MISO delivered an incomplete summer readiness report Thursday to allow staff to digest the results of the RTO’s first seasonal capacity auctions.
J.T. Smith, MISO executive director of market operations, said the monthlong delay in the Planning Resource Auction left the RTO without the capacity data it gleans from the results and unable to prepare its seasonal resource assessment.
“It’s generally an attraction to this meeting,” he told stakeholders during a teleconference Thursday.
MISO posted the results late Wednesday, showing sufficient capacity across all seasons in all zones, which diminish the chances that the RTO anticipates emergency operating procedures this summer. (See related story, 1st MISO Seasonal Auctions Yield Adequate Supply, Low Prices.)
Smith said MISO will present its usual summer assessment at the Reliability Subcommittee’s meeting Tuesday.
He said that though the assessment might show a chance of an emergency declaration, “emergencies in MISO aren’t necessarily emergencies.” Smith said the RTO usually has about 12 GW of load-modifying resources that clear in the capacity auctions but aren’t available unless the grid operator calls for emergency procedures.
“I want to emphasize that emergency declarations in MISO don’t mean we’re on the cusp of load shedding,” Smith said.
But he also said MISO had been expecting more solar generation additions to the system than what ultimately will begin operations in time for summer. About 41 GW worth of resources with signed generator interconnection agreements are prevented from commercial operations because components are tied up in supply chain issues, Smith said.
Lacking capacity data, MISO staff nonetheless presented all other summer system outlooks during the call, predicting a decent chance for June heat, a rainy summer for the Midwest and low chances for a hurricane in the Gulf of Mexico.
Staff also said they are predicting a second summer in a row where the hottest days are clustered early in the season. Last summer, the MISO footprint saw nine days in June and July when the systemwide temperature exceeded 90 degrees Fahrenheit. MISO said the hottest — and riskiest — days last year were “frontloaded” in June.
MISO meteorologist Adam Simkowski said that with an El Niño climate pattern developing as predicted, the RTO is anticipating a “near- to slightly below-normal hurricane season in the Atlantic Basin.”
Fellow meteorologist Brett Edwards said that while there was a dry pattern across much of the footprint last year, above-normal precipitation is expected this year across MISO Midwest.
Smith said it’s useful to assess even uneventful summers like last year because equal preparation goes into system events and non-events alike.
“Luckily, 2022 was generally a calm summer,” Smith said, adding that hurricane activity in the South was low, and MISO was able to successfully navigate the June heat wave.
“We came close, but we didn’t quite get to that level,” MISO Senior Adviser Mike Mattox said of the lack of maximum generation emergency declarations last summer. June 21 marked the hottest day systemwide in more than a decade, he said.
MISO risk manager Congcong Wang said the RTO has rolled out an operations risk assessment process this year to better manage “increasing uncertainty and variability” occurring on the system. Wang said MISO will assess summer risks from weeks to hours ahead using analytics and meteorological data.
Finally, MISO planner Dalton Daughtrey said an RTO analysis showed that all major transmission constraints already have mitigations in place for this summer. Daughtrey said MISO will monitor future transmission outages that may be necessary as construction ramps up on its first long-range transmission plan portfolio. Most of the $10 billion portfolio used existing rights of way for the new line work.
ALBANY, N.Y. — Facing the possibility that it will not be able to generate enough electricity with renewable technologies such as wind and solar, New York is considering adding more controversial forms of power generation to its climate protection strategy.
The state’s Public Service Commission on Thursday began a review process that could lead to a greater role for hydrogen, bioenergy, nuclear power, carbon capture and other technologies viewed with suspicion or outright hostility by the environmental advocates who have pushed for climate legislation (15-E-0302)
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The PSC ordered staff to identify technologies that might work for New York, started a two-month public comment period, and directed that at least one technical conference on the subject be held within the next four months.
New York codified one of the most ambitious decarbonization schedules in the nation in 2019, with the landmark Climate Leadership and Community Protection Act (CLCPA). It sets a goal of 70% renewable energy by 2030 and a 100% zero-emission grid by 2040.
Enough projects are now in the pipeline to reach 66% renewable, but many are unlikely to ever reach the construction stage. And those that are built will not produce power when the sun does not shine or the wind does not blow.
The CLCPA scoping plan completed in December 2022 relies on other technologies maturing to a scale and price that will make the 2040 goal attainable.
But the PSC order notes that several studies indicate current renewable resources may not be able to reliably replace fossil fuels — that existing technology is incapable of meeting the growing needs of the grid.
The order also notes that neither state Public Service Law nor the CLCPA define “zero-emissions” technologies.
‘Magical’ and ‘Scary’
Thursday’s order incorporates some aspects of a petition submitted to the PSC in August 2021 by a power industry trade association and two labor organizations: the Independent Power Producers of New York, the New York State Building & Construction Trades Council and the New York State AFL-CIO.
