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November 9, 2024

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Vistra Joins Rush for Dispatchable Generation Loans

Vistra, Texas’ largest generator, said May 30 it plans to add nearly 2 GW of gas-fired capacity to the ERCOT grid over the next year by investing in existing power plants to increase their output. 

The capacity additions will help meet ERCOT’s and the Public Utility Commission’s desire for more dispatchable (i.e., thermal) generation necessary to meet the state’s growing demand. 

“Texas is in the enviable position of experiencing sustained economic growth, which includes rapidly increasing power demand as a result of population growth and electrification activities in a number of areas, including transportation, data centers, manufacturing and industrial activities,” Vistra CEO Jim Burke said in a news release.  

Vistra said it was filing a notice of intent to seek disbursements from the $5 billion Texas Energy Fund (TEF)’s Generation Loan Program. The program is designed to drive more dispatchable energy to the ERCOT system.  

The PUC said June 1 it had received 125 notices of intent totaling $38.9 billion in financing for 55.9 GW of proposed dispatchable projects, fulfilling the hopes of some participants that the TEF would be oversubscribed (56455). 

Formal applications now can be submitted by entities that submitted a notice of intent. Completed loan applications must be filed by July 27. The first disbursements, financing up to 60% of a loan, should be issued by Dec. 31, 2025. 

The commission established the TEF in March because of state legislation passed last year. Qualifying projects must add at least 100 MW of dispatchable capacity to the grid. The PUC says the program can support up to 10 GW of new or upgraded generation capacity in ERCOT. (See Texas PUC Establishes $5B Energy Fund.) 

Through Luminant, its generation subsidiary, Vistra plans to: 

    • Build up to 860 MW of advanced, simple-cycle peaker plants in West Texas, supporting the increased power demands of the state’s oil and gas industry. 
    • Repower its coal-fired Coleto Creek Power Plant as a gas-fired unit and use the existing infrastructure to provide up to 600 MW of capacity when the coal plant retires in 2027 to comply with EPA rules. 
    • Complete several upgrade projects at its existing gas plants, adding more than 500 MW of summer capacity and 100 MW of winter capacity. 

Vistra said its quick-start gas units would help back up the grid when renewable resources are not available and battery storage resources have reached their limits. Nearly half of the capacity would come online this summer and the remainder next summer. 

All three projects are based on market reforms passed during the 2023 legislative session that include new ancillary services, the performance credit mechanism and an effective reliability standard. The company said implementation could offer the regulatory framework needed to incentivize long-term investments in the grid. 

“Since the market opened to competition, over $100 billion has been invested by a wide range of investors in a variety of power generation technologies to meet the growing needs of Texans,” Burke said. “The ERCOT market has a history of attracting generation owners who put their capital at risk when there are investment signals.” 

The projects are contingent upon other factors, including state and federal environmental regulations and long-term wholesale trends that continue to support gas generation, Vistra said. 

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Report: Home Retrofit Benefits Maxed by Combining Fed Funds with Other Sources

The American Council for an Energy-Efficient Economy, AnnDyl Policy Group and Building Performance Association published a paper last week showing how states can maximize the impact of federal funds for home energy retrofits. 

“Federal funding for residential energy retrofits will make a huge difference, but what’s most important now is that states put it to use effectively,” said ACEEE Buildings Program Senior Fellow Jennifer Amann, who co-authored the report. “Existing programs lay the groundwork for improved retrofit efforts and market approaches that will make it easier and more affordable to retrofit housing to enhance comfort, improve health, and cut energy costs and climate-warming emissions. With the new funding now available, states can improve on these programs and continue to innovate.” 

The federal government has put up $53 billion in rebates, grants and other incentives, on top of tax credits and deductions for home energy retrofits that are not capped. The Infrastructure Investment and Jobs Act and the Inflation Reduction Act offered billions in funding to agencies including the departments of Energy and Housing and Urban Development, EPA and the IRS. The biggest chunk is $27 billion from the IRA for the Greenhouse Gas Reduction Fund administered by EPA. 

An additional $30 billion is available from nonfederal sources, including state and local programs, utility offerings and housing funds. The biggest chunk of those funds comes from banks which on average put out $24 billion in loans that can be used for upgrades, while utility programs come in at just under $2 billion across the country. 

The funding can help make up for the fact that homeowners and landlords often have less access to capital than the owners of commercial buildings, which can cause them to defer efficiency investments. 

