ERCOT says it expects normal grid conditions during Saturday’s solar eclipse when solar resources, the grid operator’s workhorses this past summer during tight afternoon hours, will see their output reduced.
Staff have been looking ahead for months to an annular solar eclipse that will cross ERCOT’s region between 10:15 a.m. and 1:45 p.m. (CT). They say a maximum coverage of sun ranging from 76% to 90% will affect solar farms, with “clear-sky capability” reduced to at least 13% during the eclipse’s peak at 11:50 a.m.
The eclipse will traverse Texas diagonally, from the state’s northwest corner to the Gulf Coast. Its path includes San Antonio, Corpus Christi, several smaller cities and swaths of barren land with solar farms.
ERCOT has more than 17 GW of utility-scale installed solar capacity that has accounted for as much as a third of the grid’s fuel mix (April) and produced a record 13.7 GW of energy (Sept. 1). It has been credited with filling production gaps during a summer that saw the grid operator set multiple demand records. (See ERCOT Sets New Demand Mark, Will be Short-lived.)
The ISO has been working with solar forecast vendors to ensure the models account for the eclipse. It said it will prepare the system as necessary to meet the down and up solar ramps and use ancillary services for additional balancing needs.
An annular solar eclipse occurs when the Moon, at or near its farthest point from Earth, passes between our planet and the sun. Because the moon does not cover the sun’s entire disc, sunlight surrounds the moon’s shadow and creates a “ring of fire” effect.
The event is a prelude to next year’s total solar eclipse on April 8. That eclipse will cross over Texas from Mexico and continue into Canada and will be the last eclipse visible in the continental U.S. until 2044.
California regulators are considering a package of changes to the state’s low-carbon fuel standard, including measures to shore up prices of LCFS credits as fuel producers continue to generate excess credits.
The California Air Resources Board (CARB) is weighing the possibility of a one-time “stepdown” of the carbon intensity (CI) target, a move that could increase the demand for credits.
In addition, the agency is looking at a so-called auto-acceleration mechanism that would further decrease the CI target when certain market conditions are met.
CARB has been presenting the proposed changes to stakeholders during a series of recent workshops, and the CARB board received an update on the proposals last week.
The idea behind the proposed changes is to create a “steady price signal” for LCFS credits to spur ongoing investment in low-carbon fuels.
The LCFS is based on the carbon intensity score of transportation fuels used in the state, which reflects the greenhouse gas emissions of a fuel throughout its lifecycle.
The LCFS sets a CI target that decreases each year. Fuels that exceed the CI target generate a deficit, which fuel producers must offset by acquiring credits. The credits come from fuels whose CI is below the target.
In 2021 and 2022, the LCFS program “overperformed,” as the carbon intensity of transportation fuels, on a composite level, dropped below annual LCFS targets.
That has led to suggestions that CARB set more aggressive CI targets, which would help the state meet its carbon reduction goals.
3Degrees, a climate consulting firm, has urged CARB to roll out a lower CI target starting Jan. 1, 2024.
“We are concerned that multiple millions of credits are projected to be added to the credit bank in 2023, and a significant CI reduction is needed for 2024 in order to absorb these credits and maintain a robust market that incentivizes deep transportation sector decarbonization in line with midcentury targets,” Maya Kelty, 3Degrees’ senior director of regulatory affairs, said in a letter to CARB.
Working out Details
CARB hasn’t yet released a formal rulemaking package for the proposed LCFS changes, and many details still must be worked out regarding how CI targets would be adjusted.
The magnitude of a one-time stepdown in the CI target hasn’t been decided. The stepdown, planned for 2025, would be an additional decrease in the CI target on top of the annual decreases already scheduled in the LCFS program.
CARB also is working out what would trigger an auto-acceleration mechanism to reduce CI targets. One idea is to trigger the mechanism when the ratio of credit price to credit bank size hits a certain number; another concept would rely on the ratio of total credits to total deficits.
CARB wants an auto-acceleration mechanism to be based on “well-defined, publicly available market metrics.”
Stakeholders who support an auto-acceleration mechanism include Neste US, a producer of renewable diesel.
