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November 12, 2024

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FERC Orders Further Cold Weather Standard Modifications

NERC will go back to work on another revision to its most recent cold weather standard after FERC on June 27 accepted EOP-012-2 (Extreme cold weather preparedness and operations) while ordering additional “targeted modifications” to be completed by next March (RD24-5). 

The approval of EOP-012-2 brings to an end what FERC Chair Willie Phillips called the “second round on this particular standard” at the commission’s monthly open meeting. Phillips commended NERC for its efforts to improve the grid’s resilience to cold weather impacts while observing that there is still a lot of work left to achieve the goals in the commission’s cold weather preparedness dashboard. 

“The standard … has helped close some ongoing reliability gaps and address many of the outstanding commission recommendations on winterization,” Phillips said. “Nevertheless, I would be remiss not to note that there are still changes that need to be made to help the standard reach its full potential.” 

NERC’s Board of Trustees approved EOP-012-2 in February. The standard’s 12-month development period began after FERC accepted its predecessor EOP-012-1 last year. 

The first version, which has yet to take effect, outlined several measures for generator owners to implement to prevent their units from freezing during extreme cold weather events, along with situations in which GOs would need to submit corrective action plans. However, FERC said the standard should be further revised to clarify language and enhance some of its requirements. 

EOP-012-2 underwent three formal comment and ballot periods before finally receiving the blessing of industry in January. (See Industry Approves New Cold Weather Standard in Final Vote.) NERC’s Board of Trustees had warned that it might have to step in to approve the standard if it looked like the ERO might miss FERC’s deadline — an authority it possesses under section 321 of NERC’s Rules of Procedure — but the successful ballot averted this possibility. 

FERC called the new standard an “improvement” to EOP-012-1 but said “some elements … are not fully responsive to the commission’s February 2023 order.” While it did not agree with the ISO/RTO Council’s request to remand EOP-012-2 to NERC for further revisions — which FERC observed would leave EOP-012-1 to go into effect Oct. 1 “despite its ambiguities and other identified issues” — the commission did identify some remaining shortcomings that still need to be overcome. 

FERC’s order directs NERC to submit another revised standard within nine months that: 

    • ensures that the standard’s generator cold weather constraint declaration criteria “are objective and sufficiently detailed” so that entities understand the requirements. NERC is to remove phrases such as “reasonable [or] unreasonable costs” and “good business practices” in favor of “objective, unambiguous and auditable terms.” 
    • allows NERC to evaluate and confirm the validity of cold weather constraints invoked by generator owners “to ensure that such declaration cannot be used to avoid” compliance with the standard or corrective action plans. 
    • shortens and clarify implementation timelines and deadlines for corrective action plans. 
    • ensures that any extension of a corrective action plan deadline beyond the maximum time frame provided by the standard is preapproved by NERC, and that GOs inform relevant entities of resulting extreme cold weather operating limits. 
    • implements more frequent reviews of generator cold weather constraint declarations to ensure the declaration is still valid. 

Noting the urgency FERC has “repeatedly expressed” for implementing cold weather standards, and the fact that the above directives are meant to “fully address issues identified in the commission’s prior February 2023 order,” FERC mandated that the ERO complete revisions to the standard within nine months. 

In a statement, NERC said it “appreciates FERC’s focus on reliability matters and will continue to work toward assuring the reliability and security” of the electric grid. 

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RI Sets 600-MW Energy Storage Target

Rhode Island is the latest state to set targets for energy storage system construction.

Gov. Dan McKee (D) signed the Energy Storage Systems Act into law June 26. It directs the state Public Utilities Commission to adopt a framework for adoption of tariffs to apply to grid-connected energy storage systems, and the Rhode Island Infrastructure Bank to develop programs and distribute money to help achieve the goals of the act.

It sets a series of targets for installation of storage over the next decade: 90 MW installed by Dec. 31, 2026; 195 MW by the end of 2028; and 600 MW by the end of 2033.

On a per-capita basis, the numbers are much larger than they might appear.

New York’s target is 6 GW — the most of any state, and 10 times higher than Rhode Island’s new target. But New York has nearly 18 times more residents than Rhode Island.

Rhode Island also has the lowest electricity consumption per capita of any state, according to the U.S. Energy Information Administration.

The legislation (2024-S 2499A, 2024-H 7811aa) cleared both houses of the General Assembly by wide margins.

“This bill sets concrete goals and action plans to build a resilient grid that can accommodate the green energy transition that is happening now,” Senate Judiciary Committee Chair Dawn Euer (D) said in a June 13 press release. “This is just one of many actions we will need to meet our diverse energy goals and ensure that Rhode Island keeps its commitment to a carbon-neutral future.”

Advanced Energy United cheered McKee’s signature.

“Energy storage is flexible, reliable, affordable and will be a game changer for Rhode Island’s power grid,” said Kat Burnham, the group’s Rhode Island lead. “Investing in energy storage technologies will drive economic development and job creation in the clean energy sector.”

In its March 2024 energy storage policy update, law firm Morgan Lewis listed 11 states with codified energy storage targets: California, Oregon, Nevada, Illinois, Virginia, New Jersey, New York, Connecticut, Massachusetts, Maine and Maryland.

Some states have a long way to go to reach their goals. The U.S. Energy Information Administration reported that as of November 2023, there were three categories: California (7,302 MW), Texas (3,167 MW) and the other 48 states (3,500 MW combined).