Combining the federal funds with other sources can help states increase the overall impact and invigorate longer-term transformation for the home retrofit industry. States can successfully combine funding sources by reaching out to key stakeholders to identify program gaps, reviewing and expanding their own goals, and matching new and existing program objectives. 

States have to ensure that funds that have separate requirements are not blended together, but combining funds can make retrofits more successful, and programs that appear as a single incentive are less confusing for consumers, the report said. 

The impact of the federal programs is going to vary by state because they all have different programs themselves, for their utilities and from other sources. 

“Some states have access to deep funding streams from ratepayer programs, government agencies with a wealth of capacity and history in clean energy, and access to secure energy data, whereas other states are beginning now with none of this existing infrastructure,” the report said. “However, states with less history are also less burdened by past decisions and precedents in building their future policies and innovations.” 

The report suggests that states make customer utility data available in order to take full advantage of the federal funds. 

“Secure access to their own energy use data provides utility customers with information they can use to change their behavior and to partner with third parties (e.g., contractors) to reduce their energy use,” the report said. “Advanced metering infrastructure facilitates data access; federal and state governments are working with utilities to develop best practices to support data access while addressing privacy concerns.” 

The report also suggests incorporating grid flexibility to bridge traditional and “dynamic” efficiency, meaning smart thermostats, grid-enabled water heaters and other products that can offer flexibility for the grid. 

The current federal investment can support longer-term market transformation so that eventually, the residential retrofit agency can be self-sustaining absent incentives and other market interventions. 

“Key steps for market transformation include consideration of long-term goals in program design; collaboration with contractors, distributors and suppliers to build a robust industry infrastructure; and demonstration of the long-term value of retrofit investments,” the report said. “By considering opportunities to drive lasting changes in both market supply and demand, programs can generate benefits well beyond the life of the program.” 

Prioritizing historically underserved communities is important, with the report noting that renters have long seen much fewer benefits from such programs. Bringing programs to multifamily and single-family rental homes while protecting renters themselves from displacement is possible, it said. 

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NV Energy Confirms Intent to Join CAISO’s EDAM

NV Energy intends to join CAISO’s Extended Day-Ahead Market (EDAM), an official with the utility said May 31, notching a major win for the ISO in its competition with SPP’s Markets+ day-ahead offering in the West. 

The announcement confirms what multiple sources have recently told RTO Insider: that the Nevada-based utility had disclosed in private meetings that it had decided on the EDAM and would make that news public upon filing its integrated resource plan with the Public Utilities Commission of Nevada (PUCN). (See NV Energy to Join CAISO’s Extended Day-Ahead Market.) 

Speaking at a monthly meeting of the Launch Committee of the West-Wide Governance Pathways Initiative, Dave Rubin, NV Energy’s federal energy policy director, acknowledged the accuracy of the press reports and said the utility submitted its IRP — which includes the request — to the PUCN that same day. 

“We will indicate NV Energy’s intention to request authorization from our commission later this year to join the EDAM,” said Rubin, who also is a member of the Launch Committee. 

Rubin said the Nevada process for joining a day-ahead market is different from some other Western states because state law requires a utility to obtain “formal authorization” from the utility commission to move forward with a market decision.

The decision is a key victory for the EDAM because NV Energy’s control area occupies a central position in CAISO’s Western Energy Imbalance Market (WEIM), providing a key corridor for wheel-throughs of energy between the market’s California participants — including the ISO — and PacifiCorp’s massive balancing authority area in the inland West. 

Brian Turner, a Pathways Launch Committee member who leads Advanced Energy United’s regulatory engagement in the West, called NV Energy’s decision to join EDAM a “big deal” based on the “critical mass” it brings and the overall “functioning of the grid.” 

NV Energy’s decision moves Nevada from “being on the periphery of a possible Markets+ to being at the center of what will come with EDAM,” Turner said in an interview. “So, it’s a very big deal that they’re joining.” 

The Brattle Group study released this year that showed NV Energy could earn as much as $149 million in benefits from participating in EDAM noted that the scale of the utility’s benefits is heavily correlated with the shape of the market footprint “due to its large amount of transfer capability and centrality” in the Western Interconnection.   

“NVE benefits tend to be higher when it is central to the market and facilitates transfers within the market,” the study found in assessing outcomes based on multiple footprints for both EDAM and Markets+. (See NV Energy to Reap More from EDAM than Markets+, Report Shows.) 