“The record high credit bank and unexpected rapid increases in the credit bank have been key reasons for increasing unpredictability of the market and the price,” wrote Oscar Garcia, West Coast regulatory affairs manager for Neste US.
The Union of Concerned Scientists, however, said an auto-acceleration mechanism isn’t the proper solution. Jeremy Martin, a senior scientist in UCS’ clean transportation program, said the main cause of recently falling LCFS credit prices has been the surge in the use of lipid-based renewable diesel in California. Renewable diesel is made from fats and oils, such as canola oil or soybean oil.
“With [Renewable Fuel Standard and federal] tax credits, renewable diesel became an inexpensive source of LCFS compliance and flooded the market,” undermining credit prices, Martin said in written comments. He called for capping LCFS compliance from lipid-based fuels.
Other commenters raised concerns that higher credit prices resulting from a stringent CI target would be passed along to consumers of gasoline, who over time are more likely to be low-income drivers who can’t afford an EV.
Other Changes Proposed
The current LCFS regulation reduces CI targets each year through 2030, with a 20% statewide reduction by 2030 from a 2010 baseline. Proposed changes would implement further reductions from 2030 to 2045.
Another proposed change would add aviation fuel to the fuels covered by the LCFS. Jet fuel currently is exempted from generating CI deficits.
Other changes under consideration would offer LCFS credits for refueling infrastructure for medium- and heavy-duty zero-emission trucks. LCFS has supported light-duty ZEV refueling infrastructure since 2019.
CARB staff expect to release a formal LCFS rulemaking package this year, which would be followed by a 45-day comment period. The regulations would go to the CARB board for a vote early next year and potentially take effect in 2024.
The New York State Energy Research and Development Authority needs more time to draw up the renewable energy certificate program for two major transmission projects.
The agency on Wednesday asked the state Department of Public Service for a one-year extension of the deadline to create the Tier 4 REC implementation plan.
The Public Service Commission on April 14, 2022, approved contracts for Champlain Hudson Power Express and Clean Path New York and gave NYSERDA 180 days to draft the implementation plan for RECs for those projects (15-E-0302). A few days short of the deadline in October 2022, NYSERDA asked for a one-year extension because of the complexity of the issues, and DPS granted it.
A few days short of the deadline this month, NYSERDA is asking for another 12 months, again citing the complexity of the task before it, the newness of the concepts, the number of factors beyond its direct control and the sheer number of stakeholders collaborating on the effort.
NYSERDA lists seven focus points in its most recent letter, compared with only six last year:
reviewing Tier 1 and Tier 4 shared resources contract alignment;
assessing Tier 4 requirements for delivery verification, contract compliance and conformity with existing processes;
evaluating systematic functionality that may be required in the New York Generation Attribute Tracking System and other enterprise systems for REC accounting, verification and settlement;
preparing Supplier Greenhouse Gas Baseline accounting standards;
assessing methods to verify demand response savings;
establishing voluntary Tier 4 REC sales and settlement processes; and
monitoring NYISO rulemaking relevant to internal controllable line operations and imported generation.
In its request, NYSERDA points out the two Tier 4 projects are not expected to come online until 2026 and 2027, which allows time for thoughtful and considered planning.
Champlain Hudson is a 340-mile underground/underwater HVDC line under construction that would import electricity from Quebec hydropower plants. Clean Path is an $11 billion suite that includes 1,800 MW of new solar generation, 2,000 MW of new wind power and a 175-mile underground HVDC line.
Both projects are intended to bring emissions-free electricity to New York City, where mandated retirements of fossil-fueled generation are setting up a potential reliability margin deficit as soon as 2025.
NYSERDA’s request comes as inflation and interest rate hikes roil the entire financial structure of renewable energy development in New York.
In June, developers with contracts for 4.23 GW of offshore wind nameplate capacity — 97% of the state’s offshore pipeline — told the DPS they might not be able to move forward without substantially higher offshore wind RECs. Developers of 91 onshore projects totaling 13.5 GW made the same case to DPS. Collectively the projects are a critical component of New York’s statutory goal of achieving 70% renewable power by 2030.
In late August, NYSERDA told the PSC it endorses some form of inflation adjustments as necessary to carry out the clean energy transition in New York.
