Washington lawmakers have introduced a bill to require a study on disposing and recycling blades from wind turbines.
Senate Bill 5287, which calls for such a study by the Washington State University Extension Energy Program to be turned in to the legislature by Dec. 1, drew no opponents during a hearing before the Senate Environment, Energy and Technology Committee on Friday.
Three people testified in favor of the bill, while another 29 signed up in favor but did not testify. No one signed up in opposition. The bill has co-sponsors from both parties.
“There is currently not any facility in the United States that recycles wind turbine blades. … We think this will be someday mandatory in the future,” Jeff Gombosky, a lobbyist speaking on behalf of Renewables Northwest, told the committee.
“We need to be concerned with the total life cycle infrastructure,” said Ann Murphy, representing the League of Women Voters.
The average lifespan of a wind turbine blade is 20 years, said a Senate committee memo. The average length of a blade is 170 feet. Washington’s wind turbines produce 3,400 MW of power.
“Landfilling these giants is not green nor sustainable,” said the bill’s sponsor, Sen. Jeff Wilson (R). He added that roughly 8,000 blades have been removed from turbines nationwide.
“We’ve talked about industries being responsible for the life cycles of their projects,” Sen. Lisa Wellman (D) said.
The bill calls for the study to include the costs, feasibility and environmental impacts of disposal methods for the blades. The study would also look how a state-managed disposal program could be managed and at the possibility of recycling blades made of steel, plastic and fiberglass.
James Colombo, interim director of the WSU Extension Energy Program, said the research would include looking at the potential market for recycled wind turbine blades and at whether any current recycling operations in Washington could handle the blades.
NYISO updated the Operating Committee on the December snowstorm’s impact on grid operations, highlighting a particularly sharp shortfall in scheduled generation on Christmas Eve.
ISO Vice President of Operations Aaron Markham said that at one point that day 2,600 MW of generation scheduled in the day-ahead market failed to show up in real-time. (See FERC, NERC Set Probe on Xmas Storm Blackouts.)
He also said that Dec. 24 saw the winter season’s peak load to date, reaching 22,004 MW.
Regionally, conditions were tight, particularly in PJM, which experienced significant outages, resulting in NYISO having to facilitate emergency energy purchases and deliveries from both ISO-NE and IESO in Canada to PJM.
NYISO staff plan to return to the OC in March with a comprehensive report on Winter Storm Elliot’sfull impact on the New York Control Area, focusing on what caused outages, where production was reduced and what corrective actions need to be taken.
Howard Fromer, who represents the Bayonne Energy Center, asked whether the storm caused load to significantly deviate from ISO forecasts.
Markham responded that about 500 MW of committed resources may have underperformed in real-time but that was not significantly impactful.
ICAP Demand Curve Updates
Stakeholders approved final results for locational minimum installed capacity requirements (LCRs), net cost of new entry curves and transmission security limit (TSL) floors for the 2023/24 capability year. (See ‘Final LCR Results,’ NYISO Stakeholders Still Concerned About DER Participation Model.)
Yvonne Huang, NYISO resource adequacy manager, said updates to the modeling and methodology from last year included adopting GE’s dynamic energy limited resource functionality, maintaining 350 MW of operating reserves during load-shedding events, adopting new load shapes based on data from more recent years and considering generator outages in the TSL calculations to better align with methodology used in ISO planning studies.
Roger Clayton of the New York State Reliability Council (NYSRC) informed stakeholders at Thursday’s Transmission Planning Advisory Subcommittee (TPAS) that the council is developing interconnection reliability rules for inverter-based resources (IBRs).
Clayton said there is an “urgency” for the project because there is no standard interconnection process for IBRs, save for IEEE 2800, which, although approved last February, has yet to be adopted by any authorized agency responsible for regulating interconnection requirements.
Additionally, NERC has only released guidance documents. Although helpful, they “are not standards and only recommendations,” Clayton said.
Therefore, NYSRC is “taking action now” to get ahead of the anticipated influx of IBR projects in NYISO’s interconnection queue.
The IBR standards will be based around IEEE 2800 but tailored to the New York market. NYSRC is looking to get them in place as soon as possible, with the goal of having them be applicable to the Class Year 2023 slate of resources.
