concerns with two meetings about proposed changes to the RTO’s capacity market.
At May 30’s meeting, Constellation Energy proposed shifting to a prompt capacity auction held closer to the corresponding delivery year; the Consumer Advocates of the PJM States (CAPS) discussed states’ priorities and concerns around overhauling the Reliability Pricing Model (RPM); and American Municipal Power (AMP) presented changes to its conceptual design.
Thursday’s meeting saw presentations from the Natural Resources Defense Council on creating a seasonal capacity market; a former market design architect from ISO-NE providing information on a conceptual market design; Cornerstone Research’s Roy Shanker on his concerns about the current market structure; and Vistra on creating a credit market to value resource upgrades providing added reliability.
Stakeholders will begin developing formal packages during the third CIFP stage beginning June 14, when PJM will present its proposal.
Constellation Proposes Tighter Auction Schedule
Constellation’s Bill Berg said many of the inputs to the capacity auction could be more accurate and price signals could be improved if PJM holds capacity auctions six months to a year in advance of a delivery year. The status quo of holding auctions three years in advance makes it difficult to accurately forecast load and for generators to be sure whether they can procure firm fuel supply — a parameter PJM is considering having generators report prior to the auction.
Several stakeholders said the rationale for holding auctions three years in advance has been to allow the reference resource, currently a combined cycle generator, to be built between the auction clearing and the start of the delivery year to shore up capacity procurement shortfalls. Berg said investors monitor resource needs regardless of auction timing and are likely to make investments if they believe a region will be short on generation, regardless of auction timing.
Ryann Reagan, of the New Jersey Board of Public Utilities (BPU), questioned how a shortened time frame would interact with state retail auctions, noting that New Jersey has a three-year forward capacity product.
Berg responded that there’s a balance between price certainty and accuracy, which he believes is best weighed in favor of accuracy. Resources participating in state auctions with a longer lead time than a prompt auction would have to estimate PJM capacity prices when participating in state markets.
Constellation also suggested that compensating capacity resources at the end of the delivery year could improve performance incentives and lead to higher collections of any performance penalties the generator may accrue over the year.
While Berg said his company supports PJM’s proposal to set a minimum number of performance assessment intervals (PAIs) each year, market sellers must be able to reflect all risks and avoidable costs in their capacity offers.
“This seems like a dead-end to us because FERC already ruled on this,” Poulos said.
Berg also urged stakeholders to consider changes to the energy market, where he said PJM has put the onus of addressing reliability risks posed by forecast uncertainty and resource constraints, but it has had to resort to out-of-market actions to maintain operational reliability.
CAPS Outlines Advocate Concerns
As stakeholders discuss an overhaul of the capacity market, Poulos said state advocates are concerned about the Base Residual Auction (BRA) schedule, as well as how to ensure that market power is kept in check, performance incentivized and proper price signals are sent.
Advocates also lack firsthand insight into how the markets functioned during the December 2022 winter storm, also known as Elliott, making it difficult for them to evaluate proposals being discussed in the CIFP process, he said.
When considering changes to Capacity Performance (CP) penalties, Poulos said, it’s important to balance having penalties so high that generators risk bankruptcy after one event and having them so low that they don’t lead to better performance during future emergencies. Though performance was an issue during both the 2014 polar vortex and Elliott, he said CP likely did lead to increased readiness.
“The goal is not to bankrupt people — that is not helpful — but if you can’t perform, I don’t know what your value in this mix is,” Poulos said.
AMP Presents Revised Proposal
AMP revised the proposal it has been building throughout the CIFP process, which would replace the CP construct with a process for testing generators and penalizing them if they are not able to meet the amount of capacity they cleared. The changes aired May 30 would marry that concept with the proposed reworking of the performance penalty structure endorsed by the Members Committee last month but rejected by the PJM Board of Managers.
The revisions would shift the penalty rate and annual stop loss from being based on the net cost of new entry (CONE) to the BRA clearing price. AMP championed the language in the MC as a way of aligning market sellers’ capacity revenues with any penalties they’re assessed, while retaining an incentive to perform throughout the year.