As this was unfolding, Champlain Hudson and Clean Path made their own requests to the PSC. Clean Path in June wrote that it needed to be included in any inflation adjustments for Tier 1 RECs, as all 23 generation projects in its portfolio hold Tier 1 RECs or are eligible for them.
Champlain Hudson in August wrote that basic issues of fairness dictated it get the same increases granted to any other project, as its costs have increased just like theirs.
The PSC has not ruled on any of these requests yet.
Tier 4 is approaching its third birthday: The PSC created it on Oct. 15, 2020, through an order modifying the Clean Energy Standard. NYSERDA’s Tier 4 REC solicitation yielded 33 bids from seven sources. Clean Path and Champlain Hudson were ranked first and second, respectively, among the responses.
The two projects are predicted to reduce greenhouse gas emissions by 77 million metric tons over 15 years. The first-year impact on ratepayer bills has been estimated as an increase of 3 to 5.7% per month.
AUSTIN, Texas — ERCOT surprised the market this week when it said it plans to increase operating reserves by requesting an additional 3,000 MW of capacity to shore up the grid for the upcoming winter.
In a market notice issued Monday afternoon, the grid operator said its first monthly resource adequacy assessment indicates that if it experiences severe weather this winter similar to Winter Storm Elliott last December, it would face an “elevated” risk of entering into an energy emergency alert (EEA) during its projected peak demand. It said that risk, a 19.9% probability, exceeds NERC’s acceptable elevated risk threshold of 10%.
ERCOT said significant peak load growth since last winter, recent and proposed retirements of dispatchable generation and extreme weather events during the past few winters led to issuing a request for proposals. A list of dispatchable resources that it said could be “potentially” eligible to offer capacity and respond to the RFP included mothballed and seasonally mothballed dispatchable resources (as of Dec. 1) and dispatchable resources that have been decommissioned since December 2020.
Dispatchable resources currently in the interconnection queue that feasibly could be accelerated into commercial operations by Jan. 4 also could be eligible, ERCOT said. Resources have until Nov. 6 to respond to the RFP. Awards for three-month contracts (December-February) will be announced Nov. 23.
Speaking at the Gulf Coast Power Association’s Annual Fall Conference on Tuesday, ERCOT CEO Pablo Vegas expressed hope that some resources that have indicated they will be mothballed or enter seasonal operations “could stick around for this winter and help out with potentially managing an extreme weather event.”
“We want to try to get the risk of an EEA condition down below 10%,” Vegas said.
All but four of the 20 resources listed in the market notice would provide no more than 78 MW of winter sustained capability. Three of the four largest — CPS Energy’s two coal-fired units at the J.T. Deely plant and Austin Energy’s Decker Creek Unit 2 steam generator, each providing 420 to 428 MW of capacity — were decommissioned in 2018 and 2022, respectively.
“We are not considering bringing Deely Units 1 and 2 out of retirement. We made a commitment to our community that those would be retired,” CPS spokesperson Dana Sotoodeh said in an email.
An Austin Energy spokesman said there are no plans to bring Decker 2 out of retirement.
The fourth, a 292-MW gas unit outside Corpus Christi, has been approved by ERCOT to indefinitely suspend operations on Nov. 24. (See “ERCOT Evaluating RMR Options,” Texas Public Utility Commission Briefs: Aug. 24, 2023.)
Stoic Energy’s Doug Lewin referred to the units as “zombie power plants” and said ERCOT was trying to “bring [them] back to life.”
Another market insider, who goes by ERCOT Traders Anon on X (formerly known as Twitter), said ERCOT’s action is a capacity auction with two months’ lead time. They said this presents a gaming opportunity to marginal units that can “mothball and wait for an out-of-market RFP prior to a peak season.”
“What a mess. Nothing good will come from this,” they posted.
The news caused some GCPA speakers to scramble in revising their discussion points. Dan Jones, a retired ERCOT staffer who still consults with the grid operator, added a new question to the resource adequacy panel that he moderated.
“I just think it was a lot of surprise, really, to see the magnitude of the notice. Everyone else in the hall was pretty surprised,” he said.
ERCOT COO Woody Rickerson said the 19.9% risk of emergency conditions was an increase from last year’s 7% and “not acceptable.”