The 12-page petition urged the PSC to consider zero-emitting technologies that are not renewable, and to define zero-emissions energy systems as those that do not lead to a net increase in greenhouse gas emissions.
Comments included a 32-page rebuttal by the Sierra Club and 24 allied groups, shooting down the petition detail by detail.
More recently, NYISO has warned of narrowing reliability margins as fossil fuel plants are retired and replaced by renewable energy generated by intermittent resources. NYISO calculates the New York grid would need 27 to 45 GW of dispatchable emissions-free resources under the CLCPA scenario.
That is potentially more than the entire currently installed generation capacity in New York state — 37 GW — and there is no technology identified to fulfill that need.
IPPNY President Gavin Donohue, who helped draw up the scoping plan and voted against its adoption, has railed against what he calls the reliance on magic in the planning process — the belief that something will come along in time to affordably fill the gap.
He told NetZero Insider on Thursday that the PSC order does not solve this problem, but he is glad to see aspects of the 2021 petition incorporated in it.
“I see it as incremental progress,” Donohue said. “Nonetheless, it’s better than nothing. I’m appreciative that after two years people are taking this issue seriously.”
Whatever technology the PSC decides on, he said, it needs to be tested, proved, abundant, affordable and be available soon, as things take a very long time to build in New York.
“How we get to zero by 2040 is really magical, and at this point scary, because the technology doesn’t exist.”
The vote by the PSC was unanimous.
“The Commission’s action reaffirms efforts to ensure New York has the needed clean-energy resources to replace existing fossil fuel-fired power plants,” PSC Chair Rory Christian said in a news release. “I am proud that New York continues to lead by advancing important clean energy initiatives, such as the one commenced today.”
Two commissioners who frequently object to the process by which the regulatory agency is overseeing the energy transition — and to the costs it is authorizing — weighed in on the theme of wishful thinking.
“The order, maybe for the first time, clearly, expressly identifies that we are realizing the challenges of getting to where we need to be [and] the false narrative around that,” Commissioner Diane Burman said.
There is a need to get under the hood, she said — not to halt the transition, but to be good stewards of regulated industries and their ratepayers’ dollars.
Commissioner John Howard said much of the CLCPA is based on hopes, dreams and good intentions. “This process that’s outlined is much more reality-based. This is the entity that needs to be the reality-based decision maker. It doesn’t seem to be emerging from other state agencies and authorities. It’s our job to say what can work and what can’t work.”
The Natural Resources Defense Council released a study Thursday finding that the pace of resources clearing PJM’s backlogged interconnection will challenge the ability for states to meet their renewable portfolio standards.
“States throughout PJM set ambitious RPS goals to cut emissions, lower costs and boost reliability, but years of delays at PJM threaten to derail these plans,” Dana Ammann, policy analyst at NRDC and the study’s lead author, said in an announcement of the report. “PJM needs to work with the states to reach their renewable goals and do its part to build the clean grid we need. Without changes, PJM will likely fall short of state renewable targets.”
Drawing off PJM estimates of the number of projects that will clear the queue and enter development, the report projects that aggregate RPS goals for states within the PJM footprint will overshoot available renewable supply between 2023 and 2026, while individual states could struggle to procure enough clean energy to meet their goals even longer. Ammann said the study considers only existing RPS and policies; future legislation or regulations could further limit states’ ability to meet their goals.
“There is little doubt that RPS targets and broader policy goals will be constrained by the speed and efficiency of the interconnection queue,” the report states.
PJM spokesperson Jeff Shields said an overhaul of the way new projects are studied will be implemented this summer to speed projects through the queue faster, and that the RTO is committed to continuing to work with stakeholders to identify ways to continue to improve the process. (See FERC Approves PJM Plan to Speed Interconnection Queue.)
“PJM advanced landmark reforms to speed the interconnection queue that were overwhelmingly approved by PJM stakeholders and the Federal Energy Regulatory Commission. These reforms will begin this summer, and by 2026 we expect to study the interconnection of more than 200,000 MW of mostly renewable resources,” he said. “Currently there are 44,000 MW of mostly renewable generation resources that have cleared the PJM study process but have yet to be built due to factors unrelated to PJM, including supply chain and siting.”
NRDC Senior Advocate Tom Rutigliano said PJM needs to take action in the short term to allow resources to enter development. Easing the ability for generation owners to transfer their capacity interconnection rights from deactivating fossil fuel resources to new renewable generators, a move discussed during last week’s Planning Committee, is one change that could expedite development. In the long term, he said, a new approach to planning transmission upgrades to support state goals and new developments is needed.
The State Agreement Approach presents one avenue for states to skirt the queue to push through projects to meet their RPS goals, Ammann said, citing New Jersey’s 7,500 MW of approved offshore wind projects. The report also states that New Jersey has been leading the way in developing small-scale resources that can bypass PJM’s queue.