NV Energy’s decision in favor of EDAM also is significant for the work of the Pathways Launch Committee, which voted May 31 to advance step 1 of its CAISO governance proposal to the ISO’s stakeholder process. The proposal calls for CAISO to alter its tariff to elevate the “joint” authority the WEIM’s Governing Body currently shares with CAISO’s Board of Governors over WEIM matters to “primary” authority.  

Under the plan, the ISO would file that change with FERC only after the EDAM secures implementation agreements with a “set of geographically diverse” WEIM participants representing load equal to or greater than 70% of CAISO’s annual load in 2022.  

So far, only PacifiCorp has fully committed to signing such an agreement, but the EDAM also has solid commitments from Balancing Authority of Northern California, Idaho Power, Los Angeles Department of Water and Power, and Portland General Electric. NV Energy’s commitment would position CAISO to trigger that change. 

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Panel Provides Update on Energy Storage in Mass.

Battery storage remains largely reliant on state programs and subsidies to be viable in Massachusetts but increasingly could stand on its own as renewable resources proliferate, a panel of energy storage experts said during a webinar May 30. 

“As we further decarbonize our grid, these products become ever more important,” said Tom Ferguson, energy storage programs manager at the Massachusetts Executive Office of Energy and Environmental Affairs. 

Ferguson noted that battery storage’s ability to balance the grid will become more valuable with more intermittent resources on the system. He emphasized that long-duration storage pairs particularly well with offshore wind, which could help drive the business case for long-duration technologies. 

While credits associated with Massachusetts’ Clean Peak Energy Standard (CPS) make up a major portion of the revenue for new storage resources today, “over time, the hope is that the need for incentives will decrease,” Ferguson said. 

He cited a December 2023 report commissioned by the state that found storage likely will be “a cost-effective element of mid- and long-term resource portfolios” but needs increased state support in the near term to scale up quickly enough to meet the state’s goals. 

“Additional state programs will be required, as will dedicated efforts to reduce existing financial, technological, supply chain and operational barriers to deployment,” the report found. 

Responding to a question about Massachusetts’ progress toward its goal of deploying 1,000 MW of storage by the end of 2025, Ferguson said the state currently has “a little over 500 MW. … We’re hoping we’ll hit that target.” 

Chris Sherman, senior vice president at Cogentrix Energy, discussed the company’s ongoing efforts to replace the West Springfield Station, which retired in 2022, with battery storage. 

The first phase of the project consists of a 45-MW battery facility with a projected in-service date of mid-2025, while the company is “in the process of designing Phase 2, which will likely be an additional 105 MW,” Sherman said. 

“The clean peak standard is the basis for the project,” Sherman said, noting that it accounts for about 40% of the project’s projected revenue. 

Looming changes to how ISO-NE accredits resources in its Forward Capacity Market likely will further reduce the revenues available to battery storage from the wholesale markets, Sherman added. 

An ISO-NE analysis from early May indicated the in-development accreditation changes could result in a $58 million reduction in total capacity market revenues for storage resources. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11%.) 

The changes are intended to better align capacity procurements with actual reliability benefits. Sherman said they amount to “a fairly significant derate,” adding that “we would need to have that [capacity market revenue] made up somewhere … [but] it was probably the least amount of our revenue; it was never a great revenue source.” 

Todd Olinsky-Paul, senior project director at the Clean Energy States Alliance, said the new accreditation framework likely will “push battery storage toward longer-duration resources.” 

Jason Viadero, director of engineering and generation assets at Massachusetts Municipal Wholesale Electric Co. (MMWEC), said the company has deployed storage to minimize its peak and save customers money without substantial support from state programs. Massachusetts’ municipal utilities are not subject to the CPS. 

“This is one specific use case that completely stands on its own economically,” Viadero said. “These systems are able to pay for themselves throughout the life of the system.” 

Growing electricity demand will make peak shaving increasingly important, Viadero said, highlighting the significant differences in ISO-NE’s cost projections for a 57-GW peak load system and 51 GW. (See ISO-NE Prices Transmission Upgrades Needed by 2050: up to $26B.) 

Viadero said MMWEC is working to deploy “upwards of 50 MW” of energy storage in 2024 and 2025, with a greater focus on longer-duration storage going forward. 

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Calif. Officials ‘Cautiously Optimistic’ on Summer Reliability

California energy officials are “cautiously optimistic” about maintaining grid reliability this summer, with the state benefiting from above-normal snowpack and precipitation coupled with expectations for cooler temperatures in coastal regions.  

That was the assessment of multiple presenters speaking during a summer reliability workshop hosted by the California Energy Commission on May 29. 

