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July 7, 2024

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‘Evolution’ Key Theme at IPPNY 2024 Spring Conference

ALBANY, N.Y. — The Independent Power Producers of New York (IPPNY) celebrated its annual spring conference March 19 by marking the state’s transformation into a competitive energy market over the past 25 years with the inception of NYISO. 

Industry experts from the government, business sector and advocacy groups shared their insights on New York’s progress in evolving its energy markets, echoing sentiments from last year’s conference. (See Overheard at IPPNY 2023 Spring Conference.) 

FERC Chair Willie Phillips | © RTO Insider LLC

FERC Chair Willie Phillips discussed how the commission’s priorities have shifted toward improving “transmission to figure out how to better integrate new resources onto the grid,” enhancing the “grid’s physical and cybersecurity infrastructure,” and promoting environmental justice, which he considers a “top priority.” 

Suedeen Kelly, a partner at Jenner & Block and former FERC commissioner, concurred, saying that while the initial goals of establishing competitive markets centered around “efficiency, lowering costs and innovation,” they have shifted to include “decarbonization and the recognition of environmental and social justice” as the grid and energy markets have evolved and new generation technologies have emerged. 

Kelly praised New York’s market evolution, thanking participants for their efforts “to continue to meet the challenges of new technologies and incorporating those technologies into your market, since you’re taking huge risks to do this.” 

IPPNY President Gavin Donohue remarked in the same panel that the “competitive energy market has evolved into a bipartisan issue,” which will help to “lay the foundations for the future.” 

New York PSC Chair Rory Christian | © RTO Insider LLC

New York Public Service Commission Chair Rory Christian emphasized the theme of market evolution during his keynote address, highlighting how the commission’s decisions ensure that New York’s energy markets continue to adapt with the times. “Our daily lives depend on our ability to wield the magic of new technologies” he said, and “our actions can mean the difference between opportunity and calamity and can have ripple effects that extend far beyond our state borders.” 

“The commission has been able to lead and innovate,” he added, recognizing the need to develop a more holistic and adaptable approach that “ultimately culminated in a departure from vertically integrated utility models to a restructured wholesale energy market that incorporates competition.”

C. Lindsay Anderson, a professor of biological and environmental engineering at Cornell University, spoke about the growing recognition among New York energy stakeholders that to meet the state’s energy priorities and mandates and “to decarbonize everything, [we must] first decarbonize the power system.”

Panelists at the “Lobbying the Legislature and Executive Branch – Important Topics this Session” panel discussed how their clients and objectives have also evolved in response to New York’s policies. 

Elizabeth Garvey, an attorney at Greenberg Traurig, noted how she’s observed a shift in how political and corporate clients focus on broader engagement.  

“These years, unlike past years … [clients] really focus on all of [the market’s] issues wherever they sit in the energy economy … even if it doesn’t directly impact [them],” Garvey said. 

She added that the state’s evolving market and policies have led to an “inflection point” where it has become increasingly difficult to tell clients “where they should park their capital” since “there are so many different things happening on so many different playing fields” both in New York and across the nation. 

IPPNY

Will Hazelip, National Grid | © RTO Insider LLC

Will Hazelip, president of National Grid Ventures, US Northeast, said modernizing the transmission system is one of the biggest future challenges for New York and the country.  

“Redoing the transmission system will help enable power to move around” and also help clients “know for certain when they can build and then plug in,” he said. 

Phillips summarized the evolving perspective of conference panelists and the wider industry, saying, “As we celebrate the 25th anniversary of the [New York] market, the subtitle has been ‘cleaner, safer and cheaper,’” but “what I now say is ‘reliable, affordable and sustainable.’” 

“We need a new generation to think differently about our problems,” Phillis said, noting how energy markets, technologies and policies have evolved.  

The industry can no longer pretend “the benefits of our transition fall evenly on everyone,” he said. 

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Texas PUC Establishes $5B Energy Fund

The Texas Public Utility Commission on March 19 adopted a rule establishing the Texas Energy Fund In-ERCOT Generation Loan Program, a $5 billion fund designed to bring new dispatchable power projects to the state. 

The rule establishes the fund’s application process, project eligibility requirements, evaluation criteria and loan terms. The low-interest loans can be used for new dispatchable generation facilities or to expand existing facilities within ERCOT (55826). 

Qualifying projects for the Texas Energy Fund (TEF) must add at least 100 MW of new dispatchable capacity to the grid. The PUC says the program can support up to 10 GW of new or upgraded generation capacity in ERCOT. 

“As our state’s population and economy grow, so does the demand for electricity, and we must ensure Texans have the power they need, when they need it,” PUC Chair Thomas Gleeson said in a statement. “This rule lays a strong foundation for the Texas Energy Fund’s success and for future investment in the state.” 

Speaking on a panel during the recent CERAWeek 2024 by S&P Global conference in Houston, NextEra Energy’s Michele Wheeler, vice president of regulatory and political affairs, said the market indicates the fund will be oversubscribed. 

“We hope that’s the case,” she said. 

NRG Energy’s interim CEO, Larry Coben, said in February the company plans to apply for up to $900 million in TEF loans to finance construction of two new natural gas-fired plants that would be available in 2026. Coben reiterated during CERAWeek that the two peakers and another baseload plant will add 1,500 MW to the Texas grid. 