Clayton admitted this will be challenge, because NYSRC lacks relevant modeling and validation expertise; IBRs are new technologies that NYSRC has not extensively handled; and the timing will be tight, as CY23 starts Feb. 13.
NYSRC, however, has been working on the project since last year, and Clayton was confident that even if it misses its self-imposed deadline, it would still work to get the rules in place.
Clayton emphasized the project’s importance, calling attention to ERCOT and CAISO, which have both seen upticks in IBR interconnections but have experienced difficulties.
Gillian Coats, director of interconnection at Boralex, asked whether NYSRC was “putting the cart before horse” by trying to implement these new rules without a clear procedure in place.
“In a way we are,” said Clayton, “but if we wait, then there will be a bunch of projects that are interconnected without an objective standard, so there is definitely a tradeoff.”
Clayton, who is also chair of the council’s Reliability Rules Subcommittee, told stakeholders that NYSRC will host a meeting in two weeks to discuss the IBR draft rules and solicit additional stakeholder feedback.
Queue Reform
Thinh Nguyen, senior manager of interconnection projects, told stakeholders that NYISO continues to work on the interconnection queue to make it more responsive, transparent and expeditious.
Nguyen said that the queue has expanded from 120 projects in 2018 to 475, which has placed a tremendous workload on NYISO staff.
After initial stakeholder consultations, NYISO came away with several modifications. These included improving the interconnection portal; creating and hiring a dedicated stakeholder interaction liaison who can provide inquiry service to allow engineers to focus on technical issues; adding more project managers to handle collaborative utility processes; and eliminating certain evaluations.
Nguyen said the ISO will solicit further stakeholder feedback for the next two months, requesting comments be sent to stakeholder_services_IPsupport@nyiso.com. It will then spend spring addressing feedback and refining tariff proposals before seeking approval votes in the third quarter to ensure changes are filed with FERC before the end of the year.
Class Year Updates
NYISO Manager of Facility Studies Wenjin Yan updated stakeholders about the current status of Class Year projects.
CY21 was completed Jan. 11, and NYISO sent a notice to developers about the CY23 start date, noting that developers had until Jan. 20 to inform the ISO if they wanted to enter CY23. (See NYISO Completes Class Year 2021 Projects.)
NYISO also informed stakeholders that the next expedited deliverability study would start Feb. 23.
NYISO last week presented the Installed Capacity/Market Issues Working Group (ICAP/MIWG) with the anticipated schedules for its Installed Capacity market, energy market and new resource integration projects for this year.
The ISO plans to return to stakeholders each quarter to share status updates on each project. (See “Four Projects in 2023 Budget from Consumer Impacts Analysis,” NYISO Details 2023 Budget & Compensation Updates.)
Maddy Mohrman, NYISO capacity market design specialist, overviewed the capacity market design projects, including their anticipated first-quarter schedules and deliverables for this year.
The first project is modeling improvements for capacity accreditation, necessitated after NYISO discovered limitations within its resource adequacy analysis software, GE MARS.
2023 capacity market project overview | NYISO
NYISO will work with stakeholders and the New York State Reliability Council to improve the software by the fourth quarter. The updates should enable more accurate calculations for resource adequacy requirements, capacity accreditation factors and capacity accreditation resource classes.
The ISO will also work to improve the methodology for its LCR Optimizer software, which establishes the locational minimum installed capacity requirements (LCRs). It will spend the first quarter investigating the need for and developing any necessary enhancements to the software to improve the stability and transparency of LCRs, with an anticipated completion in the third quarter.
Another project relates to the 2025-2029 demand curve reset (DCR), a comprehensive review to determine the necessary assumptions for developing the ICAP demand curve. The project will be ongoing until 2025, but NYISO plans to post the DCR schedule in the first quarter of this year, select an independent consultant to conduct the study during the second quarter, and spend the rest of the year defining the inputs and methodology for the study.
Other software updates are needed to implement NYISO’s new capacity accreditation procedures and capacity resource interconnection service (CRIS) expiration rules.
Amanda Myott, NYISO energy market design specialist, detailed the energy market projects, including a project to rethink how to balance system needs as more intermittent renewables, energy storage resources (ESRs) and distributed energy resources come online.
The ISO anticipates proposing a market design concept by the end of the year based on previous studies of grid characteristics, resource attributes and new market products necessary to reliably maintain system balance.