But climate change is making it increasingly hard to ensure reliable grid conditions, and planners must remain vigilant to avoid outages such as those in 2020, CEC Vice Chair Siva Gunda said during the workshop. “In 2020, we had two [rolling] outages on Aug. 14 and Aug. 15 — something we hadn’t seen at that point in 20 years — and it has been a primary focus in California to ensure electric reliability as we move forward.”  

Maintaining reliability requires a host of responses to keep up with decarbonization efforts and a warming climate, including having flexible and dispatchable resources, especially during the critical sunset hours when solar rolls off the system, said David Erne, CEC deputy director of resource planning, reliability and emergency response. But this summer is looking better than last, he said.  

Weather Patterns

Zeroing in on weather conditions, Amber Motley, director of short-term forecasting at CAISO, highlighted that the central Sierra Nevada had above-normal snow water equivalent this winter, although California was at 67% of its snowpack average as of May 20, said Jeff Fuentes, deputy chief of fire intelligence at Cal Fire.  

But the Pacific Northwest “did not have as good of a snow year,” Motley said, resulting in abnormally dry to moderate drought conditions in many portions of Oregon and Washington.   

This summer also should mark a transition away from El Niño, which is associated with warmer sea surface temperatures in the Pacific Ocean and hotter, dryer conditions in the northern U.S., to La Niña, marked by colder sea temperatures, drought and warmer conditions in the South and heavy rains in the Pacific Northwest.  

“For the Desert Southwest, this is really critical,” Motley said. “Because of the position of … where the heat is focused to be, it’s expected they don’t get as much monsoon moisture, which leads to less precipitation, but also leads to less cooling for them in the evening hours. The key piece as we head into summer is really watching the position of that [heat] ridge.” 

Another factor to watch, Motley said, is above-normal sea surface temperatures in the Atlantic, leading to forecasts that hurricane season will be more extreme — which impacts conditions in the West.  

“That’s going to be critical to watch because if you have big hurricanes, when we get into the August and July time period, they will move up into the gulf, and they kind of act like a traffic jam to the atmosphere. So, that could allow a ridge to stay parked over the West and not move for a number of days.”  

Taking all these pieces into account, forecasters anticipate above-average temperatures in the Desert Southwest, interior California and Rockies regions and a low probability of above-normal temperatures in California’s coastal regions.  

California fire risk is low to normal, Fuentes said, but “normal” typically means one to two large fires in each of the state’s service areas in June, three in July and six in August. Additionally, the Pacific Northwest will see normal risk of significant fires until July, when areas of Central and Southeast Oregon may shift to above-average potential for wildfire.  

Reliability

Changing weather patterns aren’t the only significant challenge to ensuring reliability. Expedited resource builds coupled with delays and resource retirements also are having an impact, said Branden Sudduth, WECC vice president of reliability planning and performance analysis.  

“Over the last two-year cycle when we developed our reports, we saw about 5,000 MW worth of generation retirements being delayed,” Sudduth said. “A lot of states in the West are focused on making sure they have adequate energy, adequate resources over the next couple of years. But we just want to make sure that people are alert and aware that those retirements are still going to happen in the future, and we just need to keep our foot on the gas pedal when it comes to making sure that we get new resources developed, built and online.”  

Sudduth provided an overview of NERC’s 2024 Summer Reliability Assessment, which evaluates June through September. This year’s assessment showed that while all areas of North America have adequate resources for normal summer demand, British Columbia, California, Mexico and the Southwestern U.S. have an elevated risk of insufficient operating reserves and loss of load under “extreme conditions,” defined as demand meeting or exceeding the 90th percentile threshold of the region’s demand curve. (See NERC Summer Assessment Sees Some Risk in Extreme Heat Waves.) 

The “good news,” Sudduth noted, is that no regions were identified as “high risk,” indicated as having insufficient operating reserves under expected conditions, for the upcoming summer.  

Focusing on the elevated risk identified for California and Mexico, the highest chance for load loss was the period ending at 7 p.m., though that totaled less than one hour. In the Southwest, the concern lay in the potential for a heat wave to increase the region’s probability of being unable to meet its operating reserve requirements.  

A broader reliability concern identified by WECC is the industry’s ability to keep up with the pace of development.  

“From January 2023 to June 2023, the Western Interconnection added around 14 GW of new generation capacity. Currently, we’re planned to add just over 17 GW” by summer, Sudduth said. “As we look at things such as supply chain delays and … we know there are workforce shortage issues, that’s really one of the challenges we face is can we build enough generation quick enough to meet our plans, and I assume that will continue to be one of our challenges in future years as the pace of generation builds [continues] to increase.” 