Opponents of the language when it was before the MC argued that it would pose a reliability risk by cutting the penalty rate and stop loss by 90% without adding to requirements like winterization requirements.
PJM Presents Risk Modeling Analysis
PJM presented preliminary results of its analysis on the impact of switching to a reliability requirement based on an EUE model, which measures the amount of load that would go unmet during outages. The RTO currently uses a loss-of-load expectation (LOLE) model, which is a count of the number of outages expected. (See PJM, Stakeholders Present Initial Capacity Market Proposals to RASTF.)
In past CIFP discussions, PJM has proposed shifting the metric as part of its effort to improve risk modeling.
PJM’s analysis found that the EUE equivalent to the current one-day-in-10 reliability threshold would be around 1,800 MWh of lost load, with 96% of the outage risk concentrated in winter. Under the LOLE model, PJM estimates that 78% of the risk is in the winter, with the remainder being in summer.
PJM’s Patricio Rocha Garrido said winter outages tend to last longer and lead to more lost load, which he said is captured as increased winter risk through the EUE model.
The largest summer supply loss represented in the data was about 15 GW in July 2012, Rocha Garrido said, while 46 GW of generation was lost during Elliott.
James Wilson, a consultant to state consumer advocates, argued that the change would exaggerate risk and said that if being conservative in resource adequacy is a goal, that should be done through policy rather than modeling. He noted the analysis shown May 30 doesn’t account for climate change, which he said is likely to reduce the amount of risk in winter relative to summer by leading to warmer temperatures in both winter and summer.
PJM’s Pat Bruno said the RTO plans to continue improving the modeling, including by incorporating climate change into the data. He added that PJM had run sensitivities that found that climate change was unlikely to move the needle much for the type of modeling under discussion. Future analysis is also likely to include the impact on the installed reserve margin (IRM) and resource accreditation.
Bruno said the planning and market structures are currently based on an assumption that risk is concentrated in the summer, but the analysis suggests that a rethinking of those rules may be needed to maintain future reliability.
Vistra Presents Credit Market for Reliability Upgrades
During Thursday’s CIFP meeting, Vistra presented a proposal to create tradable credits to be awarded to generators that make investments to increase their performance, which would also raise their capacity accreditation.
Erik Heinle, Vistra’s director of PJM market policy, said that such investments may not lead to more capacity clearing in the BRA; however, it will increase a generator’s performance obligation, making it more likely to be subject to penalties and less likely to receive bonus payments.
The credits would be tradable in a PJM market and could be used by a buyer to excuse a performance shortfall equal to the increased capacity accreditation. PJM would create weekly risk assessments based on factors such as load and intermittent forecast variation, outages and fuel supply surveys, which buyers and sellers could use to determine their estimates of being subject to penalties.
Credits would only be awarded for facility upgrades on a list PJM would create during each quadrennial review.
Heinle said the proposal would add a financial product to allow generators to mitigate their non-performance risk, while still retaining an incentive to invest in upgrades.
Vitol’s Jason Barker said similar transactions exist today through bilateral transactions or within larger companies that maintain generation portfolios containing resources that can offset each other’s risks. Heinle said a PJM marketplace would increase transparency and improve price discovery.
Vistra’s Muhsin Abdur-Rahman said the proposal could also reduce the Capacity Performance quantified risk (CPQR) component of generators’ capacity offers to correspond with the reduced risk.
PJM’s Brian Fitzpatrick discussed a possible addition to the proposal being crafted by PJM that would create tiers of fuel security paired with the effective load-carrying capability (ELCC) model for each level. The proposal is currently focused on natural gas but would likely be expanded to other resource types as well.
Generators participating in the BRA would be required to indicate whether they will have dual fuel, single fuel with firm supply or single fuel without firm supply.
Fitzpatrick said the proposal is meant to help identify a lack of capacity on a gas pipeline or encourage greater fuel subscription to incentivize pipelines to expand, rather than creating another penalty structure for gas generators.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said fuel supply needs to be looked at holistically, incorporating issues being addressed by the Electric Gas Coordination Senior Task Force and examining other fuel types as well.