“Growth in small-scale solar (i.e., distributed solar) is especially important for meeting RPS in states with strong solar incentives. For example, in New Jersey, existing small-scale solar projects and forecasted distributed solar growth represents 69 to 85% of total annual solar energy available in the state from 2023 to 2030,” the report states.
Though distributed energy resources are not subject to RTO interconnection queues, the report notes they do go through utilities’ interconnection processes, which can vary in their bandwidth for clearing projects. It points to Xcel Energy, which has more than 300 projects awaiting approval, and cited an analysis finding it would take 260 years for Xcel to clear its queue at its current pace.
“Utilities have been generally slow to keep up with demand and upgrade the distribution network to accommodate distributed resources,” the report says.
The states with the toughest road ahead could be those requiring that their clean energy targets be met with resources sited in-state, such as the Illinois Climate and Equitable Jobs Act (CEJA). The report states that the legislation will both limit Illinois’ ability to procure renewable energy credits (RECs) from out-of-state resources and tighten the REC supply for neighboring states.
“As the supply and market for RECs tighten, CEJA may create tension between resources used for Illinois’ future targets and those used to meet regional demand,” the report states.
In addition to limiting how quickly projects can be built, the report states that the long timeline for new projects can limit their ability to take advantage of existing incentives, which may no longer be available when projects are ready to be built, increasing investor uncertainty and leading to rising costs. It cites a Lawrence Berkeley National Laboratory study finding that costs for projects in the interconnection queue have been rising. Rutigliano said projects submitted after Oct. 1, 2021, are unlikely to be studied until 2026. (See Berkeley Study Finds Rising PJM Interconnection Costs.)
“These factors may lead to much needed new renewable generation being delayed, not developed at all or unable to take advantage of new incentives under the” Inflation Reduction Act, the report states.
The Texas Reliability Entity’s Board of Directors voted to approve the organization’s 2024 business plan and budget, along with accepting its 2022 financial statements, at their open meeting on Wednesday.
The regional entity’s 2024 budget includes $19.2 million in statutory expenses, up 8% from the 2023 budget. Texas RE attributed the increase to the addition of three full-time equivalent staff in the Compliance Monitoring and Enforcement program, the Reliability Assessment and Performance Analysis program, and the Information Technology department, along with a 10% increase in employee health benefit expenses.
Meeting and travel expenses are also expected to increase by $29,000, or 7.7%, over the 2023 budget. The operating expenses budget is shrinking by 4.5%, a total that includes decreases of 3.5% in consultant and contractor costs and 7.5% in rent and maintenance on the RE’s new office space.
Texas RE’s statutory assessment is set to grow to $18.8 million next year, an increase of 9.5% from the 2023 assessment.
Henry Previews Reliability Assessment
Texas RE’s upcoming Assessment of Reliability Performance will reiterate recent warnings about the reliability performance of inverter-based resources such as wind and solar, according to Mark Henry, the organization’s director of reliability services and registration.
The RE produces the assessment each year to supplement NERC’s State of Reliability report. Like NERC’s report, the Assessment of Reliability Performance reviews the performance of the Texas grid over the previous year. Henry observed that despite NERC’s efforts to survey the entire continent, Texas grid planners felt that “things that happened in the East tend to predominate” the ERO’s report. As a result, the RE felt it would help local utilities to highlight regional issues.
This year’s document will include events such as the 2022 Odessa disturbance, in which the Texas interconnection lost more than 2.5 GW of solar PV and synchronous generation a bit more than a year after a similar event in the same area. (See NERC Repeats IBR Warnings After Second Odessa Event.) It will also look at nationwide trends such as the rise in gunfire damage to electric facilities, which Henry said is occurring in Texas as well despite not being as widely publicized as events such as last year’s rifle attacks on substations in North Carolina.
Discussing reliability trends in the region more broadly, Henry acknowledged that the RE once again fell within the brightly shaded section in NERC’s recently released 2023 Summer Reliability Assessment, referring to the ERO’s practice of shading regions at higher risk of suffering electricity supply shortfalls in orange or red rather than the gray of low-risk areas. (See NERC Warns of Summer Reliability Risks Across North America.)
“We don’t feel like there’s anything immediately lacking in what we do, but … after [Winter Storm] Uri everybody understands there are situations that couldn’t have occurred 20 years ago, but we need to be cognizant and not ignore them anymore,” Henry said.
Zero-trust, Cybersecurity’s New Focus
Kenath Carver, Texas RE’s director of cybersecurity outreach and CIP compliance, told the Member Representatives Committee earlier in the day that the federal government’s current National Cybersecurity Strategy is emblematic of a “paradigm shift” in the cybersecurity sector.