Companies can begin applying for the in-ERCOT program June 1. Initial disbursements for approved loans will be issued by Dec. 31, 2025. 

However, supply chain issues could pose a significant roadblock, commissioner Jimmy Glotfelty said during the March 21 open meeting. He recounted a conversation he had during CERAWeek with a Siemens senior executive. 

“He said, ‘Good luck with getting a combustion turbine before 2031,’” Glotfelty said. “If the market [is] seeing a massive delay in this major equipment, I think that is something that really has to be conveyed to the legislature and to us so that we don’t get in a bind.” 

One of the TEF’s four programs, an early completion bonus, awards grants to new dispatchable generation facilities that meet certain planning requirements after June 1, 2023, and interconnect to the ERCOT grid before June 1, 2029. 

The commission agreed with stakeholders to change the rule’s performance standards and ordered the revisions during the meeting. The performance availability factor (PAF) was reduced from 90% to 85% and the performance outage factor (POF) rose from 10% to 15%.  

Gleeson said in a memo he was persuaded by commenters who said the performance metrics would be “very difficult to achieve” throughout the loan’s term for units operating under standard operating processes. The commenters said that because of the length of planned maintenance outages and “unforeseen operational issues” during the early years of a plant’s life, additional flexibility in the PAF and POF metrics is “both necessary and reasonable,” Gleeson said. 

In addition to the In-ERCOT Generation Loan Program, the rule establishes TEF programs providing: 

    • completion bonus grants for new dispatchable generation projects that “consistently provide power generation over a 10-year period”;
    • grants for companies to establish or secure back-up power resources; and
    • grants to improve electric service resiliency and availability outside the ERCOT region. 

The Texas Legislature could provide additional TEF funding in future years, the PUC said.  

PUC staff determined switchable resources providing energy to both ERCOT and SPP are not eligible for the fund, as they are not totally committed to the Texas market. However, they will be eligible for completion bonuses because the law does not make a distinction between ERCOT and non-ERCOT resources. 

“We want 100% of the new capacity generated to be dedicated to the ERCOT market,” PUC staffer David Smeltzer said. 

The TEF is a result of legislation passed last year (Senate Bill 2627). Texas voters overwhelmingly approved the fund in November as a constitutional amendment. (See 2023 Elections Bring Billions for Texas Gas, Dem Wins in Virginia, NJ.) 

“Voters … made it clear that reliable electricity is a top priority,” the bill’s author, state Sen. Charles Schwertner (R), said. “We must expand and strengthen our on-demand, dispatchable power generation in order to deliver the reliable electricity all Texans expect and deserve.” 

ERCOT Preps for Solar Eclipse

ERCOT COO Woody Rickerson told the commission the grid operator is preparing for the April 8 total solar eclipse and does not expect reliability problems, using lessons learned from October’s annular eclipse. 

“ERCOT will pre-posture the system just like we did previously as necessary to meet both [solar’s] down ramp and the up ramp,” he said. 

The eclipse will cross Texas from the southwest to the northeast between 12:10 p.m. and 3:10 p.m. CDT, with sun coverage ranging from 81 to 99%, ERCOT said. Solar generation is projected to dip as low as about 7.6% of its maximum clear-sky output at about 1:40 p.m. 

“That’s a pretty big ramp down,” Rickerson said. “We are fortunate that this solar eclipse is occurring in April and not August.” 

ERCOT is working with solar forecast vendors to ensure models account for the eclipse’s effect. Ancillary services will be used for additional balancing needs. The first market notices will go out March 28, with additional communications to the market following. 

The ISO breezed through a test case in October. Solar production dropped from just over 7,000 MW to 1,474 MW as the eclipse’s “ring of fire” traversed Texas. Natural gas resources helped compensate for the solar drop, increasing generation by more than 4,000 MW increase. (See ERCOT Smoothly Handles Annular Solar Eclipse.) 

Texas A&M University’s Smart Grid Center has made public a visualization of the eclipse’s effect on solar generation across Texas. ERCOT has about 22 GW of installed solar capacity. 

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PJM Awaiting FERC Response to Court Rejection of 2024/25 Capacity Auction Parameters

VALLEY FORGE, Pa. — The future of the 2024/25 Base Residual Auction (BRA) results is uncertain following a ruling from the 3rd U.S. Circuit Court of Appeals partly vacating a FERC order authorizing PJM to change an auction parameter after bids had been received (ER23-729).  

The court’s March 12 ruling found the commission violated the filed rate doctrine in accepting a PJM proposal to revise the locational deliverability area (LDA) reliability requirement for the DPL South zone, which covers much of the Delmarva peninsula. 

PJM sought the change after identifying a nearly fivefold increase in capacity prices due to the interaction between a “misalignment” in resources that offered into the auction and the expected resource pool with the determination of the reliability requirement. (See 3rd Circuit Rejects PJM’s Post-auction Change as Retroactive Ratemaking.) 

Speaking during the March 20 meeting of the Markets and Reliability Committee, Senior Counsel Chen Lu said the RTO anticipates court approval for a new course of action about early May, following a 45-day deadline for FERC to propose a new directive for PJM and about seven days for the court to review. He added PJM is not planning to request a rehearing or appeal of the ruling to the Supreme Court. That option is open to FERC and intervenors in the case. 