But EIA predicted 2024 would be a busy year for storage installation, if all plans in place come together on schedule.

Wood Mackenzie earlier this month reported 1,265 MW of storage was deployed nationwide in the first quarter of 2024, much more than the first quarter of 2023 but much less than the fourth quarter of 2023.

Rhode Island’s first utility-scale battery energy storage — a 3 MW system serving the Pascoag Utility District — went online July 7, 2022.

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FERC Accepts NERC ROP Changes, Drops Assessment Proposal

FERC this week accepted a set of proposed changes to NERC’s Rules of Procedure to allow the ERO to register owners and operators of inverter-based resources while ordering a compliance filing clarifying whether its proposal will ensure that all IBRs are registered (RR24-2). 

In addition, the commission withdrew an open proceeding to shorten the ERO’s timeline for its performance assessments from five to three years (RM21-12). 

The ROP changes are the first step in NERC’s three-year plan to satisfy a November 2022 order in which FERC directed the ERO to register IBRs that are not currently required to register with it but that are connected to the grid and, “in the aggregate, have a material impact” on reliable operation. FERC approved NERC’s work plan in May 2023. 

NERC submitted the ROP changes to FERC in March, requesting an expedited review period of 60 days. According to FERC’s order, NERC must finish modifying its registration processes by 12 months after the commission approved its work plan, identify owners and operators of relevant IBRs within 24 months and register them no later than 36 months. 

The changes apply to Appendices 2, 5A and 5B of NERC’s ROP, with the most important updates coming to Appendix 5B. These changes will create a new category of generator owners, Category 2 GOs, comprising entities that own or maintain IBRs that “either have or contribute to an aggregate nameplate capacity of greater than or equal to 20 MVA, connected through a system designed primarily for delivering such capacity to a common point of connection at a voltage greater than or equal to 60 kV.” 

A similar new category, Category 2 GOPs, will be created for generator operators that operate such equipment. Revisions to Appendices 2 and 5A were proposed to conform to this language. 

In its order, FERC said it was generally satisfied with NERC’s proposal. However, the commission observed that the ROP revisions specifically referred to “inverter-based generating resources,” which might be construed to exclude battery energy storage systems because they store energy rather than generate it. As a result, FERC directed NERC to submit a compliance filing within 60 days explaining whether the ROP changes would apply to owners and operators of BESS resources and, if not, how the ERO plans to include these and any other IBRs that could be excluded. 

In a webinar last month, NERC Vice President of Regulatory Oversight Howard Gugel said the ERO was currently using data from the U.S. Energy Information Administration and other sources to identify IBR candidates for registration. With FERC’s approval granted, NERC can also send a request for information on additional applicable resources to registered entities, starting with balancing authorities and transmission owners. 

Assessment Proposals Faced ERO Skepticism

FERC’s decision to drop its proposal for shortening NERC’s performance assessment timeline comes three years after the commission first floated the idea in 2021.  

At the time, the commission, under Chair James Danly, said a quicker turnaround would “provide better continuity” in FERC’s oversight of the ERO Enterprise and its ability to identify potential performance improvements more quickly. 

The 2021 Notice of Proposed Rulemaking also suggested allowing FERC to request additional information beyond the statutory requirements of the performance assessment; NERC would have to honor any such requests submitted at least 90 days before the assessment’s publication date. In addition, the NOPR would have required the ERO to solicit recommendations from industry stakeholders for improvements to its “operations, activities, oversight and procedures.” 

NERC and the regional entities objected to the proposals despite recognizing the commission’s interest in “effective and efficient communication, coordination and feedback objectives.” (See ERO Enterprise Resists FERC’s Assessment Proposal.) The ERO said a three-year assessment cycle might not allow it to conduct the same level of review that it currently does in its performance assessments.  

NERC also pointed out that it already posts its draft performance assessments for public comment three months prior to submission, which should give stakeholders enough time to submit feedback. Regarding FERC’s proposal for requesting additional specific information, the ERO said it was open to such requests but 90 days was not sufficient notice. 

FERC’s June 27 order acknowledged the ERO’s concerns and concluded that “modifying the periodicity or procedural requirements for the ERO performance assessments is [not] an efficient use of ERO or commission resources.” The commission emphasized that withdrawing the NOPR and terminating the proceeding was an exercise of its own discretion. 

In a statement, NERC acknowledged the end of the proceeding and noted that it is currently preparing its assessment for the 2019-2023 period, a draft of which was posted for comment in April. (See NERC Makes Case for Recertification in Performance Assessment.) 

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Supreme Court Grants Pause of EPA Good Neighbor Rule

In a 5-4 decision on June 27, the U.S. Supreme Court issued an emergency pause on the implementation of EPA’s “Good Neighbor Plan,” which is aimed at reducing ozone pollution, a key component in the creation of smog.

The plan stems from a 2015 update of ozone air quality standards. Based on these tightened standards, EPA ruled in 2023 that 23 states had not submitted adequate plans to prevent harmful levels of pollution flowing to downwind states.

Lower courts already had temporarily paused the plan’s implementation in 12 states, and the Supreme Court sided with a coalition of Republican-led states, along with industry groups, in its ruling that the EPA likely has not justified the applicability of its plan to a smaller subset of states than initially proposed. (See Supreme Court Skeptical of EPA’s Good Neighbor Plan.)