Christine Root, integrated resource planning and compliance supervisor at the California Public Utilities Commission, emphasized the rapid pace of resource development, with 18,500 MW of clean energy nameplate capacity coming online from 2020 to 2024, 5,700 MW of that last year — “the highest amount of clean energy on record for a given year thus far.”  

Ensuring reliability is dependent on long-term forward planning and procuring the volume of resources needed to support the evolving grid, Root added. The CPUC adopted a preferred system plan in February 2024, which estimates 55 GW coming online by 2035, 32 GW of which is expected to be solar.  

Though grid planners and forecasters presented a generally positive outlook for summer 2024, they continued to emphasize the importance of being cautious and vigilant.  

“Maintaining reliability is paramount and underscored by what we’re all collectively facing with the climate crisis,” said Christine Hironaka, senior adviser for energy for the office of Gov. Gavin Newsom.  

She noted that extreme heat events like the one in September 2022 are likely “to increase in frequency and intensity as time goes on.”  

“I think the good news is, last year … the grid did not have any major emergencies and I think the topline for me is we remain cautiously optimistic for this summer’s outlook,” she said.  

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Texas RE Sees Challenges in Resource Mix, Physical Security

Staff at the Texas Reliability Entity said in a webinar that the regional entity’s upcoming Reliability Performance and Regional Risk Assessment should show most performance metrics are “trending in the right direction,” although work still is needed in some areas. 

Texas RE produces the assessment each year as a supplement to NERC’s State of Reliability report, reviewing the performance of the state’s grid over the previous year. Both reports normally are released in June. Speaking at the RE’s regular “Talk with Texas RE” event May 30, Director of Reliability Services David Penney said the assessment has performed a valuable role since the RE started releasing it 10 years ago.

“We’re one of the few regional entities that puts a report like this together, that looks at both the regional performance from a reliability perspective, as well as a regional risk assessment to look at the risks that we face as a region,” Penney said. “We tried to tailor this report [to] … a target audience [of] industry stakeholders, industry executives, as well as policymakers, to [share] the key risks that we [see] as a region, as opposed to what you may see from other industries or other [regional] entities.” 

Penney observed that of the seven reliability performance metrics the RE tracks, more than half either were improving or stable in 2023 compared to the previous year. These include resource adequacy — where reserve margins show sufficient resource capacity, and Texas RE has observed “a very positive trend” in winterization since the February 2021 winter storm — transmission performance, and protection system performance, where the misoperation rate decreased in 2023 and remains below NERC’s overall misoperation rate. 

However, the RE did note several areas where monitoring is needed, such as resource performance, which analyzes generator outage rates, primary frequency response and balancing contingency events to measure generation performance. Penney noted that while the RE has seen improvement in PFR performance, there also has been a long-term increase in equivalent forced outage rate, indicating times when generators have experienced forced outages when the units were needed to meet load.

Texas RE also identified issues in grid transformation, which measures the developing challenges associated with the shift to renewable resources. Penney said the report will discuss the need to monitor the drop in solar performance in evening hours and how it impacts reliability, as well as the decrease in system inertia levels that may leave the grid open to disruption.

Along with these issues, Penney discussed the physical security risks to electric equipment, which have risen across most categories in recent years. For example, the RE counted 15 gunshot incidents involving power stations in 2023, up from three the year before. A similar increase was reported in theft incidents, while the number of intrusion events rose from 18 to 20. Penney said the number of physical security events has continued to rise this year, indicating “this is a risk that’s definitely not going away.” 

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SPP Monitor Collins Joins ERCOT as VP of Market Ops

ERCOT said May 29 that it has hired Keith Collins, SPP vice president of market monitoring, as its new vice president of market operations, effective June 17. 

Collins will replace Kenan Ögelman, who retired as vice president of commercial operations in April. He will be responsible for ERCOT’s market analysis, performance and design, reporting to COO Woody Rickerson. (See “Ögelman Extends ERCOT Service,” ERCOT Technical Advisory Committee Briefs: March 27, 2024.) 

Collins brings more than two decades of experience in market operations and 25 years of experience in the electric power industry. He joined SPP in June 2017, serving under MMU Executive Director Alan McQueen during a brief transition period before taking over. Previously, he was CAISO’s manager of monitoring and reporting and a branch chief for FERC. Collins also worked with NYISO on market performance. 