PJM Vice President of Federal Government Policy Craig Glazer said if rehearing or an appeal is sought, that could delay PJM knowing how to proceed with the capacity results. He added that the courts don’t have hard timelines on which they must act, raising the possibility that uncertainty around capacity prices could extend into the delivery year, which starts in June. 

“If rehearing is sought, it kind of freeze-frames everything,” he said. 

Lu said PJM is assessing the feasibility of rerunning the auction with the original LDA reliability requirement parameter for DPL South with the existing offers submitted in December 2022.  

PJM Senior Vice President of Market Services Stu Bresler said the RTO is in contact with FERC staff to provide perspectives on possible next steps. But he told the MRC he could not speculate about what those steps might be. If the auction did have to be run, he said the impact would likely spread outside the DPL South zone. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, encouraged PJM to remain in communication with FERC to encourage it to come to a resolution the court could accept as quickly as possible, noting that using the full 45 days it has to respond could put resolution of the dispute within a month of the start of the delivery year. 

“We’re right before the delivery year at this point; it’s really cutting this close, so I’m wondering if there’s a way to accelerate that time frame,” he said. 

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FERC Upholds, Clarifies Generator Interconnection Rule

FERC on March 21 rejected challenges to its new generator interconnection rules under Order 2023 while offering several clarifications, minor modifications and an extended compliance deadline. 

Issued in July, Order 2023 sought to clear backlogged interconnection queues by implementing a first-ready, first-served cluster study process; increasing interconnection customers’ financial obligations; and penalizing grid operators for missing study deadlines. (See FERC Updates Interconnection Queue Process with Order 2023.) 

The commission received 32 requests for rehearing or clarification of the order, which required changes to the pro forma large generator interconnection procedures (LGIP), pro forma large generator interconnection agreement (LGIA), pro forma small generator interconnection procedures (SGIP) and pro forma small generator interconnection agreement (SGIA). 

The rehearing requests were automatically denied when FERC failed to act on them within 30 days, but the commission addressed all the filings in the 1,063-page order issued at its monthly open meeting (Order 2023-A, RM22-14-001). 

Order 2023 is the subject of at least a dozen challenges filed in federal appellate courts since October. Challenging the order are PJM, SPP and NYISO; transmission owners in NYISO and MISO; utilities PacifiCorp, Avangrid, Exelon, Dominion Energy, Florida Power & Light and FirstEnergy; and Advanced Energy United. 

‘Not a Problem that Only Exists in Isolated Pockets’

The commission rejected complaints it exceeded its authority under the Federal Power Act and denied it had declared all existing interconnection tariffs — including recently approved revisions by PJM and Dominion Energy South Carolina — unjust and unreasonable. 

“The findings in Order No. 2023 relate to the commission’s existing pro forma generator interconnection procedures and agreements, which, among other things, relied on a serial first-come, first-served study process,” it wrote. “The commission did not make any findings regarding specific transmission provider’s tariffs, and it was not required to do so under FPA Section 206. Issues regarding the individual tariffs of specific transmission providers that currently deviate from the existing pro forma generator interconnection procedures and agreements will be addressed on an individual basis on compliance.” 

FERC said interconnection queue delays “are a nationwide problem, not a problem that only exists in isolated pockets,” noting that less than 25% of requested interconnection capacity reached commercial operation between 2000 and 2017 in every region, with some regions as low as 8%. 

“The commission carefully examined recent queue-reform proposals to identify best practices to implement nationwide. However, no transmission provider has yet adopted all of the reforms in Order No. 2023,” it said, adding that it “would be waiting a very long time indeed if it could not issue a generic rulemaking while any individual transmission provider pursues its own regional queue reform.” 

FERC also rejected PJM’s assertion that some transmission providers should be presumed to be in compliance with Order 2023: “While the majority of reforms adopted herein are based on individual and incremental improvements that one or more regions have already implemented, no transmission provider has yet to adopt the entirety of Order No. 2023’s broad suite of reforms,” it said. “Thus, we are unpersuaded by PJM’s arguments on rehearing that ongoing, recently approved interconnection queue reform packages presumably already comply with Order No. 2023. Applying a presumption to transmission providers who recently adopted some similar reforms, but not all the reforms contained herein, will only result in incomplete change that fails to fulfill or further delays the comprehensive reform required by Order No. 2023.” 

Changes

The revised order: 

    • specifies that interconnection customers in the queue of a transmission provider using or transitioning to a cluster study process must comply with the transmission provider’s new readiness requirements within 60 days of the effective date of the transmission provider’s compliance filing. The commission also added a new section, 5.1.2, to the pro forma LGIP, stating that transmission providers that have adopted a cluster study process or begun a transition to it will not be required to implement the transition process specified in Order 2023. 
    • specifies that a network upgrade required for multiple interconnection customers in a cluster may be considered a standalone upgrade if the customers agree to build. It agreed with Advanced Energy United, the American Clean Power Association and the Solar Energy Industries Association that it should revise the definition of standalone network upgrades to maintain the pre-Order 2023 opportunity for interconnection customers to exercise the option to build as part of the cluster study process. 
    • requires transmission providers to complete their determination that an interconnection request is valid by the close of the cluster request window so that only interconnection customers with valid interconnection requests proceed to the customer engagement window. It set aside paragraph 234 of Order 2023 to clarify that an interconnection customer’s cure period ends at the close of the cluster request window at the latest. 
    • expands the acceptable forms of security for the commercial readiness and study deposits to include not only cash or an irrevocable letter of credit, but also surety bonds or other forms of financial security that are “reasonably acceptable to the transmission provider.” 