The legal challengers included Ohio, Indiana and West Virginia, along with Kinder Morgan, the American Forest and Paper Association, and U.S. Steel.

The opponents contended that the emissions-prevention measures required by the plan are contingent on the states included in the plan, and therefore the exemption of one or more of the states invalidates the cost-benefit analysis the rule was based on.

Responding to this argument, EPA said the plan’s requirements are independent of the other states included.

Justice Neil Gorsuch — joined by Chief Justice John Roberts and Justices Brett Kavanaugh, Clarence Thomas and Samuel Alito — wrote that a stay on the plan is warranted because its opponents “are likely to prevail on their argument that EPA’s final rule was not ‘reasonably explained.’”

“EPA did not address whether or why the same emissions-control measures it mandated would continue to further the [Federal Implementation Plan’s] stated purpose of maximizing cost-effective air-quality improvement if fewer states remained in the plan,” Gorsuch wrote, adding that the 12 states already excluded from the plan account for most of its targeted emissions.

Justice Amy Coney Barrett broke with her fellow conservatives on the court to author the dissent, supported by the court’s three liberal justices. She said the majority based its decision on “an underdeveloped theory that is unlikely to succeed on the merits.”

Barrett noted that none of the 23 states proposed to take any action to reduce ozone emissions to comply with the 2015 regulations, and because no state has been permanently exempted from the plan, it “may yet apply to all 23 original states.”

She added that the Good Neighbor Plan does consider differences between states when establishing state-specific emissions budgets; that EPA relied on national data when setting the rule’s emissions limits; and that the agency “did not depend on the number of states in the plan.”

Fossil fuel and industry groups applauded the decision, arguing that the plan would hurt grid reliability and increase electricity costs in the affected states by driving coal plants into retirement.

“We are pleased that the court recognized the immediate and irreparable harm this rule would do to utilities and ratepayers,” Michelle Bloodworth, CEO of the coal lobbying group America’s Power, said in a statement.

Bloodworth called the rule “yet another example of EPA overreach,” and expressed her hope the courts will permanently strike down the rule.

Jim Matheson, CEO of the National Rural Electric Cooperative Association, said the decision “directly speaks to the gravity of EPA’s unlawful ozone transport rule which directly threatens the American economy and way of life.”

Meanwhile, climate and environmental advocacy groups said the court’s ruling will have major climate and public health consequences.

Conservation Law Foundation President Bradley Campbell told RTO Insider that the rule is “another example of the Supreme Court’s new majority using its ‘emergency powers’ to obstruct EPA rules it doesn’t like.”

“This is going to directly impact the health and life expectancy of communities in downwind states that historically have been overburdened by pollution,” Campbell said. “It’s clear that the new Supreme Court majority is going to use every tool at its disposal either to overturn or at least significantly delay new EPA protections and safeguards, and that’s going to result in a lot more illness and premature death.”

The decision comes as the Supreme Court appears poised to overturn or significantly roll back the Chevron doctrine, which directs courts to defer to the reasonable judgment of regulatory agencies in the absence of clear direction from Congress. (See Supreme Court Hears Oral Arguments on Overturning Chevron and Energy Lawyers Debate the Impact of Losing the Chevron Deference.)

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FERC ANOPR Seeks to Move the Ball Forward on Dynamic Line Ratings

FERC is moving forward on its examination of dynamic line ratings (DLRs), with the issuance of an Advance Notice of Proposed Rulemaking (ANOPR) on June 27 indicating the commission is considering requiring the transmission industry to adopt the technology (RM24-6). 

DLR technology uses the latest weather forecasts and monitors other conditions — such as sunlight and wind speed — to more accurately reflect transmission line ratings, allowing for more efficient power flow and reducing congestion. 

“Our success in ensuring reliability and operability of our nation’s transmission grid requires work on many fronts,” FERC Chair Willie Phillips said in a statement. “Last month, we took the major step of issuing Order No. 1920 to determine how to plan and pay for transmission facilities that our nation will need. Today, we are looking to wring efficiencies out of the grid so we can make the best and most efficient use of what we already have.” 

The ANOPR reflects public comments FERC received from a Notice of Inquiry issued in early 2022 alongside Order 881 that required transmission line ratings to reflect ambient air temperatures. (See FERC Opens Inquiry on Dynamic Line Ratings.) 

FERC will collect more information on DLRs based on specific questions it asks in the ANOPR before potentially moving forward with a proposed rule. Comments are due 90 days after the ANOPR’s publication in the Federal Register, and replies are due 30 days after that. 

Despite its earlier work, some implementation issues for DLRs still need to be worked out, Phillips said at a press conference that followed FERC’s monthly open meeting. 

“We look forward to moving as quickly as possible … to get a final rule in place,” Phillips said. “We can’t just build our way to where we need to go. We have to get as much as we can out of our existing system if we have any hope to not just reach goals, but to also serve our consumers reliably.” 

The factors that can change a line’s capacity include solar heating, cloud cover, wind speed and direction. The ANOPR asks whether hourly solar conditions should be reflected in all transmission line ratings and how to determine which lines would benefit from reflecting hourly wind conditions. 