“It’s too high,” he said. “That 3,000 MW is enough to reduce the probability of going into EEA.”
Asked by an audience member about the probability of getting the RFP’s full 3,000 MW, Rickerson said, “I think that’s a really big question that’s going to get answered in the next couple of months.
“This is also a way of testing what the market is capable of,” he added. “What is out there? And what will the cost be? Just because we’re asking for up to 3,000 MW doesn’t mean that we will have signed contracts. We may not get that much, or it may be too expensive. I think this exercise will help educate us as to what the market is capable of providing.”
In its annual report, the successor organization to the Cyberspace Solarium Commission applauded the federal government’s efforts to improve the nation’s cybersecurity but warned that criminals and foreign adversaries still are hard at work.
The CSC 2.0 Project was created after the bipartisan, congressionally sponsored commission issued its final report in 2020. Its annual report is intended to evaluate the country’s progress toward implementing the 116 recommendations in the CSC’s final report. (See Solarium Team Urges Long-term Cybersecurity Focus.)
According to the new report, 42 of those recommendations have been fully implemented, meaning legislation has been passed, an executive order issued or some other definitive action has been taken to make them official policy. An additional 36 recommendations are nearing implementation, which means the legislation or executive order containing them “has a clear path to approval” or they have been partly implemented.
Significant measures that have been implemented include an updated national cyber strategy, which the Biden administration issued in March; the 2021 creation of the office of National Cyber Director at the White House; creating a cyber bureau at the State Department; and codifying sector risk management agencies for critical infrastructure sectors to support the cyber defenses of companies in those sectors.
Less progress has been made on the remaining recommendations. Some are categorized as “on track,” meaning the recommendation is being considered for a legislative vehicle or executive order or there are “measurable/reported signs of progress.” Others are listed as “progress limited/delayed,” which means there are no known legislative or policy actions underway or “significant barriers to implementation” for measures that “are not expected to move in the immediate future.”
Only one recommendation remains in the final category: creating House and Senate select committees on cybersecurity. The report cited “significant pushback” to the measure from unidentified sources and suggested “a future emergency [might] create the political impetus” to take action on the recommendation.
The report also noted progress on implementing suggestions from six white papers the commission published. These range from cybersecurity lessons learned during the COVID-19 pandemic to growing the federal cyber workforce, building a trusted supply chain and countering online disinformation.
Despite the successful implementation of some public-private coordination measures, the report warned that many federal agencies “have an uneven record of collaboration with the private sector,” while singling out the Defense and Energy departments for having “made more progress than others.” Even in this regard, the CSC previously suggested the Electricity Information Sharing and Analysis Center’s relationship with electric utilities is not as strong as it should be. (See Solarium Report Warns of E-ISAC Info Sharing Shortfalls.)
“Significant work remains necessary to build an effective cybersecurity partnership between the public and private sectors,” Solarium Commission co-chairs Sen. Angus King (I-Maine) and Rep. Mike Gallagher (R-Wis.) said in the introduction to the report. “This will require a careful balancing of incentivization, collaboration and … regulation across and between each of the country’s critical infrastructure sectors. A similar effort is needed to enhance cooperation with like-minded international allies and partners, ensuring a resilient global economy.”
FERC on Wednesday reaffirmed its support for NYISO’s 17-year amortization period for demand curves in its installed capacity market, rejecting protests from the New York Public Service Commission and consumer stakeholders (ER21-502).
The commission’s latest order amends but essentially upholds its May ruling, when the commission reversed course and approved NYISO’s proposal to shorten the assumed operational lifetime of a hypothetical natural gas peaking plant from 20 to 17 years. The commission approved the ISO’s proposal after the D.C. Circuit Court of Appeals issued a remand, ordering the commission to reconsider its prior rejection. (See FERC Accepts NYISO’s 17-Year Amortization Period Proposal.)
NYISO’s proposal was in response to New York’s Climate Leadership and Community Protection Act, which mandates strict net-zero emission goals and makes it more challenging for fossil fuel power plants to operate in the state. NYISO had used a 30-year amortization period until 2014, when the commission approved the 20-year term to reflect the technological, market and environmental risks of investing in the proposed proxy plant.