Another project includes developing potential software and market rules that would enable NYISO to dynamically schedule reserves or procurements, which would better align market outcomes with system conditions by determining reserve requirements within a given region (See Study: NYISO Dynamic Reserves Could Lower Congestion, Costs.)
NYISO will spend the first quarter overviewing the project plan, looking through scheduling and pricing examples in the day-ahead-market and examining if updates are required to the posting of reserve requirements. It anticipates completing the market design by the third quarter.
2023 energy market project overview | NYISO
Another project centers on creating more transparency around emissions data, which the ISO believes will help end users and other market participants optimize their electricity usage. It expects to finish the necessary functional requirements and start publishing emissions rate data by the end of the year.
Mark Younger, president of Hudson Energy Economics, asked if this effort would be impacted by the cap-and-invest program proposed by New York Gov. Kathy Hochul, but NYISO said the project was an independent initiative. (See Hochul Highlights Cap and Invest in State of the State Address.)
William Acker, executive direct of the New York Battery and Energy Storage Technology Consortium, said that there’s a strong need for the project because it will help New York City buildings comply with Local Law 97 by better understanding how they can shift their energy consumption based on their emissions profile. (See NYC Proposes Rules to Implement Building Emissions Law.)
NYISO’s energy market team will also work to enhance the software for internal bilateral transactions, which currently does not enable ESRs to be a sink.
Stakeholders had indicated this project as a priority as the demand for ESRs to use bilateral transactions to contract output from specific resources has increased. The ISO expects software design specifications to be completed by the end of the year.
NYISO will also conduct a fuel and energy security study, which stems from a recognition that New York’s fuel supply mix is rapidly evolving and extreme weather events have become increasingly disruptive. This study is expected to be completed by the fourth quarter and will be a refresh from a similar 2019 security study, which examined future reliability standards, resource mix and load patterns, and resource requirements.
Chris Wentlent, of the Municipal Electric Utilities Association of New York State, asked if the study would be New York-specific or also investigate neighboring grid operators, including in Canada.
Myott replied that NYISO is considering including their neighbors in the study.
The last planned energy market project focuses on creating an operating protocol for the Long Mountain phase angle regulator (PAR) installation, a planned 345-kV intertie between NYISO and ISO-NE. The plan is to complete and vote on a joint operating agreement by the end of this year, though if discussions with ISO-NE extend beyond the third quarter, the project could be delayed.
An ongoing project relates to updating software to implement constraint-specific transmission shortage pricing, which would help NYISO to alleviate short-term constraints by dispatching suppliers more efficiently. The ISO plans to deploy these updates in October, after the relevant DER updates are finalized, and will file the previously approved project modifications with FERC in the first half of the year.
New Resource Integration Projects
Finally, Harris Eisenhardt, NYISO market design specialist, presented an overview for the new resource integration projects.
2023 new resource integration project overview | NYISO
By the end of this year, NYISO anticipates delivering a market design concept that will enable its DER participation model to be fully compliant with FERC Order 2222 requirements by incorporating any additional market features that were not included in the deployment scope.
Howard Fromer, who represents the Bayonne Energy Center, sought confirmation that FERC approved NYISO’s request to extend the deadline for DER deployment until 2026, which Eisenhardt confirmed, saying the ISO would spend the next three years scoping out the DER software, getting the market design finished and building out the deployment plan.
Another project that concerns the demand side to identify new ways that demand response and DER programs can be improved to increase consumer engagement in NYISO’s markets. The ISO believes that improving demand-side programs will enable consumers to assume greater control of their energy use and push New York toward zero emissions by better balancing increasing penetration of intermittent generation.
The ISO anticipates presenting a final report, which summarizes both external and internal stakeholder feedback and identifies gaps in existing programs, in the fourth quarter.
James W. Brew, principal at Stone Mattheis Xenopoulos & Brew, and Kevin Lang, partner at Couch White, both emphasized the importance of NYISO soliciting feedback from experienced individuals and talking directly with end-use consumers.
Finally, Eisenhardt discussed the project to assess whether storage resources can be considered transmission assets.
NYISO expects to share its findings during the fourth quarter, spending the earlier part of the year reviewing how other grid operators treat storage resources and discussing operating rules for market participation.