“We’re talking about what’s inside the networks … the bad actor coming in,” Carver said. “Well, now we’re talking about the center of a Tootsie Pop, the center of the Earth, the core, where we need to be a little bit more cognizant on what’s going on in our networks. It doesn’t have to be a bad actor, right?”
He said the government and FERC are committed to zero-trust architecture, defined as a strategic approach that secures an organization by eliminating implicit trust and continuously validating every stage of a digital interaction. The commission in January issued Order 887, directing NERC to study new reliability standards for internal network security monitoring within a trusted CIP-networked environment (RM22-3).
“Zero-trust is basically you’re not trusting yourself,” Carver said. “We could be doing things internal to our networks that may be causing some issues or accidentally causing an issue. Because if someone got in, how would we know? Are we monitoring that? Are we alerting that? There’s a check and balance with everything that you do internal into your network.”
As part of the study, NERC is determining whether to apply internal network security monitoring to low-impact cyber systems, Carver said.
Shape market forces to drive security and resilience.
Invest in a resilient future.
Forge international partnerships to pursue shared goals.
The MRC also approved the NERC Standards Review Forum revised charter. The forum’s members added clarification around periodically reviewing its membership to ensure an accurate roster of members and revised its non-disclosure agreement for guests to its closed sessions.
The New England States Committee on Electricity (NESCOE) pressed transmission owners Thursday to increase the transparency of their asset condition projects and incorporate them into ISO-NE’s planning process.
In a presentation to the Planning Advisory Committee (PAC), NESCOE also called for more information on spending plans and assumptions used in estimating project costs. NESCOE also suggested the RTO create guidelines around right-sizing transmission projects and integrating asset condition project planning into the RTO’s regional planning process.
Thursday’s discussion came in response to NESCOE’s Feb. 8 memo to the New England Transmission Owners (NETOs), which called for maximizing the use of the region’s transmission, saying that “modernizing planning processes and protecting system reliability will be fundamental in the transition to the clean energy future.”
Asset condition projects are undertaken by transmission owners to maintain transmission infrastructure that is aged or damaged. While ISO-NE directs the regional transmission planning process for transmission reliability projects, asset condition projects are not included in this process and are therefore subject to less scrutiny from other stakeholders.
NESCOE has previously highlighted how costs associated with asset condition projects have been trending upward in recent years, with over $3 billion in projects currently proposed, planned or under construction. Asset condition project costs are eventually passed on to ratepayers.
“The process by which asset condition projects are developed by NETOs, reviewed by ISO-NE, states and the public, approved for rate recovery, and considered in overall transmission system needs and planning is antiquated and ultimately, inadequate,” NESCOE wrote in its February request to reassess the planning process. “It is the right time to implement planning process improvements to protect consumers from excessive costs and to maximize the use of all transmission assets by moving Asset Condition Projects from the current siloed, notice-based method into meaningful and holistic transmission system planning.”
In a memo sent to participants prior to the PAC meeting on behalf of consumer advocate members of NEPOOL, Synapse Energy Economics argued that the current process risks putting unnecessary burdens on ratepayers.
Asset condition spending since 2016 | NESCOE
“Asset condition spending now constitutes the majority of new regional transmission investments and is projected to continue increasing,” Synapse wrote. “Ratepayers ultimately bear the costs for asset condition projects, but unlike other investments that have cost reviews built into approval processes, there is little to no meaningful check on the prudency of asset condition spending.”
NESCOE wrote in its February memo that modernizing planning procedures is also important in anticipation of increased reliance on clean energy technologies in the energy transition.
“The question of whether and to what extent to ‘right-size’ transmission to account for broader potential needs will arise more often in the future as the region considers transmission expansion to account for clean energy resources and state decarbonization requirements,” NESCOE wrote.
In its March 2 response to NESCOE’s memo, the New England Transmission Owners expressed their support for a review of the planning process while emphasizing their commitment to reliability and transparency. “Specifically, we agree that there is an opportunity to better integrate asset condition planning with longer-term planning for transmission to meet future system needs,” they wrote.
At the PAC meeting, NESCOE asked for feedback from stakeholders to be submitted to pacmatters@iso-ne.com by June 2.
Asset Condition Projects
Also at the PAC meeting, National Grid and Eversource outlined their plans to spend a total of $492.4 million on infrastructure updates and repairs, while New Hampshire Transmission detailed a projected $14 million cost increase for its Browns River capacitor bank station.
New Hampshire Transmission, a subsidiary of NextEra Energy, said that the cost estimate for the capacitor bank station it is building near the Seabrook nuclear plant in Southern New Hampshire has more than doubled, increasing from $8.9 million to $22.9 million. The company said that most of the projected increase — $10.9 million — is because of additions to the scope of the project, with an additional $3.1 million increase resulting from rising costs, including changes in commodity prices.