The order also provided clarifications on the allocation of cluster network upgrade costs; withdrawal penalties; study delay penalties; availability of surplus interconnection service; operating assumptions for interconnection studies; consideration of alternative transmission technologies; and ridethrough requirements. 

Acknowledging the changes it made, the commission also extended the compliance deadline from April 3 to 30 days after the publication of Order 2023-A in the Federal Register. 

Commission Acts on 3 Compliance Filings

In separate orders, the commission found Duke Energy had largely complied with Order 2023 but gave Idaho Power and Arizona Public Service lengthy to-do lists. FERC ordered the utilities to file revised provisions within 30 days of publication of Order 2023-A in the Federal Register. 

Duke Energy

The commission found that Duke Energy Carolinas and Duke Energy Progress were fully in compliance but that Duke Energy Florida failed to fully comply (ER24-679, ER24-683). 

It required the Florida utility to modify or defend its definitions of “scoping meeting” and “transmission provider’s interconnection facilities” because they varied from in the commission’s pro forma LGIP, and it said the utility had not fully complied with the order regarding the allocation of cluster study costs and site control.

Idaho Power

The commission gave Idaho Power a mixed grade, faulting it for “various unexplained revisions throughout” its LGIP, pro forma LGIA, SGIP and pro forma SGIA (ER24-10, ER24-1399). 

It cited the utility’s proposed definition of “generating facility” and insertion of “nonrefundable” when describing the $5,000 application fee in its LGIP. 

It also required the utility to make minor changes to its provisions regarding cluster studies and other changes to sections concerning affected-system studies, surplus interconnection service and provisional interconnection service. 

Arizona Public Service

FERC was most critical of APS’ compliance filing, saying the company had proposed “to retain a significant number of existing tariff provisions that deviate from the pro forma interconnection procedures and agreements” adopted in Order 2023 (ER24-330). 

APS said its proposals were justified because the commission approved several APS-specific interconnection changes in a September order — after issuing Order 2023. 

The commission disagreed. “Although the commission previously accepted certain deviations proposed by APS in its queue reform filing, the commission evaluated the queue reform filing under the commission’s pro forma interconnection procedures and agreements in effect at the time — that is, those adopted in Order Nos. 2003, 2006 and 845, without the modifications adopted in Order No. 2023,” it said. “As such, the commission’s findings in the queue reform order have no bearing on whether APS has satisfied its obligation to comply with the requirements of Order No. 2023.” 

The commission said APS had proposed deviations from the commission’s pro forma LGIP and pro forma LGIA regarding the cluster study process “without demonstrating how such deviations satisfy the ‘consistent with or superior to’ standard.” 

It also found APS only in partial compliance in its language on allocation of cluster study costs; network upgrades and interconnection facilities; study deposits; site control; commercial readiness provisions; withdrawal penalties; transition process; operating assumptions for interconnection studies; alternative transmission technologies and modeling; and ridethrough requirements for nonsynchronous small generating facilities. 

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Solar Developer Seeks Inslee’s OK for 60-MW Eastern Wash. Project

A Seattle-based company is proposing its second solar project in southeastern Washington. 

OneEnergy Renewables briefed the Washington Energy Facility Site Evaluation Council (EFSEC) March 20 about its proposed 60-MW solar farm near the Columbia River community of Plymouth in southern Benton County. The Wallula Gap project also could include an optional battery energy storage system not to exceed the facility’s nameplate capacity, EFSEC said. 

The project would interconnect through a line tap to a Benton Public Utility District 115-kV line and then be connected to the Bonneville Power Administration grid at McNary substation in Umatilla, Ore. 

OneEnergy has another 80-MW solar farm, Goose Prairie, due to go online in early 2025 in adjacent Yakima County near the town of Moxee.  

On Wednesday, OneEnergy Associate Director for Development Nathan Stottler told the EFSEC that its Wallula Gap project is eyeing 392 acres of flat, partly rocky pastureland and hoping to complete construction by April 2026.   

In Washington, solar and wind power ventures can seek approval from either the appropriate county government or, after receiving recommendations from EFSEC, the governor. Benton County declared a moratorium on new solar and wind power facilities in 2021, leaving OneEnergy with the option of going through EFSEC for approval of Goose Prairie. (See Inslee Approves 80-MW Goose Prairie Solar Farm.) 

Benton County already opposes a proposed huge and controversial wind farm in the Horse Heaven Hills south of Kennewick. That developer — Scout Clean Energy of Boulder, Colo. — also is going through EFSEC.  

In February, EFSEC decided to set up a two-mile buffer around each known ferruginous hawk nest within the project’s 112-square-mile site. In 2021, the Washington Fish and Wildlife Commission unanimously heightened the status of ferruginous hawks from threatened to endangered. (See Washington Renewable Developer Rankled by Siting Board Alterations.) 

Scout’s plans call for either 222 wind turbines up to 500 feet tall or 141 657-foot turbines along a 24-mile east-west stretch of the Horse Heaven Hills. EFSEC’s Jan. 31 decision potentially would cut up to 116 of the shorter turbines or 73 of the taller ones from the project. The agency granted Scout’s request, giving it until April 30 to continue with the project. 