New York is moving to cut the cost of electricity supplied to commercial charging stations for electric vehicles.
The Public Service Commission on Thursday approved a multiphase package of incentives, tariffs and programs to reduce the impact of demand charges.
As an immediate solution, all investor-owned utilities are directed to implement a 50% rebate against traditional demand charges for public direct current fast charger (DCFC) sites.
Customers qualify if their charging station accounts for at least 50% of their maximum on-site electrical demand.
The order also implements commercial managed charging program with use-case-specific adders in the territories of the two downstate utilities: Consolidated Edison (NYSE:ED) and its subsidiary Orange & Rockland Utilities.
In the upstate territories of Central Hudson Gas & Electric (NYSE:FTS), National Grid (NYSE:NGG), New York State Electric & Gas (NYSE:AGR) and Rochester Gas & Electric, the 50% rebate is extended to all commercial EV charging use cases. The four utilities are also required to file commercial managed charging program proposals within 180 days.
As a near-term solution, the PSC order requires the utilities to file within 180 days a proposal for a phased-in rate solution that will replace the demand charge rebate and use-case-specific adders.
Additionally, the order directs the utilities to implement standby rate exemptions for customers who install energy storage systems to help manage their EV charging load.
The order also imposes semiannual reporting requirements on the utilities and creates a biennial review of the effectives of the cost-relief programs and tariffs contained in the order.
The PSC’s order stems from a 2021 change to state Public Service Law. A September 2022 white paper written by Department of Public Service staff, with comments submitted by the utilities and other stakeholders in response, form the basis for much of the order.
The aim is to reduce the operating cost barrier to rapid expansion of public EV charging infrastructure that would be posed by traditional demand charges.
The PSC order notes the inherently conflicting goals at play: The demand charge is a powerful incentive for customers to manage the load they impose on the electrical grid and also potentially a disincentive to wider public acceptance of EVs. But if the incentive is removed and customers do not manage their demand, utilities will have to pay for expensive infrastructure upgrades to accommodate it, and customer prices will rise as a result.
Also, it is impossible to predict when drivers will pull into a public charging station or how much of a charge their vehicles will need. So, planning or managing load is impossible, as well as antithetical to the very point of having public chargers.
Other utility customers will bear the expense of reduced-cost electricity to public charging stations via a surcharge with a one-year lag.
“Our determination to allocate costs among service classes using the transmission-and-distribution revenues allocator reflects the fact that all customers will benefit from the environmental and societal benefits of the transition to electric vehicles, which this order seeks to accelerate,” the PSC said in its order.
The commission will cancel the existing DCFC Per-Plug Incentive (PPI) program and use its unspent funds for a new program to incentivize EV charging demand management technologies. The order calls PPI an “unpopular … series of foibles” and says that “onerous eligibility requirements” similar to those of the program would undercut the demand charge rebate.
The order refers to the “chicken-and-egg” problems of this stage of EV deployment, in which more people need to buy EVs to fund the buildout of public charging infrastructure, and more public chargers need to be built before New Yorkers have confidence to purchase EVs in larger numbers.
“It is clear that the electric vehicle charging industry faces challenging economics under today’s market conditions, particularly in areas where electric vehicle adoption does not yet generate a sufficient level of sales to offset the utility costs,” PSC Chairman Rory Christian said in a statement. “Electric vehicle deployment will play a key role in meeting the dramatic carbon-reduction goals set forth in the Climate Leadership and Community Protection Act, and our decision today provides the industry with a level of operating cost relief that will accelerate investment.”
The Nuclear Innovation Alliance (NIA), a D.C.-based nonprofit think tank, is advocating a makeover of the U.S. Department of Energy to expand its research-and-development mission to include assisting developers in commercializing advanced reactors.
On Thursday the group released a 37-page report, “Transforming the U.S. Department of Energy: Paving the Way to Commercialize Advanced Nuclear Energy,” arguing that the future of nuclear energy are small modular reactors (SMRs) but that they will not be rapidly deployed without a federal push.
SMRs are factory-made, installed on-site and designed with fail-safe cooling systems. They are typically 100 to 300 MW, a fraction of the power output of the nation’s existing fleet of aging commercial reactors, most of which generate at least 1,000 MW.