National Grid projects that the relocation of its substation in Adams, Mass., will cost $133.5 million, with an expected in-service date of early 2030. The current substation is located in a wetland area along Hoosic River and is frequently subject to flooding events. The proposed new location is at a higher elevation next to a mobile home neighborhood in North Adams.
Eversource expects to spend a cumulative $358.9 million on a series of transmission infrastructure rebuilds and replacements in New Hampshire. In Northern New Hampshire, the company would replace wood structures with new steel structures and install optical ground wire on 115-kV lines B112, Q195 and U199, with respective in-service dates of late 2024, late 2026 and mid-year 2026. The company would also replace wood structures with steel structures and replace 49 circuit miles of shield wire with optical ground wire on 115-kV and 345-kV lines in Southeastern New Hampshire, with in-service dates ranging from late 2023 to early 2024.
Most regions of the North American grid remain at elevated risk of supply shortfalls this summer, NERC said in its 2023 Summer Reliability Assessment released Wednesday, with an organization official warning the media that “the system is close to its edge.”
In presenting the assessment, John Moura, director of reliability assessment and performance analysis, and other NERC staff stressed the impact on reliability of changing weather patterns, combined with the transition to renewable energy sources that has left some areas relying on weather-dependent technologies like wind and solar power. In a video released alongside the report, NERC said that “generator retirements continue to increase the risks associated with extreme summer temperatures.”
“With the grid transformation in full force, the retirement of conventional generation remains highly concerning,” Moura said. “That’s something that we’d really like to focus on in the coming years as we … respond to environmental rules [and] enable a cleaner grid, but also maintain reliability every step of the way.”
Weather Driving Demand
NERC publishes the assessment each year to identify potential regional reliability issues and topics of concern, covering the June to September timeframe. This year MISO, Ontario and New England, SPP, ERCOT, SERC’s Central subregion — comprising all of Tennessee and portions of Georgia, Alabama, Mississippi, Missouri and Kentucky — and the U.S. Western Interconnection all “face risks of electricity supply shortfalls during periods of more extreme summer conditions,” the assessment said.
According to the National Weather Service, above-normal temperatures are likely across most of the continental U.S. and Alaska, while most of Canada is expected to see normal or below-normal temperatures.
The assessment marks an improvement in one regard from last summer because MISO is no longer assessed at high risk, which indicates the potential for insufficient operating reserves in normal peak conditions. NERC said the reduced risk level is because of higher firm import commitments coupled with lower forecasted demand for the region, though its resources are also projected to be lower than last year. MISO’s anticipated reserve margin has increased to 23% this year, from the 21% predicted for summer 2022.
Resources are also expected to be lower this year in New England and Ontario, though still adequate for normal peak demand, confirming the regional entity’s own summer assessment released earlier this month. (See NPCC Warns of Tight Summer Margins in Ontario.) NERC warned that “generation and transmission outages will be increasingly difficult to accommodate” in Ontario for the foreseeable future because of generator retirements, especially among the province’s nuclear fleet.
NERC also expressed concern that utilities would be “unable to reschedule certain outages” during summer, as the Northeast Power Coordinating Council suggested in its assessment. The ERO said that Ontario might need to rely on as much as 2,000 MW of non-firm supply from other areas, along with “additional operating actions,” though NPCC said the province would likely need “only limited use” of its operating procedures during the summer.
SERC-Central has seen its forecasted peak demand rise by more than 950 MW since 2022, with no accompanying growth in anticipated resources. However, while the subregion’s prospective reserve margin is significantly lower than last year as a result, entities reported to NERC that they expect to “address unexpected short-term issues by leveraging diverse generation portfolios and spot purchases from the power markets when necessary.”
IBR Issues Continue in Texas
Mark Olson, NERC | NERC
For Texas, the report’s authors noted that the growth of inverter-based resources (IBRs) in the region continues to create concerns around “system stability and strength,” along with rising curtailments of energy production because of transmission constraints, frequently at solar sites. The ERO has issued multiple warnings about the reliability of IBRs in recent years after events like the Odessa disturbances in 2021 and 2022, when the Texas Interconnection lost multiple gigawatts of solar PV and synchronous generation. (See NERC Repeats IBR Warnings After Second Odessa Event.)
Mark Olson, NERC’s manager of reliability assessments, also observed that the region’s growing use of solar generation carries additional risks because of the mismatch between solar PV sites’ most productive time in the early afternoon and the period of greatest demand later in the day. Without dispatchable generation, utilities may find themselves operating closer to the edge than the numbers would indicate at first glance.
In WECC’s U.S. footprint, NERC warned that while resources in the interconnection are sufficient to support normal peak demand, a wide-area heat event could create problems for multiple subregions that normally rely on regional transfers to meet peak demand when solar production falls off. In addition, the assessment noted the risk of wildfires to the transmission network, which can limit the transfer capacity and lead to localized load shedding.