The ANOPR had not been published as of press time. But a FERC fact sheet noted that reflecting hourly solar conditions would not require utilities to install any equipment to monitor them. But it “would go beyond the simple day/night considerations in Order No. 881 by requiring hourly forecasts of solar intensity and cloud cover events.” 

Wind conditions have the highest impact on line temperature out of any weather condition, but reflecting them does require the installation of sensors and communication equipment. “Recognizing this potential added cost, the ANOPR specifies that transmission providers could be required to reflect wind conditions in ratings only on lines that … are heavily congested and located in geographic areas with windy conditions,” FERC said. It seeks information on how congestion levels and environmental factors could identify the lines that would most benefit from better monitoring wind conditions. 

It also seeks comment on new methods for measuring congestion and other related data. 

Commissioner Allison Clements said that not implementing DLRs leaves significant benefits and cost savings on the table. 

“This has been a long time coming,” Clements said. “We first voted on DLR issues in December 2021. That’s nearly three years to move the ball forward several yards — with most of the field yet to cover. Best case, we are looking at another year for the NOPR and then a final rule, plus compliance and implementation after that. All of this emphasizes the need for good, thoughtful comments in response to this ANOPR, which sets up a promising framework.” 

LineVision, which makes the sensors that are sometimes required by DLRs, welcomed the ANOPR. 

“With demand spiking, extreme weather intensifying and increasing congestion straining overall grid capacity, today’s decision by FERC to initiate a rulemaking will help to ensure that dynamic line ratings become an even more critical tool in the toolbox to achieve a commonsense solution: squeezing all the capacity that we can out of our existing grid,” LineVision Vice President of Policy Hilary Pearson said in a statement. “We appreciate FERC’s continued leadership in advancing transmission line ratings solutions and pursuing criteria for DLR to help support just and reasonable rates.” 

Advanced Energy United also welcomed the proposal. 

“Transmission operators aren’t maximizing the potential of our power lines, leading to unnecessarily high energy costs for consumers,” Managing Director Caitlin Marquis said. “Dynamic line ratings are one of the most cost-effective tools we have for getting more out of our existing power grid infrastructure.” 

Clements’ Last Meeting

The meeting marked Clements’ last as a commissioner; her term ends June 30. 

She said she was particularly proud of the commission’s recent major orders: 1920 on long-term transmission planning and cost allocation and 2023 on generator interconnection rules. Also, she was glad to help set up the Office of Public Participation. 

“At this moment in time, when facts on the ground are changing so quickly, it is difficult to regulate at the pace necessary to keep up,” Clements said. “I urge the new commission to lean in and take a proactive approach to reliably and affordably adapting to the energy transition that is underway. Regulation will fail if it is deemed ‘ideological’ to try and skate where the puck is going. More than any time in our memory, the commission’s regulations must be nimble in the face of a changing energy system and new threats.” 

New Commissioner David Rosner sat in on the meeting, though he did not vote on any items because he had not had enough time to properly review them since being sworn in. His taking office means FERC is at no risk of losing a quorum once Clements leaves. He will soon be joined by Judy Chang and Lindsay See once they are sworn in. 

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FERC Approves Sloped Demand Curve in MISO Capacity Market

After two requests for more information and nine months, FERC has greenlit MISO’s plan to exchange its current, vertical curve for sloped demand curves in its seasonal capacity auctions (ER23-2977).

FERC said use of a downward-sloping curve in MISO should “reduce volatility in auction clearing prices, increase the stability of the capacity revenue stream over time and render capacity investments less risky, thereby encouraging greater investment and at a lower financing cost.” The commission pointed out that it has approved similar sloped curves in the PJM, NYISO and ISO-NE capacity markets.

“We find that using the proposed sloped demand curve will result in capacity price signals that reflect the marginal reliability impact of incremental capacity additions, provide better incentives for efficient resource entry and exit and, as a result, improve resource adequacy and economic efficiency across the MISO footprint,” the commission said in an order issued at its monthly open meeting June 27.

MISO CEO John Bear announced the approval during the Board of Directors’ meeting the same day in Eagan, Minn., to applause from stakeholders.

FERC addressed arguments from Midwestern transmission-dependent utilities and the Mississippi Public Service Commission that it foreclosed on the possibility for a sloped demand curve when it consistently found in previous orders that the RTO’s vertical curve was just and reasonable.

FERC said that its past orders finding the vertical curve sufficient did not mean that it would not entertain a proposal from MISO to change the design of the curve.

Prior to its approval, the commission twice said it needed more information before it could judge the plan. (See MISO’s Sloped Demand Curve Plan Draws 2nd Deficiency Letter.) Both times, the commission focused on MISO’s proposal to remove its annual price cap for auction clearing prices as part of the move to sloped demand curves. It said it required more explanation for the RTO’s proposal to eliminate the yearly cap.

The commission ultimately found that it is appropriate under the sloped demand curve for clearing prices to reach as high as four times the cost to build new generation. It said MISO is free to scrap its current annual price cap of 1.75 times the cost of new entry (CONE) for local resource zones (LRZs).

MISO has said that once it implements the sloped curves, the total annual price for an LRZ could reach as high as four times CONE, depending on whether capacity shortages occur in all four seasons of the auction. The RTO didn’t explicitly list an annual price cap in its new tariff language, telling FERC it isn’t necessary because its plan limits clearing prices to seasonal CONE values. It also said there’s only a small chance a zone would experience shortage conditions in all four seasons, and if that occurred, the more than $1,300/MW-day prices that ensue would properly reflect an “extreme” situation.