New reactor designs must be approved by the Nuclear Regulatory Commission, which has approved only one so far, by Oregon-based NuScale Power. The company’s modules are rated at 50 MW each in a design configuration that could hold as many as 12, for a total capacity of 600 MW. NuScale has an agreement with Utah Associated Municipal Power Systems to build an SMR later this decade on the grounds of the Idaho National Laboratory.
NIA’s report argues that SMRs can be a vital part of the nation’s efforts to decarbonize U.S. power generation and are small enough and safe enough to be installed at the sites that once were occupied by coal-burning power plants.
In a webinar following the release of the report, Executive Director Judi Greenwald elaborated: “Our hope is that the recommendations in this report will better position DOE as a catalyst with a public-private partnership needed to reach full-scale commercialization.
“This is the moment to have this conversation. Over the past couple of years, especially the Energy Act of 2020, the Infrastructure Investment and Jobs Act [of 2021] and the Inflation Reduction Act [of 2022], Congress has provided substantial new direction and funding. Now it’s time for DOE, Congress and stakeholders to focus on effective implementation of these transformative policies through DOE transformation,” Greenwald said.
The report reasons that DOE “will need to coordinate across many segments of the industry” in order to quickly allow “deployment at an immense scale” and “at least double the domestic nuclear energy capacity that is online today.”
It argues that the department should develop an agency-wide plan and include advanced nuclear energy in its Energy Earthshots Initiative.
“This strategic plan would involve establishing an advanced nuclear energy Earthshot that integrates capabilities across DOE; leveraging recent legislation and DOE’s current and future advisory committees; assessing the viable pathways to solve climate stability and energy security issues; and developing a comprehensive national strategy for exporting advanced nuclear energy technology,” the report explains.
The plan would also require a new role for DOE as a critical partner working with private SMR developers, a significant expansion of the department’s long-time role, especially through its National Laboratories, as a pure research-and-development partner.
Finally, the report advocates that the White House appoint a senior director for civil nuclear energy to assist DOE in its new role, and that Congress increase the department’s funding for its expanded responsibilities.
Kathryn Huff, assistant secretary for DOE’s Office Nuclear Energy, said she appreciated NIA’s input.
“I think the work that you all put into this report is apparent in the nuance of some of the specific examples of what we could be doing to accelerate our transformation in DOE,” she said during the webinar. “And I think it really reflects a lot of understanding of where we are as DOE and where we should be and where we could be.”
Connecticut has officially launched the Innovative Energy Solutions Program, a “regulatory sandbox” aimed at rolling out new ideas for a decarbonized, affordable and equitable electric grid in the state.
The program, established in March of last year by the Public Utilities Regulatory Authority, will give out $25 million in funding each project cycle, with a maximum project award of $5 million.
The idea is in part to “break up the inertia of electric utility service in Connecticut,” PURA Chairman Marissa Gillett said back when the program was announced.
The utilities can take part too, however: They would be expected to put forward “innovative customer programs and/or tariff structures.” PURA gave the examples of an advanced critical peak pricing tariff for commercial customers, and the development of a “bring your own device program” to enhance demand flexibility.
Applicants can send in their ideas for innovating through an online portal, which opened Friday.
Eligible projects don’t have to be based in Connecticut, and the types of pilots the state is looking for cover a broad range: “products, services [and] programs that are ready to be tested and have the potential to provide widespread benefits to the grid and ratepayers.”
Once selected, the applicants will have 12 to 18 months to launch their projects and collect performance data.
PURA is holding an information session Tuesday for potential applicants to learn more about the program.
Two major offshore wind power developers are warning again of economic problems with projects off the New York and New England coasts.
Ørsted on Thursday notified investors that there would be a cost impairment of 2.5 billion kroner (roughly $365 million U.S.) on the 924-MW Sunrise Wind project in New York, its 50/50 venture with Eversource Energy (NYSE:ES), because of rising interest rates, higher capital costs and inflation.
And Avangrid (NYSE:AGR), which has said repeatedly that its 1,232-MW Commonwealth Wind project will be impossible to finance as negotiated, filed an appeal Thursday with the Massachusetts Department of Public Utilities, seeking once again to exit the power purchase agreements.
Inflation is hitting many areas of the renewable energy industry, particularly the offshore wind sector, which is forming nearly from scratch in the U.S. (See related story, Inflation Throwing a Wrench into Renewable Development.)