“I look forward to the challenges and opportunities of working with stakeholders, regulators, legislators and [ERCOT’s Independent Market Monitor] to continue to develop and improve on one of the premier electricity markets,” Collins told RTO Insider. “I am confident that my background and experiences have prepared me for success in this role.” 

“With the Texas energy market rapidly evolving, ERCOT is focused on continuing to make improvements to market performance,” ERCOT CEO Pablo Vegas said in a news release. “A key component will be to review the current market design and behavior to drive positive market outcomes.” 

Collins has a master’s in public policy from George Mason University and a bachelor’s in economics and government studies from Bowdoin College. He also attended the Advanced Management Program at the Massachusetts Institute of Technology Sloan School of Management. 

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SPP’s REAL Team Moves Package of Policies

SPP’s resource adequacy stakeholder group has moved several policies that indicate the team’s work is “coming home” after months of presentations and discussions. 

“I know we’ve spent at least six, seven months on this now, so this is coming to a head and very important for the region,” Casey Cathey, SPP’s newly minted engineering vice president, said during a conference call with members of the Resource and Energy Adequacy Leadership (REAL) Team on May 24. 

The team plans to bring several policy issues and tariff changes to the July and August governance meetings, where SPP’s Board of Directors and its Regional State Committee hold the key votes. 

The REAL Team endorsed policies that set the base planning reserve margins (PRMs) at 36% and 16% for the winter and summer seasons, respectively, effective with summer 2026 and winter 2026/27; and extend the sufficiency valuation curve’s applicability so it applies to the three planning seasons beginning in 2026. 

Cathey said staff will circle back to the June REAL meeting with proposed tariff revisions that codify the policies. 

The team also approved a fuel assurance revision request (RR621) and agreed to evaluate and update the tariff’s cost of new entry, effective summer 2028. RR621 would add an “after-the-fact” application of fuel assurance based on historical performance, rather than imposing prescriptive requirements; it would be additive to the approved performance-based accreditation (PBA) methodology and meet the RSC’s directive to develop a policy incorporating PBA weighting based on critical system periods. 

In a separate motion, REAL directed the Supply Adequacy Working Group (SAWG) to evaluate and recommend summer 2029 and winter 2029/30 PRMs for the September REAL meeting. 

The team also agreed to staff’s request for support in developing potential use cases for the value of lost load in resource adequacy and transmission planning studies using a “willingness-to-pay” calculation. As the use cases are developed, the calculation will be evaluated and updated as appropriate. 

SPP is using willingness to pay for 30-minute, one-hour, two-hour and eight-hour outages, based on a recent study conducted by The Brattle Group for ERCOT. Its initial work has shown the weighted average of various commercial-and-industrial and residential sectors ranging from $35,863 for a half-hour outage to $220,592 for an eight-hour outage. 

ERCOT is using an interim VOLL of $25,000, and MISO is using $35,000 to create its operating reserve demand curve and a market VOLL (price cap and administrative price during load shed) of $10,000 to reflect a price that aligns with load that should be incented to shed. 

“The work done here kind of lays the framework for us to move forward,” Cathey said. 

REAL rejected an alternative reserve-retention proposal, submitted by American Electric Power, for cases in which load-responsible entities are not able to secure excess reserves. The proposal would have set accredited capacity (ACAP) requirements for 2026 using a 36% base PRM; LREs that voluntarily agreed to retain or sell excess reserves within the region would have their ACAP reduced to effectively meet a 33% base PRM. 

“This AEP proposal does step forward into the future, not just perpetuate this piecemeal reserve margin-setting process that we have before us,” AEP’s Richard Ross said. 

Golden Spread Electric Cooperative’s Mike Wise, supporting SPP’s proposed PRM changes, pointed out AEP’s suggestion had not been vetted through the LREs. 

“I do like [AEP’s] glide slope concept that he’s got,” Wise said. “The concern I have over Richard’s proposal is that it needs further work.” There would be “consequences intended and unintended that need to be really vetted and thought about.” 

Staff withdrew from REAL’s consideration an initial proposal for optional voluntary load-mitigation agreements between the RTO and LREs. An agreement would satisfy LREs’ deficiency for a transitional period during the summer and winter seasons. During a Level 3 energy emergency alert, the SPP would instruct voluntary load reductions pro rata among LREs with the agreements; additional load mitigation would be pro rata across LREs. 

“I hate this,” Ross said. “What about NERC penalties? I feel like this puts us in a situation where we are planning the system to not have adequate reserves. I fear that puts SPP in the position where they don’t have a good answer, and I don’t like NERC penalties.” 