The PSC and consumer stakeholders argued the 17-year amortization period could increase capacity costs by $400 million over the 22-month period from July 2023 through April 2025. They also said the commission’s ruling runs afoul of its previous rulings rejecting the same proposal.
FERC rejected these arguments, saying it provided a “full and rational explanation” for its reversal and emphasized the ISO’s compliance filing was in line with its directives.
The order included a dissent from Commissioner Mark C. Christie that reiterates his previous arguments, which contend FERC’s decision to accept NYISO’s 17-year proposal undermines the commission’s original rulings and ignores expert opinions from industry stakeholders.
A call for FERC to run a technical conference on capacity accreditation ran into a mixed reception in comments filed this week, with the ISO/RTO Council saying it is too regional of an issue for the idea to have an impact (AD23-10).
“While the members of the IRC acknowledge that commission-led technical conferences can often be beneficial and understand the concerns raised by ACP in its petition, the regional variation on matters related to resource adequacy renders the topic of capacity accreditation less well suited for a national forum intended to drive toward ‘consensus,’” the IRC said. “As capacity markets themselves are neither mandatory nor standardized — reflecting regional differences in priorities and reliability needs — so too are the various accreditation frameworks that operate within each capacity market.”
Regions outside organized markets without capacity markets are even more distinct, which means a technical conference applicable to all would have limited value, it added.
Every FERC-jurisdictional ISO and RTO is talking about capacity accreditation modifications for a variety of reasons, and some of those processes contemplate a filing this year or next. Holding a technical conference likely would delay those changes, which are of “vital importance.”
The IRC said it was sympathetic to the issue of ex parte restrictions on commissioners discussing the topic, but it noted that no proceeding was open at this point that would lead to any issues.
“But should one arise, the commission could turn to alternative procedures that would not require a national technical conference to discuss individual ISO/RTO proposals,” IRC said. “For example, commission staff can notice a meeting to gather additional information about the unique reliability concerns facing a particular ISO/RTO to assess proposed capacity accreditation reforms.”
The Electric Power Supply Association told FERC it is not opposed to a technical conference and it supports broad engagement on system planning and resource adequacy. But like the IRC, it cautioned FERC about the idea’s impact on the ongoing stakeholder processes.
“Those processes are the result of extensive stakeholder participation and negotiation and are tailored to the region’s specific needs; for this reason, the commission should take care to both timing and framing a technical conference such that it supports — rather than stymies — this regional progress,” EPSA said.
Colorado Public Utilities Commission Chair Eric Blank wrote to FERC in support of holding a technical conference, saying it would help given all the changes happening on the Western grid. The PUC is working to facilitate a transition that economically reduces greenhouse gases over time while also moving toward more regional cooperation through expanded markets.
“Taken together, these forces will likely result in a significant increase in interregional transfers, an expansion in alternative generator and customer supply structures, and greater investment in intermittent and customer-sited resources, all of which present new challenges for maintaining resource adequacy,” Blank said.
Capacity accreditation may need to change from analyzing a few hours of peak demand in a deterministic way to dynamically evaluating in a probabilistic way the value of individual resources during more frequent tight supply conditions, he added.
The Solar Energy Industries Association told FERC a conference is a good idea given the changes the industry is going through.
“Regions are shifting from a single summer peak to biannual summer and winter peaks, with climate change exacerbating the reliability risks associated with these changes,” SEIA said. “The risk of correlated outages of thermal resources during extreme weather events is becoming more commonplace, and capability during extreme weather events is now the biggest risk to the reliability of the grid.”
Advanced Energy United said it would like FERC to offer guidance on the patchwork of capacity accreditation rules around the country and thus supported the technical conference.
“Existing ongoing efforts — which will continue to be iterated on for years at RTOs/ISOs — point to the need for a technical forum to holistically discuss issues and challenges related to capacity accreditation that have and will continue to arise,” AEU said. “Existing processes to accredit capacity are inconsistent and leave out some of the important issues raised by ACP in its petition.”
Sierra Club, Earthjustice, RMI, the Natural Resources Defense Council and the Sustainable FERC Project filed joint comments arguing a national technical conference on capacity accreditation would be worth FERC’s time.