During a conference call Friday with Ørsted CEO Mads Nipper, financial analysts drilled in the company’s offshore projects broadly and Sunrise specifically.
Nipper said Ørsted is negotiating contracts for Sunrise in a very expensive environment, particularly for transportation and installation costs. Barring further increases in interest rates, he said, Ørsted does not expect 2023 impairments on other projects in its offshore portfolio, which were negotiated in less expensive environments.
An installation vessel is being built for Sunrise, Nipper added, and while it is a bit behind schedule, it should be ready in time to work next year.
Like Avangrid, Ørsted says it remains committed to its Northeastern offshore wind projects. It previously acquired the first commercial OSW project in the U.S., Block Island Wind in Rhode Island, and is a partner in the construction of the second, South Fork Wind in New York.
On Wednesday, a day before it quantified the financial obstacles facing Sunrise, Ørsted announced it had acquired Public Service Enterprise Group’s (NYSE:PEG) 25% share of Ocean Wind 1, giving it 100% ownership of the 1,100-MW project off the New Jersey coast. Nipper told analysts Friday that PSEG’s exit did not indicate the project was in trouble; rather, it was a strategic move to optimize tax credits.
The company said preliminary unaudited results show 2022 earnings from its worldwide offshore business down 9.5% from 2021, primarily because of delays to three projects and impacts from hedging. But it expects significantly higher offshore earnings in 2023.
Ørsted’s stock price dropped 8.7% in trading Friday.
The Commonwealth project has been unraveling for the last few months, with Avangrid saying it has negative net value as negotiated. The company has said it remains committed to the concept and would like to submit a viable bid on the project in Massachusetts’ next offshore wind solicitation.
The Massachusetts DPU has rejected Avangrid’s requests, first to pause its review of the power purchase agreements with three electric distribution companies, and then to dismiss the PPAs altogether. The companies meanwhile refused to negotiate any changes. (See Mass. DPU Orders Commonwealth Wind Project to Continue.)
In its appeal Thursday, Avangrid said the DPU’s orders are based on errors in law, unsupported by evidence, and arbitrary, capricious and an abuse of discretion.
Developers of another proposed Massachusetts wind farm — Mayflower Wind, phase 1 of which would deliver 405 MW — have cited the same financial pressures as Commonwealth but have not yet attempted to back out.
Mayflower, which previously was granted limited participant status in the Commonwealth proceeding because the two projects are interrelated, requested full participant status Thursday because of Avangrid’s latest motion.
MISO wants to exclude its intermittent class of resources from providing ramp capability by midyear.
The grid operator said last week that, in practice, dispatchable intermittent resources have not “assisted in ramping needs,” referring to wind generation that’s often trapped behind transmission congestion.
The RTO’s ramp capability product’s current design doesn’t account for a resource’s deliverability, staff said, adding that ensuring a deliverable ramp product will produce better price signals.
Senior Market Engineer Chuck Hansen said during a Market Subcommittee meeting Thursday that MISO wants to file with FERC in February to disqualify intermittent resources from ramp eligibility by June.
Some stakeholders argued that wind can provide upward ramping and said MISO seems to be treating certain resource types unfairly because of system congestion.
Hansen said the action is prudent in today’s operating environment, but it doesn’t have to be a “forever change.” He said staff can revisit ramp eligibility as the fleet evolves.
In early December, Clean Grid Alliance’s Natalie McIntire pointed out that ramp-capable hybrid resources with storage capability currently are forced to register as dispatchable intermittent resources because MISO doesn’t yet have a hybrid resource market participation model.
MISO also wants to disable its downward ramp capability product by setting the product’s demand curve price to zero. The grid operator overwhelming needs up ramping, not down ramping.
Hansen said devaluing downward ramping is a “way of turning it off without throwing it away.”
“We’re not ready to remove it permanently,” he said. “But this is a way to disconnect the clutch, to use a metaphor.”
Hansen said staff will still track down ramping in its markets but won’t price it. He said from 2018 to 2022, MISO paid $542.80 in real-time payments for the downward product.
“It’s not that it has not been sending useful pricing signals. It’s really that it’s been sending no pricing signals,” Hansen said in December.