“This is counter to what we’re trying to accomplish, right? Having resources out there that we can count on when we need them instead of not having a resource and somebody banking on shedding load,” Oklahoma Municipal Power Authority’s David Osburn said. “We could in essence be creating almost like a free rider that the rest of us are spending a lot of money getting resources available when we need them.” 

“The bottom line is if this idea is not well formed, if it’s not fully baked, maybe now’s not the time to act on it,” Cathey said.  

Looking ahead, Cathey promised more discussion on PRM stabilization policies at the next REAL meeting June 13 in Little Rock, Ark. He said the focus will be on accurate forecasting and stronger assumptions, with more frequent studies ensuring SPP is sending moderate signal changes and smoothing out capacity requirements over time. 

Staff will work with the SAWG to develop a plan for a plan, he said. 

“We haven’t spent a lot of time at the REAL on this,” Cathey said. “This is sort of a strategic and recommended approach for the REAL to work with the SAWG and really have the SAWG come up with some longer-term solution.” 

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MISO IMM Knocks LRTP Benefit Calculations; RTO Poised to Add More Projects

MISO’s Independent Market Monitor continues to cast doubt on the theoretical benefits estimates of the second long-range transmission projects as the RTO intends to add more projects to the already $17 billion to $23 billion portfolio.  

During a May 29 stakeholder workshop, IMM David Patton said MISO risks “substantially overstating” the benefits of its proposed, second long-range transmission plan (LRTP) portfolio. 

“We think transmission investment is extremely important, but it’s also expensive. So, it’s important that the transmission investment be economic. … Overinvesting in transmission has adverse effects on the market,” Patton told stakeholders at the workshop.  

MISO has not yet finalized the benefits it will use in the business case for the second LRTP portfolio, but it has signaled it will value decarbonization, reduced risks from extreme weather and the avoided costs of otherwise-necessary new capacity in addition to other, more traditional benefits. (See MISO to Present Final, $20B 2nd LRTP Portfolio in September.) 

Patton said MISO is on track to confer outsized benefits on its second LRTP portfolio because it doesn’t consider how the market would influence generation additions without the LRTP projects. He said it’s “not valid” for MISO to presume it will need more capacity in aggregate if it doesn’t build the second portfolio.  

Patton recommended MISO “eliminate altogether or fundamentally change” its proposed LRTP benefit derived from the avoided costs of adding capacity that otherwise would be necessary without the lines.  

“There is little basis to assume that transmission will affect MISO’s capacity requirements,” he said.  

Patton said absent major transmission, markets will facilitate the construction of generation to meet reserve requirements in areas where it’s more easily deliverable to load. He also said MISO isn’t optimizing its hypothetical generation siting in its transmission planning and that MISO’s zonal capacity needs would shift depending on whether LRTP lines are built. He said it’s worth MISO’s time to explore an alternative siting of future resources and simulate market responses without a second LRTP portfolio.  

“We can’t ignore those changes,” he said.  

For instance, Patton said MISO should factor in plans to restart Michigan’s Palisades Nuclear Plant in its modeling.  

“I just can’t see us not adjusting in the benefits analysis for those sorts of known” developments, Patton said. 

Patton also said MISO underestimates how additions of storage assets can mitigate some transmission congestion and chip away at the perceived congestion savings of LRTP lines.  

“Storage is really, really good at alleviating congestion due to transitory peaks,” he said.  

He also said MISO shouldn’t consider placing its own value on decarbonization because it’s already “baked into” the government’s production tax credits.  

“I really don’t think it’s MISO’s place to speculate on what the value of carbon is,” he said.  

Patton also said it’s not appropriate to calculate potential voltage problems without LRTP lines using the cost of load shed. He said no RTO resorts to load shedding when faced with voltage issues. MISO would be better served by calculating the cost of equipment to correct voltage issues, he said.  

Finally, Patton took issue with MISO attempting to quantify transmission’s role in reducing extreme weather risks to the grid, calling it “one of the most uncertain and speculative benefits.” He said MISO should use a lower, more realistic probability of extreme weather events occurring in the footprint.  

Sustainable FERC Project Attorney Lauren Azar countered that unlike transmission built on 10- to 15-year timelines, markets stimulate only near-term investments.  

Azar said if MISO followed Patton’s recommendations, it would be ignoring FERC’s recent Order 1920 to engage in long-term, scenario-based transmission planning.  