“This subject is also a matter of substantial public interest as policymakers at all levels strive to maintain affordable electric rates while grappling with increasingly frequent extreme weather that threatens reliable electricity supplies,” the groups said. “Accurate capacity accreditation is key to a successful transition from conventional generation resources to a more decentralized and lower-emitting resource mix broadly supported by consumers and many state and local policies.”
The current patchwork might reflect legitimate regional and operational differences, but FERC hasn’t examined whether that is the case or whether different rules undermine reliability and skew investment decisions in a way that doesn’t benefit customers, they added.
Doubts continue to swirl around which version of MISO’s future fleet mix is appropriate for long-range transmission planning: the RTO’s or the Independent Market Monitor’s.
MISO pledged additional examinations of its fleet prediction during a stakeholder teleconference Monday, but that did little to quell reservations on either side of the debate.
Monitor David Patton said he continues to have misgivings about MISO’s 20-year fleet assumption that’s dominated by nearly 250 GW in anticipated wind and solar additions alongside 53 GW in gas and other flexible generation and 31 GW of standalone battery storage.
MISO is using that fleet assumption to plan the second portfolio of its continuing long-range transmission plan (LRTP). The RTO says recent studies are showing its estimate of the future fleet holds up well and should be used in the multibillion-dollar portfolio.
Now that it has had time to conduct several tests, MISO says it has determined that its middle-of-the-road, 20-year planning future, referred to as Future 2A, “is most aligned with an optimized, least-cost expansion that meets member goals.” Director of Economic and Policy Planning Christina Drake said MISO continues to strive to “make sure we have a least-regrets portfolio.”
Patton, however, countered, “We continue to believe Future 2A is just not a reasonable basis for planning.”
Future 2A underwent an update last year to include members’ more aggressive decarbonization goals. Senior Director of Transmission Planning Laura Rauch said MISO will conduct more sensitivities for 2A based on different variables. The RTO is planning a new sensitivity based around hypothetically reduced incentives from the Inflation Reduction Act to see if its projected resource expansion changes meaningfully.
“We’ll continue to look for answers, but quite frankly, the answers that we get might not be the ones you’re looking for,” MISO Vice President of System Planning Aubrey Johnson told stakeholders.
MISO planners are prepared for contentious LRTP workshops, he said. “There’s a lot at risk. There’s a lot at stake. And we don’t take these meetings lightly.”
Drake said there have been many questions over how MISO arrived at its future fleet assumptions. She said MISO’s envisioned resource mix is “rooted in the reality of member plans” and that the LRTP is developed to optimize the delivery of members’ decarbonized future fleet. She also said MISO developed the second future over 18 months of stakeholder engagement.
Customized Energy Solutions’ David Sapper said numerous stakeholder meetings are not a “proxy” for the actual vetting of the future resource mix used for planning.
MISO: Monitor’s Fleet Vision More Expensive
MISO said it tested both the Monitor’s ask that it study more natural gas and battery storage resources and a scenario in which capacity accreditation is drastically reduced. It said both comparisons showed that its own version of the future resource mix under 2A represents a “least-cost expansion while considering state and member goals and resource economics.”
The RTO found wildly different fleet predictions between its version, the Monitor’s and the low accreditation future. It expects the total installed capacity under 2A to reach 471 GW by 2042 and cost $234 billion. It said if it introduced more gas resources and battery storage in place of renewable generation — as the Monitor recommended — costs would climb to $319 billion for 462 GW of capacity in the same time frame.
According to MISO, the Monitor’s version of the resource mix would include 103 GW of hybrid renewable and storage resources and nearly 96 GW in gas generation, with 83 GW less in wind resources and over 25 GW less in solar generation from the RTO’s prediction. Future 2A calls for 67 GW in natural gas and just 10 GW worth of hybrid resources.
In the reduced capacity accreditation scenario, MISO found a $251 billion resource expansion for 521 GW in installed capacity. That scenario returned a drastic spike in standalone battery storage to 103 GW by 2042.
MISO test results of the three kinds of fleet assumptions | MISO
But Patton said the amounts MISO inferred from his recommendations are faulty.
“The math is obviously wrong. … Your costs are obviously wrong,” Patton told MISO planners. “I don’t want anyone coming away from this thinking this is correct.”