This year’s CONE value averages $330/MW-day. MISO has said its sloped demand curves won’t allow prices to automatically jump to CONE values for small capacity shortages below reserve requirements, unlike the current, unyielding vertical demand curve.

FERC agreed that sloped curves will result in a more nuanced pricing of shortages, rendering an annual price cap no longer necessary.

“Given that the sloped demand curve more accurately reflects the value of the increase or decrease in reliability of one additional (or one fewer) megawatt of capacity, under a small megawatt shortfall scenario, the auction clearing price will increase more gradually than it would with a vertical demand curve, and the capacity price will not rise to CONE unless MISO is experiencing a severe capacity shortage,” the commission reasoned.

It agreed with MISO that sloped curves will moderate pricing extremes and produce more “graduated and meaningful” price signals.

Commissioner Allison Clements wrote a concurrence to express a longstanding concern with the design of MISO’s seasonal capacity auction. She said that while downward-sloping demand curves in the auctions are a sound idea, she remains apprehensive over MISO appearing to allow sellers to compress their full annual costs into the seasonal offers they make.

Clements said that in the 2023 order accepting MISO’s seasonal auction design, the RTO’s testimony appeared to contradict its tariff language that seasonal offers may include only costs associated with providing capacity for that season. (See FERC Affirms MISO’s Seasonal Auctions, Accreditation.)

“My concern at the time was that if sellers can include their full annual costs into each and every seasonal offer, and they clear multiple seasons, they could receive in excess — potentially up to two, three or four times — their actual costs of providing capacity,” Clements wrote. “This risk is a direct result of MISO’s choice to conduct the four seasonal auctions for each delivery year simultaneously.”

Clements ended by asking MISO to consider conducting its auctions sequentially.

In a statement to RTO Insider, MISO said while offers generally are cleared on a seasonal basis in the auction, there may be “a situation where a unit clears one season but still needs to recover its full cost.” MISO noted that its Independent Market Monitor reviews all offers to make sure they’re appropriate.

“The sloped demand curve and seasonal construct are designed to work together to provide the right market signals to address the growing complexity of the system,” MISO said.

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AEP Selects Industry Veteran as Next CEO

American Electric Power, one of the nation’s largest utilities, said June 26 its Board of Directors has selected industry insider Bill Fehrman as its president and CEO, effective Aug. 1. 

Fehrman replaces Julie Sloat, who parted ways with AEP in February after just a year in the top job. Former Xcel CEO and AEP board member Ben Fowke, who has been running the company on an interim basis since then, will serve as a senior adviser during the transition. (See Interim CEO Fowke Explains AEP Leadership Change.) 

AEP’s new leader brings decades of industry experience. As infrastructure services company Centuri Holdings’ CEO, he helped launch the organization as a public company. Before that, he led Berkshire Hathaway Energy, MidAmerican Energy, PacifiCorp Energy and the Nebraska Public Power District. 

Fehrman said in a statement he was honored to join a “renowned industry leader” during the energy transition’s “pivotal time.” 

“AEP has built a strong foundation with a long history of solid operational and financial results and a focus on customers,” he said. “I see incredible potential in this company, and I look forward to working with the best-in-class team at AEP to continue delivering safe, reliable and affordable service to customers and advancing our long-term growth strategy.” 

“Bill is an accomplished leader and industry veteran with a proven ability to drive operational excellence, produce strong financial results and deliver for customers and stakeholders,” board Chair Sara Martinez Tucker said. “His expertise and unique perspectives will help AEP implement new solutions as we build the energy system of the future to power our communities.” 

AEP has 5.6 million customers in 11 states and several RTO markets. The Columbus, Ohio-based company says it plans to invest $43 billion over the next five years to make the electric grid cleaner and more reliable. It plans to reduce carbon dioxide emissions 80% from 2005 levels by 2030 and to achieve net zero by 2045.

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MISO Members Stress Need for Speed to Manage Load Growth, EPA Carbon Rule

EAGAN, Minn. — Members of MISO’s Advisory Committee have emphasized that all players in the footprint need to act swiftly to position themselves for “hyperscale” load growth and EPA’s new carbon rule.  

The Advisory Committee decided both topics were worthy of discussion at its quarterly meetup June 26.  

Carbon Rule

Multiple MISO members framed EPA’s carbon rule as not as industry-altering as it seems. They said the directives generally were where the industry is headed but underscored that the rule makes the inevitable play out faster.   

Minnesota Public Utilities Commissioner Joe Sullivan said some MISO states are less concerned about the rule because they’ve been gearing up for a decarbonized fleet. Other states in MISO are not as prepared, he said.  

Sullivan said to quote former Mississippi Public Service Commissioner Brandon Presley, “Where you sit on this is relevant to where you were standing.” 

“The rule might just be the current flavor of the uncertainty we’ve all been experiencing anyway,” Sullivan said. He added the rule “definitely” adds pressure to MISO’s capacity anxieties amid its first meaningful load growth in years.  

Ameren’s Jeff Dodd said the carbon rule’s 2031 implementation is a tall order and construction needs to move quickly.  