North American seasonal fire assessment for May through July 2023. | NERC
Olson also noted that while California’s hydroelectric system has experienced some relief from snowmelt refilling reservoirs, it is too early to tell whether this supply will continue to aid the region in late summer.
“Higher temperatures now can lead to a lot of melt early on, [but] much of the summer risks in the West tend to be later in the season when hydro is normally starting to be lower. So it’s harder to project how the current rainfall and snowpack may play out later into the season,” Olson said.
Supply Chain, Spare Parts Issues
Other potential reliability issues noted in the report include low inventories of replacement parts, such as distribution transformers, that could delay restoration of power following hurricanes and severe storms. Additional supply chain issues, along with labor shortages, could cause challenges for maintenance, summer preparedness and new resource additions.
The assessment also noted that EPA’s Good Neighbor Plan, which will require significant reductions of emissions at power plants and industrial facilities in 23 states, will likely limit the operation of coal-fired generators that are currently used for dispatchable generation. (See EPA Good Neighbor Plan Expected to Accelerate Coal Plant Retirements.) NERC recommended that entities familiarize themselves with the plan’s electric reliability provisions and be prepared to “act to preserve generation resources … to support periods of high demand.”
Industry groups seized on the assessment’s warnings about coal retirements as ammunition in their arguments against both the Good Neighbor Plan and EPA’s more recent proposals for carbon dioxide emission standards at power plants. (See Regan: New EPA Standards Designed to not Jeopardize Grid Reliability.) America’s Power, which represents coal-fired generators, said in a statement that retiring coal plants “will needlessly expose consumers to potential power outages,” while Jim Matheson, CEO of the National Rural Electric Cooperative Association, said that “America’s ability to keep the lights on has been jeopardized” by growing demand and restrictions on supply.
“American families and businesses expect the lights to stay on at a cost they can afford. But that’s no longer a guarantee,” Matheson said. “Nine states saw rolling blackouts last December as the demand for electricity exceeded available supply. … Absent a major shift in state and federal energy policy, this is the reality we will face for years to come.”
The results of MISO’s inaugural seasonal capacity auctions, released late Wednesday, showed sufficient supply for the 2023/24 planning year, with prices ranging from $2/MW-day in winter, to $10/MW-day in summer and spring, and $15/MW-day in fall.
The RTO’s first set of concurrently conducted seasonal capacity auctions is a far cry from last year’s annual auction, which cleared all of MISO Midwest at the nearly $240/MW-day cost of new entry (CONE), signifying a critical need to build resources. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)
This year, all zones were shown to have enough capacity on their own. Even MISO’s external resources zones followed suit. However, Zone 9 in Louisiana and southeast Texas experienced price separation to meet its requirements and cleared at $59.21/MW-day in fall and $18.88/MW-day in winter, the only departure from the otherwise uniform clearing prices.
The RTO said the mostly flat prices were a function of adequate supply this year. It entered the auctions with a 133-GW summer planning reserve margin requirement systemwide. The Midwest region was able to turn its previous deficit around through a combination of “lower demand, new generation, delayed retirements, additional imports and higher accreditation.”
While wind, gas and solar units in the Midwest were able to increase their accredited capacity values by nearly 2 GW, the region’s coal resources lost 924 MW in accredited capacity owing to MISO’s new availability-based accreditation process that assigns thermal units value based on past performance and anticipated availability during predefined risky periods. (See FERC OKs MISO Seasonal Auction, Accreditation.)
2023-24 Planning Resource Auction clearing prices by zone and season | MISO
The grid operator said members offered capacity in the Midwest that exceeded the summer planning reserve margin by 4,760 MW, compared to the 1.2-GW deficit uncovered in last year’s auction.
On the other hand, MISO South offerings declined this year. Though the subregion still beat its summer requirement by 1,723 MW, it was not as robust as last year’s 2.8-GW surplus. MISO said the South’s natural gas, nuclear and other generating units lost a little more than 1 GW in accredited capacity through the new accreditation process.
MISO’s Independent Market Monitor has reviewed and certified the auction results, finding no exercise of market power.
The RTO said the adequate supply this year is not indicative of “continued risks posed by the portfolio transition.” It said its move to seasonal requirements reduced the summer planning reserve margin. It also said its lower load forecast this year might become an anomaly, so members cannot postpone their planned generation retirements indefinitely. Projects continue to show a “continued decline in accredited capacity even as installed capacity increases,” MISO said.
Since last year, MISO Midwest has retired almost 1.2 GW worth of coal, while MISO South has retired about the same amount from its natural gas fleet.
The grid operator said it continues to need “urgent reforms” to its resource adequacy and market design to ensure reliability.
Entergy’s operating companies have challenged MISO’s seasonal capacity market at the D.C. Circuit Court of Appeals (22-1335). They are asking the court to review FERC acceptance of MISO’s availability-based capacity accreditation for thermal resources, the timeline to move to the seasonal market and the 120-day advance notice requirement for planned outages, among other elements of the commission’s order.