Gov. Jay Inslee (D) already has approved three solar projects in eastern Yakima County, including the 94-MW Black Rock project 20 miles east of Moxee and the two 80-MW High Top and Ostrea projects just west of the border between Benton and Yakima counties. 

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MISO Members Mull Full Impact of DER Aggregations in Markets

DALLAS — MISO members pondered at Board Week how quickly the full impact of Order 2222 will be felt across the footprint.  

During a March 20 Advisory Committee meeting, WEC Energy Group’s Chris Plante said it’s difficult to pinpoint the contribution of aggregated DERs across MISO because state regulatory authorities have differing views on how DER aggregation programs should look. 

Fresh Energy’s Mike Schowalter also predicted a “scattered approach” among MISO utilities.  

MISO doesn’t yet have FERC’s go-ahead to proceed with its implementation plan. The commission said MISO has a few kinks to work out, namely how it will manage cybersecurity, dispute resolution and reformulating a go-live date sooner than MISO’s initial 2030 target. (See Stakeholders Ask MISO to Share New Order 2222 Go-live Date ASAP.) 

Executive Director of Market and Grid Strategy Zak Joundi said Order 2222 means bringing together “a lot more parties,” and jurisdictions with responsibilities outside of the MISO tariff.  

Minnesota Public Utilities Commissioner Joseph Sullivan said the Organization of MISO States’ annual DER surveys found approximately 12.5 GW of DERs across the footprint, some ripe for aggregations.  

“I think we’re all over the map in terms of expectations,” said ITC’s Brian Drumm, representing MISO’s transmission owners. He said the complexity of the order’s aims is compounded by the fact some technology to harness aggregated DERs is undeveloped. 

Minnesota Public Utilities Commissioner Joseph Sullivan | © RTO Insider LLC

“This is going to take a lot of time. This is a very expansive order. There’s a lot of work to be done that’s kind of nebulous and very broad,” Drumm said.  

“Where there is meat on the bone, where there is money to be made, participants will find their way into the market,” the Union of Concerned Scientists’ Sam Gomberg said. He predicted steady, slow-moving work preparing markets for DERs and then “a rapid, widespread adoption” of rooftop solar, electric vehicles and distributed storage.  

Gomberg said it would be a “missed opportunity” to not prepare and be forced to “scramble” and seek a pause when MISO reaches the described DER tipping point. 

MISO Director Nancy Lange asked if utilities’ distribution systems can handle aggregations efficiently and economically. 

“We’ve taken steps,” Alliant Energy’s Mitch Myhre said, referencing investments in communication systems, distribution upgrades, energy management systems and fiber technology.  

Xcel Energy’s Susan Rossi also said MISO’s transmission owners are investing in advanced metering management systems, calling them the “building blocks” of Order 2222.  

“We’re all in the space of where to invest the money. And of course, we’re sensitive to customer affordability,” Ameren’s Jeff Dodd said. Dodd added that no RTO is far enough along in incorporating DER aggregations in the market to “steal good ideas” from.  

“My sense is technically we’re capable,” Sullivan said, though he added he has reservations about utilities’ preparedness for the supply uncertainties aggregated DER offers will introduce.  

MISO Director Todd Raba said recent instances of demand response gaming in MISO markets begs the question of “who’s going to be the policeman” and discourage fraud in aggregations.  

“It has to be a multilevel responsibility and accountability structure. I think it’s MISO, it’s FERC, it’s state commissions. And that’s not to punt, that’s not to say that it’s no one’s responsibility,” Sullivan said.  

Drumm said he believed that stopping potential exploitation of MISO’s markets by DER aggregations “falls squarely” under the monitoring duties of the Independent Market Monitor.  

MISO will hold discussions on its new Order 2222 implementation date through April via the RTO’s Distributed Energy Resources Task Force. The task force was scheduled to sunset this year but has been extended through 2025.  

The RTO has until May 10 to file an updated implementation plan with FERC.  

“There are meetings we still have on the books before the filing,” Joundi said, encouraging stakeholders to weigh in on MISO’s second Order 2222 compliance filing.  

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MISO Says Rigorous Accreditation Key to Managing Future Market Ops, Reviews Mostly Calm Winter

DALLAS — MISO’s imminent filing for a new capacity accreditation is a crucial first step to prepare for a more complex and challenging future, executives told attendees during March Board Week.  

The added persuasion comes as MISO exited winter with no critical steps taken to maintain reliability.  

Executive Director of Market and Grid Strategy Zak Joundi said MISO’s growing reliability risks mean accreditation should be tied to resource’s output during hazardous periods. The RTO plans to file before the end of March to implement a probabilistic capacity accreditation, where capacity credits will be determined by individual past performance and a resource-class average performance during risky hours for different types of generation. (See MISO: New Capacity Accreditation Filing Imminent.) The accreditation style is marginal, using loss-of-load inputs instead of unforced capacity, and will chip away at solar generation’s capacity credits over the decade until they’re a fraction of what they used to be.  

MISO’s predicted capacity accreditation percentages in summer by 2032 | MISO

“Accreditation is one of the most important signals that we as an RTO can provide our members,” Joundi said.  