NRDC Proposes Seasonal Market
The NRDC presented a series of priorities it believes CIFP proposals must address around managing resources’ performance risk, including accurately accrediting resources and avoiding double-penalizing resource characteristics through CP and accreditation.
Tom Rutigliano, senior analyst for the NRDC, said accounting for resources’ characteristics through accreditation is the most effective option, rather than creating eligibility criteria for capacity resources, penalties or combining approaches. He supported PJM’s proposal to expand the use of the ELCC model to all resource types on the basis that it can weigh generators’ performance against the disparate risks the grid faces for each hour throughout the year.
Creating a system like ELCC to evaluate multiple gas generators fueled by a single pipeline to determine the marginal capacity value could also improve accreditation by revealing whether a pipeline is likely to be oversubscribed during an emergency, he said.
Though he said it would likely be topic to explore after the CIFP process, Rutigliano suggested moving to a seasonal capacity market to resolve some of the issues that expanding ELCC would not address, including variable transmission constraints, price signals incentivizing winterization investments, and treatment of planned and maintenance outages.
Rutigliano said that subjecting resources, particularly intermittent ones, to penalties for underperformance owing to characteristics already priced into their accreditation amounts to penalizing them twice. During Elliott, he said, wind and solar both performed as expected, but solar resources were generally assigned penalties, while wind resources receive bonuses based on attributes included in their ELCC analyses.
Shanker Highlights Concerns with Market Structures
Consultant Shanker presented a series of suggestions for stakeholders to consider throughout the CIFP process impacting all proposals, including:
how the must-offer requirement relates to auction planning parameters and performance obligation during PAIs;
how power exported from PJM during emergencies affects the balancing ratio;
who is the beneficiary of export premiums if the capacity benefit of ties is removed;
how many of these issues result in hidden future transmission charges; and
how stochastic generation and common mode outages could cause locational impacts adverse to reliability.
The forecast pool requirement (FPR) and associated IRM are determined with the assumption that all resources holding capacity interconnection rights (CIRs) will offer into the capacity market; however, excepting intermittent resources from the must-offer requirement skews both parameters, Shanker said.
Shanker cited Independent Market Monitor studies showing that about half of such resources hold CIRs but have not been offering in auctions. Because the variable resource requirement (VRR) curve is derived from the FPR and IRM, this leads to overstatement of the reliability of the capacity procured through the BRA. He said the calculation of the capacity emergency transfer objective (CETO), capacity emergency transfer limit and locational deliverability areas’ reliability requirements cause the same issue. The issue also raises market power issues regarding holding CIRs but not using them, he contended.
Shanker also said that many market components, including the FPR, IRM and CETO, incorporate an infinite transmission assumption, which can also lead to overstated reliability by not taking location and intermittency into account, causing additional hidden transmission costs.
Shanker also called for eliminating the capacity benefit margin (CBM) and capacity benefit of ties (CBOT) when determining PJM’s reliability requirement in order to ensure the RTO can meet its own needs at a capacity price that matches the cost of resources required to reliably meet grid requirements. He noted that this should logically change the price of emergency assistance and that associated export revenues would flow to native load rather than into any potential penalty and bonus structures added to the current CP design.
Conceptual Capacity Market Exchange Presented
Dick Brooks of Reliable Energy Analytics presented how PJM could use an always-on capacity exchange (AOCE) with further development of the concept.
A former software architect of ISO-NE’s forward capacity market clearing engine, Brooks said the project was developed as a strawman design for the clean energy transition and was being brought before the CIFP to demonstrate that other paradigms are being created.
The market would use a shorter auction advance timeline with capacity prices determined using an exchange and clearing price similar to day-ahead energy markets. Capacity resources would be approved by the RTO and enter offers into the market to be bid on by customers.
The RTO would continue to determine the total amount of capacity needed for a location and time, which the RTO would issue its own reliability bids to meet needs in the short or long term. Bids exceeding the total amount of capacity needed wouldn’t be cleared to receive capacity payments.