LS Power’s Sharon Segner said the rule underscores MISO’s obligation to hold developers to high standards so they meet project milestones on time with quality work.  

Sharon Segner, LS Power | © RTO Insider LLC

“We are indeed in serious times, and serious times need serious oversight,” Segner said.   

The Union of Concerned Scientists’ Sam Gomberg celebrated the carbon rule as the government “finally beginning” to address the perils of climate change.  

“This rule will protect what’s left of our functioning ecosystem that society depends on. … To quote my favorite scientist, Ray Stantz of ‘Ghostbusters,’ we’re talking real, rapid ‘wrath-of-God type stuff,’” he said. “The opportunity is one to save our own asses.” 

Gomberg said the most difficult thing about the rule might be wading through disinformation campaigns and politically motivated rhetoric. He acknowledged that members should redouble efforts around new transmission and generation projects alongside demand-side management. But he said he believes the expansion can happen swiftly and reliably.  

Paul Bailey, America’s Power | © RTO Insider LLC

“I think everyone would like some more flexibility [on the rule], but that ship has sailed when everyone has ignored the scientific evidence of the last 50 years,” he said.  

But Paul Bailey, of coal lobby group America’s Power, said the rule means “massive coal retirements very soon” with only about a 2% resulting reduction in carbon emissions nationwide. He said the rule rightfully concerns many, as evidenced by extensive litigation.  

Gomberg retorted that the coal industry’s trajectory isn’t affected much by the rule, save for the utilities that plan to keep coal plants online past 2039.  

“It doesn’t necessarily change the future all that much. We’ve been talking about the phaseout of coal for quite some time now,” Gomberg said.  

Wisconsin Public Service Commissioner Marcus Hawkins said the rule introduces concerns about the costs of stranded thermal assets. Sullivan agreed the potential for “ratepayer shocks” is worrying.  

Load Growth

Equally urgent is the need to address massive load growth from new data centers, members decided.  

Stakeholder Services Executive Director Suzie Jaworowski said the MISO region is experiencing data center growth, manufacturing reshoring and “big hyper-scale industry that needs unblinking power.”  

Tract’s Nat Sahlstrom, a guest speaker who was Amazon’s first hire dedicated to energy procurement, said utilities and RTOs aren’t equipped for the data center load growth that’s coming. He also said data center energy procurement is no longer as simple as a “tech guy in flip-flops and a baseball cap” approaching Dominion for an additional 5 MW.  

Utilities’ integrated resource plans are insufficient to meet the “scale and speed of cloud energy demand dynamics,” Sahlstrom said. He said the tech industry is partly to blame for distrust among utility planners because in the past, representatives would “clandestinely” approach utilities with promises for big demands for power that didn’t materialize.  

These days, Sahlstrom said data centers are more transparent about their needs and using “every electron that they’re asking for.” He also said though data centers are hungry for clean electricity, some run the risk of “greenwashing” by using utilities’ thermal units, then investing in far-flung renewable generation and deeming their renewable energy targets met.  

MISO Director Barbara Krumsiek asked if the industry is anticipating a public backlash to the “hyper-scale” of data centers and their zoning.  

“Frankly, I don’t want a data center near my church. They’re not horrible, but nobody wants that in their backyard in the same way they don’t want transmission lines in their backyard,” Sahlstrom said. He added that data center campuses these days are sited more thoughtfully and remotely. 

Clean Grid Alliance’s Beth Soholt said data centers share some of the characteristics associated with renewable energy development in terms of expanding tax bases, growing infrastructure and creating jobs.  

Soholt said there might be an opportunity for data center developers to build where renewable energy is flush and locational marginal prices are lowest in MISO.  

UCS’ Gomberg said MISO might need a new process to study large load additions and their impact on the system. He said he wondered if data centers might help pay for the manpower MISO may require to study new loads.  

MISO Director Phyllis Currie urged load-serving entities to recalibrate their load forecasts and update them more often with MISO with legitimate economic development.  

But Sullivan said he believes MISO regulators are anxious that utilities might “gild the lily” if probabilistic load forecasts are introduced and overstated load to pad bottom lines. He said it would help regulators’ distrust if data center representatives appear alongside utilities to assure commissions that the growth is real.  

“The solution to this has got to be more transparency and collaboration,” Sullivan said.  

Sahlstrom said data centers could stand to double a rural cooperative’s system demand within months after decades of stagnant load growth. He said developers are willing to pay for a “bespoke” integrated resource plan for their needs if the interconnection is a sure thing.  

NextEra Energy’s Erin Murphy said her company and others want MISO to create a designated market participation and registration for co-located load and generation behind the same point of interconnection. She said MISO should harmonize” its load growth studies completed under annual Transmission Expansion Plan (MTEP) with its studies for new generation through its interconnection queue. 

NextEra has suggested that the connected studies be reserved for “mega loads” and that MISO institute a minimum size requirement to consider the studies simultaneously. (See “NextEra Asks MISO to Study New Load and Generation Duos,” MISO Starting from Scratch on New Schedule for Reviewing Expedited Tx Projects.)  

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MISO Vouches for 2nd, $25B Long-range Tx Portfolio

EAGAN, Minn. — MISO reaffirmed its commitment to its second, approximately $25 billion long-range transmission plan (LRTP) portfolio while stakeholders asked MISO to be mindful of river crossings and whether it may reassign developers for the first LRTP portfolio’s projects in Iowa.   