NV Energy will keep looking for resources to replace its coal-fired North Valmy Generating Station, scheduled for retirement in 2025, after Nevada regulators shot down the utility’s plan for a $466 million battery storage system.
The Public Utilities Commission of Nevada (PUCN) voted 3-0 last week to reject the project. The battery storage system was part of NV Energy’s fourth amendment to its 2021 integrated resource plan (IRP). The commission approved the amendment in part, but denied some components.
NV Energy had planned to replace capacity lost from the North Valmy coal plant closure with the Hot Pot and Iron Point solar-plus-storage projects. The 522-MW North Valmy plant, in Northern Nevada, is NV Energy’s only remaining coal-fired power plant.
Hot Pot and Iron Point together would provide 600 MW of solar paired with 480 MW of battery storage. In January 2022, PUCN approved NV Energy’s plan to buy Hot Pot and Iron Point from developer Primergy Solar.
But in its proposed IRP amendment, NV Energy said that due to supply-chain issues, Hot Pot and Iron Point are “no longer expected to move forward as previously approved.”
The 200-MW Valmy battery system was intended as a substitute for Iron Point and Hot Pot. NV Energy acknowledged the four-hour battery system wouldn’t be a total answer to the North Valmy coal plant closure, but said more resources could become available in Northern Nevada in the future.
But the commission wasn’t ready to give up on Hot Pot and Iron Point, saying NV Energy had “provided limited evidence” about the projects’ status.
“The commission finds it premature and unreasonable to approve the $466 million Valmy BESS investment as a cost-effective replacement for the Valmy coal plant without all the necessary facts,” the order stated.
The commission directed NV Energy to come up with a “complete solution” for the Valmy retirement in the next amendment to the 2021 IRP, or in its 2024 IRP, whichever comes first. The utility said it would file a fifth IRP amendment over the summer.
PUCN also asked for a thorough analysis of financial impacts of each potential solution for the Valmy closure.
And the commission wants details on “federal and state limitations on continued operations of the Valmy coal plant and associated costs.”
Another issue, the commission said, is whether NV Energy or its customers are entitled to damages resulting from delays in the Hot Pot and Iron Point projects.
Postponed Retirements
In another part of the fourth amendment to its 2021 IRP, NV Energy proposed a 400-MW gas-fired peaker plant in Southern Nevada, which PUCN approved in March. (See Nev. Regulators OK Controversial Gas-fired Peaker.)
NV Energy also asked to postpone retirements of several gas-fired plants by five or 10 years. The commission approved the extensions and, in some cases, postponed the retirements even further. That includes the Silverhawk and Higgins generating stations, for which NV Energy had proposed a 2044 retirement date. Instead, PUCN set a 2049 retirement date, in recognition of the state’s 2050 target for economywide net-zero greenhouse gas emissions.
“At a time when planning to meet the energy needs of customers is more complex, the commission believes that all cost-effective options which also allow NV Energy to meet state environmental requirements should be modeled and considered,” the commission’s order said.
The commission also approved NV Energy’s addition of a 120 MW portfolio of geothermal resources.
NV Energy said the IRP amendment was intended to reduce Nevada’s dependence on the open energy market, improve reliability and advance the state’s clean energy goals.
FERC on Thursday approved CAISO’s second attempt at complying with Order 2222, which requires RTOs and ISOs to foster participation of distributed energy resource aggregations (DERAs) in organized markets.
Thursday’s ruling found that CAISO fully addressed the directives the commission laid out last June in its order on the ISO’s first compliance filing (ER21-2455). In that order, FERC said the ISO — as the first RTO/ISO to implement a DERA model — had already complied with “the vast majority” of Order 2222 mandates, but the commission determined its proposal came up short in a number of areas. (See CAISO Order 2222 Filing Needs Some Work, FERC Says.)
Chief among the commission’s concerns last June was CAISO’s partial compliance with Order 2222 provisions around the role of distribution utilities in DERA market participation.
Order 2222 requires RTO/ISO markets to accept bids from a DERA if the aggregation includes resources that are customers of utilities that distributed more than 4 million MWh in the previous fiscal year. But it prohibits grid operators from accepting bids from an aggregation that includes resources that are customers of smaller utilities without the approval of the relevant electric retail regulatory authority.
Thursday’s ruling found that the ISO’s revised proposal had complied with FERC’s directives to:
specify the criteria utilities must use to determine whether each DER is capable of participating in an aggregation;
develop a process in which utilities will determine that a specific DER’s participation in an aggregation “will not pose significant risks to the reliable and safe operation of the distribution system;” and
share with utilities any “necessary information” and data collected about the individual DERs participating in an aggregation.