“I challenge your fundamental assumption that markets are the best driver of new lines,” Azar said. “I would caution MISO to follow your advice.”  

Azar said avoiding congestion is just one benefit of new transmission infrastructure, not the primary aim.   

Patton insisted he isn’t advocating for anything beyond appropriate customer costs for transmission expansion.  

Patton for months also has criticized MISO’s second transmission planning future as unrealistic. (See MISO Shelves IMM’s Transmission Planning Recommendation in State of the Market Report.) The second LRTP portfolio is based on that 20-year scenario, which predicts that by 2042, MISO will manage 466 GW of installed capacity, have a 145-GW peak load that occurs in January rather than July and have overseen 103 GW in generation retirements. It also expects its fleet will emit 96% less carbon pollution than it did in 2005.   

MISO Undeterred, Plans More LRTP Projects

Meanwhile, MISO likely will fill in its second LRTP portfolio with more projects than it originally proposed in its draft plan.  

MISO’s Jeanna Furnish said MISO has been evaluating alternatives and additional projects to its indicative map of transmission solutions under the second LRTP portfolio. She said MISO is poised to make seven additions of 765- or 345-kV projects in the Dakotas, Minnesota, Michigan, Indiana and Iowa and replace an original 765-kV project in Missouri and Iowa with segments of 345-kV line in the St. Louis metropolitan area.   

Furnish said MISO tested 47 of nearly 100 project alternatives suggested by stakeholders. MISO turned to stakeholders for more ideas after it revealed its draft plan in March.  

“The feedback we got is that we need to take a bigger step,” Executive Director of Transmission Planning Laura Rauch said. “It’s that guidance that helped us look at a bigger Tranche 2 portfolio than we originally envisioned.” 

American Transmission Co.’s Tom Dagenais thanked MISO for taking suggestions and being open to expanding the portfolio.  

Furnish said while “initial ideas were good,” MISO sought to improve the reliability and economic performance of the second LRTP portfolio. MISO said its lone replacement proposal for lower-voltage projects in St. Louis would provide congestion relief while increasing interstate transfers. It also said it could revisit the possibility of a continuous 765-kV line spanning Missouri and Iowa in the future.  

MISO planners didn’t address Patton’s critiques during the workshop.  

Later, in an emailed statement to RTO Insider, MISO said it “appreciates Dr. Patton’s report and will continue working on LRTP solutions through our stakeholder process.” The RTO did not say whether it plans to address Patton’s recommendation to axe certain benefit metrics.  

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Smaller Projects Expected from Maiden MISO-PJM Joint Tx Study

CARMEL, Ind. — MISO has told stakeholders not to expect sweeping, greenfield projects as a result of its new transfer capability study with PJM.  

Speaking at a May 29 Planning Advisory Committee meeting, MISO Director of Expansion Planning Jeanna Furnish said MISO and PJM anticipate sharing more details around possible projects in the first half of 2025. However, the projects probably won’t be staggering in scale. 

MISO Director of Economic and Policy Planning Christina Drake said MISO and PJM’s transfer capability study first must entail an engineering analysis before the RTOs begin future work on a new project type or adding a new cost allocation method to the MISO-PJM joint operating agreement.  

After prodding from state regulators and consumer groups, MISO and PJM in early May announced they would embark on a new type of interregional planning study. (See MISO, PJM Agree to Perform New Type of Joint Transmission Study.)  

Drake said MISO and PJM might create a new project type to expand interregional transfer capabilities.  

But she said MISO and PJM first need to “explore the edges” of their joint modeling. She said the first study will center on near-term construction, not the more complex, interregional projects that require greenfield development. The first study probably will aid “future work on project type and cost allocation,” Drake said.  

Drake said it’s likely MISO and PJM will identify project needs even though the study was described as “informational” by the RTOs.  

“Informational does not imply that we’re just going to post results and not bring anything forward,” Drake said.  

Invenergy’s Arash Ghodsian asked whether MISO and PJM’s study also will focus on interconnection upgrade needs on the seam that have been showing up for years in the RTOs’ interconnection queues.  

Drake said the focus of the study is strictly interregional transfers, not enabling more generator hookups, as is the case with MISO and SPP’s Joint Targeted Interconnection Queue study. Drake also said it’s unlikely MISO and PJM will develop a major, multivalue style project stemming from the initial study.  

Nevertheless, Ghodsian said the study is “long due” and Invenergy looks forward to the effort.  

Drake said MISO is meeting with PJM regularly on the nascent study.