Patton offered to consult with MISO on a joint hypothetical case of his version. He said there’s “no way” his would necessitate more than 100 GW of hybrid resources.
Drake said MISO “triple checked” its cost and capacity conclusions under the Monitor’s fleet predictions with more gas and battery resources. Rauch said MISO worked with the best information from the Monitor and said she was “frustrated” that it disagreed with the RTO’s outcome.
“We’re looking at roughly a 9-GW difference between the two scenarios,” Rauch said of the overall resource totals.
“There are some more sensitivities that we’ll run,” Rauch continued. But she said she hasn’t so far noticed anything that would cause MISO to rebuild its assumption from the ground up. She said more testing of MISO’s fleet assumption will likely “help us solidify and refine what comes out of Future 2A.”
WEC Energy Group’s Chris Plante said he was “disappointed” MISO didn’t work with the Monitor to come up with costs for the high gas and battery model to make certain it was what the IMM had in mind.
Minnesota Power’s Tom Butz said MISO’s current generation expansion tool used in modeling, the Electric Generation Expansion Analysis System, is no longer “cutting edge” and can’t capture all nuances of the future grid. He said MISO filled out the hypothetical resource mix with its own predictions when it didn’t see enough generation in members’ plans.
“The bottom line is that this is 100,000 MW beyond what the members have put in there. It’s troubling, and it’s not indicative of a collaborative process,” Butz said of MISO’s forecasted 471 GW.
Drake said MISO plans to move to the more sophisticated PLEXUS tool for transmission planning in the coming years.
Patton questioned why the nearly 30 GW in unnamed, flexible resources MISO prescribed won’t negate the need for some of the hundreds of gigawatts of renewable energy it is also expecting. He said MISO can’t claim it’s planning the most cost-effective portfolio if it’s not siting more battery storage, especially at constrained transmission points.
“It’s not that we lack for capacity. There’s sufficient capacity,” MISO’s Johnson said. Rather, he said, the RTO aimed for a fleet assumption that will furnish energy adequacy across all hours, even in the riskier dawn and dusk periods. MISO foresees a danger of being unable to meet all demand after sunset on hot summer days and during pre-dawn and post-dusk periods on winter days. The RTO said it may find itself depleting battery storage with not enough dispatchable generation to meet hourly demand at those times.
Patton said he thought MISO simply requires capacity under a tougher accreditation to conquer its reliability risks.
Support for MISO’s Fleet Prediction
MidAmerican Energy’s Dehn Stevens said some members’ “myopic view” that the evolution of the system fleet is only going to be driven by capacity needs is “completely off the mark.” He said the race to decarbonize will drive the bulk of the resource transition.
“We think this approach is very good,” Stevens said of Future 2A.
Otter Tail Power’s Stacie Hebert said load growth and resource transformation is imminent for the footprint and that stakeholders need to put more faith in MISO’s expertise in transmission needs.
“It’s easy to pick out things that might not look right from our worldview right now,” she said. But she said MISO is an industry leader in transmission planning. “Inaction and delay also has a cost, so we really need to be balancing our interest in restudies and restudies against inaction.”
“Obviously a lot of the stakeholders expressed frustration today,” Sustainable FERC Project attorney Lauren Azar said. She said she thinks MISO is doing “all of the analysis it needs to do.”
While she said she respects Patton’s opinion on markets, she said he is not a transmission planner and does not specialize in grid planning.
“MISO needs to use its professional judgment about what changes it needs … for the grid in 2042,” Azar said. She said the RTO’s Environmental sector is already concerned that its planning is not keeping pace with the regional backbone projects it will need to support fleet transformation.
“I think we need to move forward and not let the perfect be the enemy of the good,” she said.
IMM Again Expresses Worry for Market Operations
Patton repeated concerns that MISO’s LRTP fleet assumption stands to affect the markets during a mid-September virtual forum hosted by the Gulf Coast Power Association.
The Monitor said that ordinarily, MISO’s transmission planning doesn’t ring alarm bells, but the enormous amounts of renewable energy coupled with “very little” dispatchable generation mean MISO will try to build a transmission system to absorb the fluctuations of an intermittent fleet.