The commission further found that CAISO’s revised proposal met a requirement that the ISO share with a DER provider any information about a DER that a utility provides to CAISO as part of the utility review process. In approving CAISO’s related tariff revision, the commission also ruled that Pacific Gas and Electric’s protest that the rule could conflict with non-disclosure obligations between the ISO and utilities represented an “untimely request for rehearing” of FERC Order 2222-A, since PG&E “did not seek rehearing or clarification of the commission’s determination during the rehearing period of that order.” But the commission added that it acknowledged PG&E’s concern about “the appropriate protection of confidential information,” saying Order 2222-A does not preclude the use of NDAs.
“We believe that in a case where a utility distribution company declines to provide information because of confidentiality concerns, one avenue CAISO could use to facilitate participation of distributed energy resources is to encourage the distributed energy resource provider to sign a non-disclosure agreement in order to obtain the information needed to participate in the CAISO market via an aggregation,” the commission wrote.
The commission also found that CAISO’s revised proposal satisfied Order 2222’s requirement to revise its tariff to include a dispute resolution provision as part of the utility review process. Responding to a concern by PG&E, the commission clarified that the DERA dispute resolution process is not intended to supersede the existing process outlined in the ISO wholesale distribution tariff for resolving disputes related to interconnection issues — including the interconnection of DERs.
Lastly, the commission approved CAISO’s request to set the effective date for the DERA rules to no later than Nov. 1, 2024.
“As CAISO explains, ‘software enhancements required for this compliance will be highly complex, incorporating both energy injection and load curtailment into a single model that allows aggregations over a wider footprint than the majority of ISOs and RTOs have proposed,’” the commission wrote.
The author of a California bill that could eventually turn CAISO into an RTO said he will hold it in the legislative committee that he chairs while he tries to overcome opposition from labor unions, ratepayer advocates and his fellow lawmakers.
State Assemblymember Chris Holden (D), chair of the Assembly Appropriations Committee, said at the start of a committee hearing Tuesday that he still intends to move forward with AB 538.
“Interactions with my colleagues and stakeholders throughout the West persuade me that there is strong and widespread interest in working together on the details of governance and operations of a Western regional transmission organization,” Holden said. “I’m putting AB 538 on hold for now to allow that to happen. I’m hopeful of rapid progress, opening the way for legislative action at the earliest possible date.”
The move was not a surprise. In a hearing of the Assembly Utilities and Energy Committee in April, committee members allowed the bill to move forward only on the condition that Holden hold the bill in the Appropriations Committee while he addresses concerns with several key provisions. (See Committee Gives CAISO RTO Bill a Cool Reception.)
The bill would allow CAISO to develop a plan for independent governance, free from legislative oversight and with board members who are not appointed by California’s governor. (See Lawmaker Introduces Bill to Turn CAISO into RTO.)
CAISO is a public benefit corporation created by the legislature in 1998. The governor appoints the ISO’s Board of Governors, and the State Senate confirms them.
Having independent governance is essential for CAISO to become an RTO because other states will not join one dominated by California. But Golden State lawmakers have refused to cede control.
Holden’s prior efforts to expand CAISO governance to include other states in 2017/18, which were supported by former Gov. Jerry Brown, failed because of opposition from fellow Democrats in the legislature.
Until this week, Gov. Gavin Newsom has been silent on Holden’s latest effort, but he issued a statement after Tuesday’s announcement indicating support.
“I’d like to thank Assemblymember Holden for his leadership in the discussions around a Western regional transmission organization,” Newsom said. “I Iook forward to our continued work with the legislature, California stakeholders and our partners in other states to advance this important effort on enhanced regional collaboration that will benefit all the West.”
Circumstances have changed since Holden’s prior effort to expand CAISO governance. Notably, SPP is planning to establish a Western version of its Eastern Interconnection RTO, called RTO West, and is planning Markets+, a program with a day-ahead market.
Proponents of Holden’s bill have warned lawmakers that Western entities will abandon CAISO’s successful interstate Western Energy Imbalance Market and join SPP unless the ISO can offer an RTO with independent governance.
Jan Smutny-Jones, CEO of the Independent Energy Producers Association, told energy committee members in April that SPP “will be a different RTO than the one that would be built by [CAISO]” and asked whether they wanted a Western RTO to be run from California or Arkansas, where SPP is based.
Opponents of the measure say expanding CAISO to other states will siphon clean-energy construction jobs to states such as Arizona and Nevada, where it is cheaper to build and operate generation and storage resources.
They also contend that California lawmakers should not relinquish control of CAISO.
“The creation of a multistate RTO divests the legislature from having any ongoing role, and, in fact, you’re being asked to make yourselves and state agencies and the governor completely irrelevant,” Matthew Freedman, staff attorney for ratepayer advocacy group The Utility Reform Network, said in April’s hearing.