“The accreditation MISO is moving towards filing is one of the most important it will make in years,” MISO Independent Market Monitor David Patton agreed.  

“We have some controllable resources, but those are quickly disappearing,” Vice President of Operations Renuka Chatterjee added while talking about mounting risks during winter mornings by 2030.  

Chatterjee said for roughly the past month, MISO has been monitoring low system stability during weekends due to unprecedented renewable output.  

“I don’t want to scare folks. We are OK. We have tools to manage this. … But if we don’t do this work, we will be in worse shape by 2030,” Chatterjee said.  

Winter Storm Performance Improves

MISO appears to be getting well versed in steady operations amid increasingly volatile weather.  

Executive Director of System Operations Jessica Lucas said the RTO had no trouble handling a mild winter except for mid-January’s footprint-wide Arctic blast. The cold front delivered MISO’s 105.9-GW winter peak on Jan. 17. On that day, MISO South set a new winter peak at 32.6 GW.  

The footprint also set a new wind generation peak of 25.7 GW on Jan. 17, where wind served 30% of load and buoyed the system above maximum generation alerts. (See MISO Holds Steady in Mid-Jan. Storm with Help from Wind.)  

“It does look like we’re creating a pattern. Three years and every year, another 100-year storm,” Lucas said, referencing “déjà vu” winter storms in February 2021 and December 2022. 

However, for this winter storm, MISO experienced just 5 GW in incremental unplanned outages, compared to 15-20 GW in added forced outages during the previous comparable winter storms. 

MISO Director Barbara Krumsiek commended the grid operator for improved performance during the deep freeze.  

“The first one, the first time is a shock to the system. But to see how MISO and its members have adjusted is gratifying,” Krumsiek said.  

Lucas said MISO’s better prep is due in part to its availability-based accreditation that’s been in place for thermal generation for about two years.  

She also said MISO’s new uncertainty management model flagged the winter storm span as high-risk days in advance, leading operators to increase the RTO’s short-term reserve requirements. Requirements averaged 5 GW over the event and climbed as high as 6 GW.  

Patton praised MISO’s progress on uncertainty modeling. He said MISO has been more dynamic in procuring reserves, which mitigates risks and ultimately lowers costs. 

“This is the kind of model that I wish Texas would incorporate,” he said. “I think [MISO is] on the forefront here.”  

At the Gulf Coast Power Association’s early March MISO-SPP conference, Executive Director of Market Operations J.T. Smith also said MISO’s model augmented by machine learning did a solid job predicting which generation showed up during the mid-January Arctic blast.

Smith said a pressure gradient over MISO Midwest could mean an up to 10 GW difference in wind production and that a 50-mile discrepancy in a winter storm’s path over MISO South causes vast differences in demand.  

“Our entire system is weather dependent,” Smith said.  

MISO also recently secured a $3 million grant from the U.S. Department of Energy to explore more machine learning and modernize control room operations. 

Patton said the RTO dramatically reduced its usual manual redispatch during the cold snap, instead allowing its transmission constraint demand curve to price generation to manage flows on the system. Patton said compared to the winter storm a year ago, this time MISO operators took 84% fewer out-of-market actions to manage congestion. He said if the latest storm had happened a few years ago, MISO operators probably would have made more commitments than necessary. 

“Overall, the management of the system during Winter Storm Heather was really good,” Patton said. “MISO exercised good judgment in commitment decisions and avoided unnecessary uplift, deferring decisions until necessitated by offered lead times.” 

Patton said MISO’s real-time revenue sufficiency guarantee payments totaled just $5 million, compared to the almost $90 million incurred in the February 2021 winter storm.  

MISO Director Phyllis Currie joked that she heard Patton complimenting MISO’s actions repeatedly. 

“Excellent. Then I must have missed something,” Patton said with a laugh.  

The IMM said over the winter, regional transfer generally flowed from South to Midwest. However, when the cold blast struck, flows shifted from Midwest to South.  

The IMM said drought conditions in the Manitoba Hydro service territory caused South-to-North flows over the winter. Ordinarily, MISO imports power from the hydroelectric utility. Members of late have been consistently exporting power across the border.  

Total congestion over the mid-January storm totaled almost $153 million, Patton reported.  

Patton said while overall congestion was more manageable during the latest winter storm, MISO did receive incorrect transmission flow data from a market participant, contributing to a transmission violation and MISO having to declare a safe operating mode to redispatch generation in PJM to get flows back in line with the rating.  

“This raises substantial concerns regarding the information some participants provide to MISO, which can impact reliability,” Patton said. “The same participant failed to provide SCADA data on a nuclear unit, which impacted MISO’s response to it tripping offline in mid-February.”  

Patton declined to name the market participant.  

“If this was going on, this would make me very unhappy, trying to operate the system without full and accurate data from all participants,” Patton said. He flagged the issue as a “big concern.”  

He also said that over Jan. 15 and 16, MISO “effectively ran out of generation” in the Southeast Texas load pocket; the area racked up severe congestion and prices jumped to $1,500/MWh. Patton said the situation subsided when a generator in the area that’s “almost entirely connected to ERCOT” decided to direct its output into MISO.  

Patton singled out the generator for consistently failing to show up in MISO during times of need despite participating in its capacity auctions. Patton said MISO should strike that generation from its capacity totals, and that the RTO should make the adjustment before its upcoming capacity auction, so it doesn’t count on generation that won’t materialize.  