“We’ve got the landing gear down,” Vice President of System Planning Aubrey Johnson told MISO board members of the near-final second LRTP portfolio during a June 26 System Planning Committee meeting, part of MISO’s quarterly Board Week.  

Last week, MISO announced it would take some stakeholders’ project suggestions and add seven more lines to its second LRTP, bringing the portfolio to between $23 billion and $27 billion. That’s up from an original estimate of $17 billion to $23 billion. (See MISO’s 2nd Long-range Tx Portfolio Jumps to About $25B.)  

Great River Energy’s Matt Ellis said the larger portfolio “is a significant but still very necessary step forward” in MISO transmission planning.   

Johnson said he believes MISO’s current LRTP work, coupled with its annual Transmission Expansion Plans, “puts us in a position to be generally compliant with FERC Order 1920.” He said MISO nevertheless will conduct a gap analysis to unpack the 1,300-page rule and determine how it might need to alter its current planning processes to be in full compliance.

MISO Director Todd Raba said MISO deserves congratulations for having a strong-enough planning process that FERC used it as example.  

“I’ve been a firm proponent that we stay in front of the line,” Raba said during the June 27 board meeting.  

FERC Commissioner Allison Clements has said the commission modeled some of the comprehensive transmission planning rule on the planning MISO already conducts. (See MARC 2024 Displays Mixed Feelings on Transition Feasibility.)  

Johnson said MISO is further preparing for intensive system planning by transitioning its modeling to Energy Exemplar’s more sophisticated PLEXOS tool. He said MISO’s current capacity expansion modeling tool — the Electric Power Research Institute’s Electric Generation Expansion Analysis System (EGEAS) — is “at the very limits” of the variables it can simulate as the system becomes more complex.  

“That was in use when I was in college,” MISO Director Trip Doggett joked of EGEAS.  

Board members asked MISO when they can expect to see HVDC lines in LRTP portfolios.  

Johnson said MISO remains open to planning HVDC lines, but the second portfolio wasn’t an appropriate jumping-off point.

“We’re able to move to a 765-kV dominant voltage because of our work on the 345-kV system,” he said, implying that each portfolio builds on previous planning.  

Johnson also said MISO would be best served by HVDC lines that are at least 300 to 400 miles long. The second portfolio’s longest lines don’t exceed 300 miles, he said.  

Board members also expressed interest in the extent MISO uses artificial intelligence to chart new transmission.  

“I have a confession to make: I had really pushed against AI technology,” Johnson said, adding that he prefers to focus on making the system resource adequate first.  

However, Johnson said his thinking has changed of late and said MISO can use “tip of the iceberg” artificial intelligence now. For instance, he said MISO can feed an AI application with all past interconnection queue study results to create a search engine database and answer interconnection customers’ questions without sacrificing more staff attention.  

LRTP Mississippi Crossing Raises Specter of Cardinal-Hickory Creek

Xcel Energy’s Carolyn Wetterlin said she was apprehensive over the second LRTP portfolio calling for a line crossing the Mississippi River from Wisconsin’s Driftless Area into Minnesota. She said the line was reminiscent of the beleaguered 345-kV Cardinal-Hickory Creek’s controversial river crossing in the same region.  

Cardinal-Hickory Creek’s final mile to intersect Upper Mississippi River Wildlife and Fish Refuge remains tied up in litigation. The line was approved in 2011 as part of MISO’s MultI-Value Project portfolio. (See Cardinal-Hickory Creek Developers Appeal Injunction on Line’s Final Mile.)  

Clean Grid Alliance’s Beth Soholt said she similarly was “deeply concerned” about a new 765-kV line’s chances of crossing the river. She urged MISO to reflect on its route assumptions before it finalizes the portfolio.   

But ITC’s Jeff Eddy said Cardinal-Hickory Creek developers ITC and Dairyland Power Cooperative are “doing the hard work” to blaze a trail for future transmission development in the area.  

LS Power Senior Vice President of Transmission Policy Sharon Segner said the portfolio of 765-kV greenfield projects will be “tough by any standard” to get built. 

Variance Analyses for Iowa LRTP Projects

Finally, MISO announced it has embarked on variance analyses for the first LRTP projects located in Iowa due to uncertainties over who will develop the projects. MISO Deputy General Counsel Kristina Tridico said MISO doesn’t yet have a timeline to offer on the studies. 

Already-approved LRTP projects in Iowa have been in limbo since last year, when an Iowa court struck down the state’s right of first refusal (ROFR) law and halted regulatory permitting for LRTP lines that incumbent developers ITC Midwest, MidAmerican Energy and Cedar Falls Utilities elected to build under the ROFR law. (See MISO Asks Court for Injunction Reversal on Iowa LRTP Projects.)  

During the June 25 System Planning Committee meeting, Segner stressed the importance of conducting variance analyses on the Iowa LRTP projects. She noted that Iowa’s legislative session wrapped for the year with new ROFR legislation failing to gain traction (HF 2551). Segner said the inaction on a new ROFR law makes for “an appropriate time” for MISO to re-evaluate the project and assign new developers, if necessary.  

MISO performs variance analyses on transmission projects when they encounter schedule overruns, significant design changes or a 25% cost increase from original estimates. After completing the analysis, MISO can let projects stand, cancel them or assign them to different developers.  