A MISO analysis showed that if it priced its downward ramp capability at zero, only 18 of 70,000 five-minute market settlement intervals would have been short on down ramp in the first eight months of 2022.
“We have an abundance of ability to ramp down. It’s physics; it’s always easier to ramp down,” Hansen said. “We don’t want to pay for something that’s inherent to the system.”
Less than a year after debuting availability-based accreditation, MISO is proposing to reformulate how it accredits its resources.
Stakeholders aren’t happy.
MISO wants to accredit all resources based on their performance during predefined resource adequacy hours, or tight operation conditions. It will then adjust unit accreditation by a capacity value determined by loss-of-load expectation. The equation’s LOLE piece would replace the grid operator’s use of unforced-capacity values that rely on forced outage rates.
The new design is also intended to replace MISO’s current accreditation method for renewable energy, which uses a unit-level effective load-carrying capability calculation based on a peak hour contribution. It would also have staff fashioning new planning reserve margin requirements based on coincident loss-of-load hours rather than coincident peak load hours.
Jordan Bakke, director of policy studies, told stakeholders during a Resource Adequacy Subcommittee (RASC) meeting Wednesday that MISO’s goal is to create a single, “comprehensive resource adequacy accreditation reform” filing with FERC by next year, though the requested effective date is up for debate.
“We’re not trying to seek immediate implementation,” he said.
Bakke said the grid operator wants to shift its accreditation philosophy from “peak load-based” to “risk-based” under a sampling of the system’s riskiest hours.
Multiple stakeholders said they had serious concerns with the proposal, arguing that a direct loss-of-load approach should be applied to all resources. They contended a loss-of-load approach will only rely on a limited number of forecasted hours that are too small a sample to use for accreditation.
Invenergy’s Sophia Dossin asked how the approach will help MISO. She said a forced-outage value is broader and based on more reliable historical — rather than forecasted — information.
Bakke said a probabilistic loss-of-load approach is better suited for the tighter operating reality MISO is facing. He said the past is not an indication of the future conditions and resource mix.
Staff said using a direct loss-of-load calculation produces similar accreditation values to unforced capacity calculations.
“My reaction to that is, ‘So what?’ That’s almost a tautology,” resource adequacy consultant Michael Milligan said.
WEC Energy Group’s Chris Plante wondered whether MISO and stakeholders would be better served if they reexamined the tariff’s Schedule 53, which defines the RTO’s seasonal accreditation calculation.
“I think we’ve gone in the opposite direction of what stakeholders have intended,” he said. “I think we need to ask what it is we want out of our resource adequacy construct. Do we want it to tell us when to construct generation or do we want it to tell us the reliability value of the existing fleet? And I think it should be the latter.”
“I think what you’re hearing in this meeting today is there’s not support for this proposal. And yet, you’re moving forward with it anyway,” Clean Grid Alliance’s Natalie McIntire said.
McIntire asked why staff is proposing to change thermal resource accreditation so soon after winning approval of its availability-based method. Were they revisiting accreditation because they “didn’t get it right,” she asked.
“We need more. We need more here from MISO. And I think we need to take a step back and see what’s needed from the stakeholder process … rather than MISO completely driving this train,” McIntire said.
“I share what a lot of other stakeholders are feeling in this process: Are we going to be railroaded?” Southern Renewable Energy Association’s Andy Kowalczyk said.
Staff said they will devote more time to the topic during future RASC meetings.
FERC last year approved MISO’s seasonal capacity accreditation, which assigns accreditation based on a generating unit’s past performance during expected tight conditions. That accreditation only applies to MISO’s thermal generators; MISO has yet to file a separate, availability-based accreditation for its renewable generators. (See FERC OKs MISO Seasonal Auction, Accreditation, MISO Adding Availability-based Renewable Energy Accreditation.)
During a Jan. 17 discussion before the subcommittee, market participants complained about the difficulty of making minor adjustments to planned generator outages without taking hits to their resource accreditation. Representatives from Minnesota Power and WEC Energy Group said they have either started an approved outage early or extended it by a few days, only to entirely lose their outage exemption and negatively impact their accreditation.
Stakeholders said MISO is unfairly decrementing their availability-based accreditation for the outage’s entirety and not for just the few days tacked on. They asked staff to rectify the situation and make it easier to modify existing planned outages in MISO’s nonpublic interface.