MISO set a solar output record of 4.4 GW on Feb. 19, where panels managed 6% of load. The grid operator has had 12 new solar peaks over the past year as members swiftly add solar installations.  

MISO also said wind generation made its first appearance in the South during the winter quarter, with the debut of the 185-MW Delta wind farm in Tunica, Miss. A 180-MW wind farm, Nimbus, is planned to begin operations next year in rural Arkansas. 

Looking ahead, MISO said even high demand over the spring shouldn’t present challenges. Although MISO expects demand could top out at nearly 107 GW in May, the grid operator’s 113.6 GW of cleared capacity throughout spring appears sufficient. 

MISO is also planning for a rapid drop in output and then recovery among its growing solar fleet April 8, when the solar eclipse tracks across its footprint. Lucas said MISO likely will need greater-than-usual ramping capability and more congestion management efforts that afternoon. 

MISO spring capacity projections in GWs | MISO
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IMM Tells MISO to Do More to Curb Fake DR Schemes

DALLAS — MISO’s Independent Market Monitor told the Board of Directors on March 19 the RTO must crack down on confirmations to prevent more phony demand response from infiltrating its markets.  

Monitor David Patton said penalties for the string of demand response schemes have eclipsed $100 million. FERC in February put the squeeze on an obscure, Texas-based LLC formed to sell in-car ketchup holders to the tune of $27 million for offering faux load reductions. It was the third time recently a company was caught manipulating MISO’s demand response market and collecting unjustified payments. (See FERC Catches Ketchup Caddy Co. in Another Fake DR Scheme in MISO.) 

“When you move demand to the supply side, there’s certain things you need to do … to validate the demand response is actually real,” Patton said during a Markets Committee of the MISO Board of Directors meeting. 

Patton said he’s working with MISO to “remove vulnerabilities” from its ruleset regarding DR registrations and validations. He said the RTO must dedicate more resources to authenticating DR capabilities.  

MISO directors discussed recent instances of apparent DR fraud in a nonpublic session following the MC meeting. No board members stated their opinions publicly on the scams during Board Week.  

WEC Energy Group’s Chris Plante suggested MISO’s Advisory Committee schedule a discussion on the Ketchup Caddy situation and where responsibility for authenticating demand response market participants ultimately lands. 

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CAISO’s EDAM Scores Key Wins in Contested Northwest

HOUSTON — CAISO scored simultaneous victories in heavily contested territory on March 21 after Portland General Electric (PGE) and Idaho Power both signaled their intent to join the ISO’s Extended Day-Ahead Market (EDAM). 

The moves significantly boost EDAM’s position in the Pacific Northwest, a region where SPP’s competing Markets+ day-ahead offering has won a strong following among the network of publicly owned utilities entitled to low-cost power from the Bonneville Power Administration — which has been a key participant in developing Markets+ and expects to issue a market “leaning” next month. (See NW Cold Snap Dispute Reflects Divisions over Western Markets.) 

“This has been an important and consequential week for improving grid reliability and customer value in the West,” CAISO CEO Elliot Mainzer said in a statement. “We are honored that both Idaho Power and PGE are taking steps to join the EDAM. Their participation will allow for improved optimization and coordination of critical components of the Western electricity network, helping to bridge the Pacific Northwest with the Rocky Mountain and Desert Southwest regions.” 

The decisions add to a string of good news for EDAM. In February, the Los Angeles Department of Water and Power (LADWP) received board approval to prepare to join the EDAM, while earlier this month, the Western Area Power Administration’s Desert Southwest Region pulled out of the second phase of developing Markets+. 

The commitments by PGE and Idaho Power put five entities in the EDAM camp, including PacifiCorp, the Balancing Authority of Northern California and LADWP. 

‘Rigorous Analysis’

PGE’s decision should come as little surprise to electricity sector stakeholders in the West, with multiple industry sources telling RTO Insider as early as last year that the utility firmly favored joining EDAM. 

The utility has been participating in CAISO’s Western Energy Imbalance Market (WEIM) since 2017 and “worked extensively to help develop [EDAM] to lower power costs, increase resilience and access more clean energy sources across the West,” CEO Maria Pope said in a statement accompanying the utility’s announcement. 

Additionally, Pam Sporborg, the utility’s director of transmission and market services, is co-chair of the Launch Committee for the West-Wide Governance Pathways Initiative, a multistate effort to develop a governance framework for an independent RTO that would expressly include California and build on the WEIM and EDAM. 

“We looked at Markets+ very seriously,” Pope told RTO Insider on March 21 on the sidelines of the CERAWeek by S&P Global conference. “I was in Little Rock [at SPP headquarters] last summer, looking at our analysis and how we were thinking of the product that they were offering. We compared that with CAISO’s opportunities, and we did rigorous analysis and came to [our] conclusion as a result of the analysis.” 

That analysis showed PGE should expect “anticipated gross cost savings between $6 million and $18 million annually, based on current modeling and depending on the final number of EDAM participants,” PGE spokesperson Andrea Platt told RTO Insider in an email. 

Platt also noted that the move “takes advantage of technology and systems PGE has deployed and leverages PGE’s transmission system to connect regional resources across a common market — such as hydropower from the Pacific Northwest, and solar facilities in California and the Desert Southwest.” 