Alliant Energy’s Mitch Myhre asked that the board remain focused on how the first LRTP portfolio’s lines are faring in state regulator processes. He said though the more expensive second LRTP is drawing the most attention now, it’s MISO’s obligation to encourage and assist regulators and developers as the first, $10 billion batch of 345-kV lines progresses. 

“There’s a role for the board to continue to monitor and assess … timelines and barriers,” Myhre said.  

MISO Director Nancy Lange agreed with the MISO community that the first LRTP portfolio is not in the rearview mirror.  

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MISO: Calm Spring no Indication of Expected Summer Challenges

EAGAN, Minn. — MISO said a quiet spring isn’t a portent for the months to come. Meanwhile, its Independent Market Monitor insists MISO needs to penalize renewable generators that do not bridle output when asked.  

Speaking during a June 25 Markets Committee of the MISO Board of Directors meeting, Executive Director of Market Operations JT Smith said between predicted summer heat, an active hurricane season and the seasonal capacity auction returning a shortfall in spring and autumn, MISO anticipates tense months ahead.  

“We should expect probably a nice, stressful summer for our operating folks,” Smith said. “A couple of capacity advisories shouldn’t be surprising.”  

Smith said MISO’s Planning Resource Auction in April showed the RTO’s capacity surplus eroded 30% when compared to last year, falling from an overall 6.5 GW to 4.6 GW. The auction returned sufficient capacity in all but Missouri’s Zone 5, where prices topped out at a $720/MW-day seasonal cost of new entry in fall and spring. (See Missouri Zone Comes up Short in MISO’s 2nd Seasonal Capacity Auction, Prices Surpass $700/MW-day.)  

However, Smith said MISO should have “a lot of other resources” at its disposal, referring to its load-modifying resources and imports. Soon after Smith spoke, MISO issued its first conservative operations instructions of the summer for about two hours in the North region.  

Board member Phyllis Currie pressed MISO on the health of MISO’s relationships with its neighbors, asking in particular about the potential for the Tennessee Valley Authority and MISO to forge a symbiotic relationship.  

Recently, MISO leadership have expressed disappointment in TVA because although MISO has assisted TVA with exports — especially during the December 2022 winter storm — TVA as a rule doesn’t flow power to MISO.   

“TVA is an interesting animal in the Eastern Interconnect. They are limited in who they can sell power to,” Smith said. 

Smith said MISO and TVA are working toward an emergency purchases agreement so the two can transact power when one is experiencing risk.  

“Not only is the coordination between PJM and MISO and SPP and MISO good, it’s as good as it’s ever been,” MISO CEO John Bear reassured board members of MISO’s RTO neighbors.  

In a spring lookback, Smith called April’s solar eclipse a good learning experience on solar forecasting. He also said MISO staff enjoyed the eclipse because MISO “walked out of it without hassle.”  

“This is the first time we’ve had a significant amount of solar on our system to have an impact,” Smith said. 

MISO also reported its system performed as expected May 11 during the largest, most severe geomagnetic disturbance across the footprint since 2005.  

Otherwise, Smith said MISO experienced a mild spring. He said spring’s peak at 97 GW on May 21 fell short of MISO’s forecasted 100-GW peak for the season. Load averaged 69 GW, in line with the previous three years, and real-time prices averaged $24/MWh, $2 lower than in 2023. Daily generation outages averaged 51 GW, a few gigawatts better than in previous years.  

Predictably, MISO set another all-time solar peak May 25 at 6.2 GW.  

“Expect that every board meeting for the next couple of years,” Smith told MISO’s board and stakeholders.  

IMM Says MISO Should Rein in Renewable Operators

Carrie Milton, of the Independent Market Monitor, said the spring saw a rise in unpredictable output due to renewable energy operators disregarding MISO’s instructions to curtail.  

Milton said control room operators were forced to manually intervene “extensively” this spring, with double the rate of manual redispatches and capping wind generation dispatch to bring flows under control of last spring.  

She stressed the IMM’s oft-repeated position that unchecked flows from renewable generation exacerbate transmission constraints, with wind operators having little incentive to dial back energy production when told by MISO. That leaves MISO operators having to intervene to maintain system integrity and bring flows back within line ratings.  

“It’s effective but very inefficient, and unfortunately, that inefficiency is felt throughout the system,” Milton said. She said not only does manual redispatch raise costs to serve energy, it prevents MISO’s dispatch from pricing congestion accurately and increases uplift payments to generation.  

Milton said MISO should introduce software that flags renewable energy owners when their output is exacerbating a constraint and is deviating from their dispatch instructions. If the dispatch flag is ignored, MISO should levy financial penalties, she said.  

“They don’t always know when there’s a constraint,” Milton said of wind operators.   

Milton said MISO’s wind forecasting also is to blame, and MISO needs to work to reduce forecasting errors. She also said MISO should train its control operators to adjust transmission constraints so its dispatch model can manage constraints optimally.  

Over spring, MISO said it experienced $449 million in real-time congestion while wind operators churned out 26 TWh. MISO has acknowledged that uninstructed deviations are worse now than before it introduced the rules to curb them and said it will work with the IMM on potential new rules and software. (See MISO: Worsening Uninstructed Deviation Needs Attention.)