He said “large, uneconomic” transmission investment can dampen the market’s ability to facilitate new generation investment and retirements. It’s imperative that MISO make sure lines address actual needs, he said.
“Now, the reason we care about this is because transmission investments, by definition, occur outside the market,” Patton said. “They’re not being done in response to market signals, and they’re not being paid for through market revenue … and that’s not necessarily bad. That’s a choice that in this country we’ve made in terms of how we make transmission investments.
“But what is important is the investments be made economically … that we invest in transmission as if we were making them in response to forecasted market signals. Because when we make uneconomic transmission investments, then it will distort the market signals and it will adversely affect the participants in the market, as well as raising costs for transmission customers.”
Patton said he envisions “a very different future” by 2040, in which MISO adds 108 GW less in renewable energy than it’s expecting. He maintains that reduction would save the RTO about $120 billion in renewable energy costs by 2040. He said if MISO adopted his view of the future, it would result in more accurate transmission planning.
“What we believe is more realistic is that batteries and hybrid renewables, which have batteries on-site, will be developed,” Patton said.
He also said he takes issue with MISO modeling and planning for a footprint-wide carbon-reduction target when it doesn’t have one.
Clean energy groups active in MISO told FERC last week that it should rethink its support of a ban on renewable energy in MISO’s ancillary services market because the commission didn’t consider hybrid resources when it made its decision.
The Solar Energy Industries Association, American Clean Power Association, Clean Grid Alliance, Natural Resources Defense Council, Fresh Energy and Sierra Club are seeking a limited rehearing of FERC’s prohibition on renewable energy furnishing ramping needs (ER23-1195-001).
The groups said FERC’s authorization of MISO’s embargo is faulty because it doesn’t explain where hybrid resources — combinations of renewable energy and energy storage — factor into the ban.
FERC this year allowed MISO to exclude renewable resources from providing ramping capability and rejected a challenge from SEIA on the RTO’s practice of precluding renewable resources from providing ancillary services in its markets. (See FERC: MISO Can Ban Intermittent Resources from Providing Ramp and FERC Blocks Solar Group’s Contest of MISO Ban on Renewable Ancillary Services.) In both cases, FERC said renewables are almost never the most economic choice to supply operating reserves because they’re often trapped behind already binding transmission constraints, rendering their output undeliverable.
But the clean energy groups argued that hybrids, unlike standalone renewable resources, are “fundamentally different” in terms of operations and economics.
“Storage paired with renewable resources can relieve congestion and have flexibility that renewables alone do not possess. Because of these differences, the rationale and evidence that MISO provided in support of its prohibition do not apply to hybrids,” they said.
The groups suggested MISO eschew a “blanket prohibition” and, at a minimum, allow hybrid participation in the ancillary services market on a one-year temporary basis with the option to reevaluate. They said MISO used the same open-ended, one-year approach when it allowed intermittent resources into its energy market years ago. They said the same approach “is appropriate to deploy here specifically to hybrids.”
MISO has calculated significant increases in its annual cost of new entry (CONE) values for use in its 2024/25 capacity auction.
The average CONE surged to nearly $330/MW-day, ratcheting up from $275/MW-day a year ago and $243/MW-day during the 2022/23 capacity auction. For the first time, all local resource zones surged beyond a $100,000 annual cost to build a single megawatt.
MISO said the increase is “mainly due to significant increases in base project capital costs and the weighted average cost of capital, both reflecting actual and expected inflation estimates.”
The RTO’s CONE represents the cost of building an advanced combustion turbine. It differs by zone to reflect regional differences in construction costs. The values include capital costs, operations and maintenance expenses, property taxes and insurance costs. MISO South typically has lower costs than MISO Midwest.
MISO’s Zone 5 in parts of Missouri carries the highest CONE of the zones, at $131,725/MW-year, and experienced the highest year-over-year increase at $22,145/MW-year. Zone 5 usually has the highest CONE.
Zone 7, covering Michigan’s Lower Peninsula, came in second at $127,135/MW-year.
Mississippi’s Zone 10 holds MISO’s most inexpensive CONE value at $112,263/MW-year. The zone consistently returns the lowest CONEs.
On average, the zones’ CONE values increased by $19,931/MW-year.