PGE is Oregon’s largest utility by customer base, serving about 900,000 customers in a 4,000-square-mile service territory covering seven counties in the northwestern part of the state, with most concentrated in the Portland metro area. It operates about 1,255 circuit-miles of transmission and is co-owner of the California-Oregon Intertie, a key 500-kV link for transferring energy between the Northwest and CAISO. 

Speaking on a panel at CERAWeek, Pope emphasized a point repeatedly made by advocates of a single electricity market in the West, including the backers of the Pathways Initiative, highlighting the need to “leverage” the full diversity of resources across the West to deliver “the lowest-cost renewable energy to our customers with significant savings, but also significantly enhance reliability.” 

“I think when you see the additional load growth that is coming, you see the continual closure of some of our more carbon-emitting resources across the West, the expense and time it takes to build renewable energy as well as transmission, the work it takes to build out a virtual power plant and really using the distribution system, we need all solutions to be on the table to keep customer prices as low as possible,” Pope told RTO Insider. 

While PGE is not required to obtain approval from the Oregon Public Utility Commission to join EDAM, it has provided regulators with an informational filing that outlines its analysis and decision, Platt said. 

Letter to CAISO

If PGE’s participation in EDAM looks inevitable, Idaho Power’s decision for the CAISO market appears more tentative, if still likely. 

The Boise-based utility conveyed its intentions in a March 21 letter to CAISO COO Mark Rothleder rather than in a formal announcement. 

The letter signed by Kathy Anderson, the utility’s transmission and markets senior manager, explains that market studies it commissioned indicate it will benefit financially from extending its current real-time market participation into the day-ahead time frame and that EDAM “could provide the most value for Idaho Power’s customers.” 

“Based on the study results and additional analysis performed, we are currently leaning towards EDAM as the preferred day-ahead market in our respective balancing authority area, subject to the necessary regulatory approvals and satisfactory resolution of certain outstanding issues,” Anderson wrote. “Before formally committing to join and implement EDAM, it is important to resolve a few issues.” 

The letter cites two of those concerns, including the need for the EDAM to include a “transmission revenue recovery mechanism” that allows participants to be reimbursed for short-term open-access transmission tariff-related revenue losses incurred when transitioning into the market, the only aspect of the market that FERC rejected when approving the EDAM tariff in December. (See CAISO Wins (Nearly) Sweeping FERC Approval for EDAM.) 

The other concern relates to ensuring that the EDAM’s default energy bids for gas-fired generators represents the “actual fuel risk and costs of each unit, addressing both the fuel zone and purchase cycle relative to the awards,” a concern for generators that don’t benefit from the same storage ability as that within CAISO’s BAA, the letter says. 

The letter also encourages CAISO and stakeholders to address the ISO’s lack of independent governance but says Idaho Power will not require that issue to be resolved before committing to EDAM. 

“We are encouraged by the results of the benefits studies and view EDAM as an important option to increase market benefits that our customers are already experiencing in WEIM,” Anderson wrote. 

Idaho Power serves 630,000 customers across 24,000 square miles in southern Idaho. The utility operates about 1,988 MW of hydroelectric generation and 4,800 miles of high-voltage transmission, some of which interconnects with the BPA system.  

In December, CAISO’s Board of Governors approved a plan for the ISO and Idaho Power to jointly fund the $1 billion Southwest Intertie Project-North (SWIP-N) project, a 285-mile, 500-kV line in Nevada designed to tap energy from Idaho’s wind resources for delivery to markets to the south. The project is now included in the ISO’s 2022/23 transmission portfolio. (See CAISO Board Approves Nevada Transmission Line to Access Idaho Wind.) 

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FERC Proposes Restricting Reactive Power Compensation

FERC on March 21 proposed preventing transmission providers from including charges associated with supplying reactive power in their transmission rates in the hopes of preventing unjust and unreasonable rates for end-use customers (RM22-2). 

At its monthly open meeting, the commission issued a Notice of Proposed Rulemaking seeking comments from “all interested persons” on its proposal to revise Schedule 2 of its pro forma open-access transmission tariff to prohibit the inclusion within transmission rates of charges associated with the supply of reactive power within the standard power factor range of a generating facility. Generators set the standard power factor range in their interconnection agreements. 

In addition, the NOPR would revise section 9.6.3 of FERC’s pro forma large generator interconnection agreement and section 1.8.2 of its pro forma small generator interconnection agreement to remove the requirement that transmission providers “pay an interconnection customer for reactive power within the standard power factor range if the transmission provider pays its own or affiliated generators for the same service.” This change would make the LGIA and SGIA consistent with OATT revisions. 

Reactive power is “a critical component of” an electrical grid, FERC said in its NOPR, because it keeps system voltage within appropriate ranges, allowing the transmission system to reliably supply “real power,” which provides energy to end users. Generating facilities, transmission lines and equipment, power electronic equipment and load can either produce or absorb reactive power. 

FERC ruled in Order 888 that transmission providers must incorporate six ancillary services into their OATTs, including the reactive supply and voltage control supplied by generators. However, the commission indicated in 2021 that it was considering updating its approach to compensating reactive power capability, seeking industry input in a Notice of Inquiry. (See FERC Seeks Comments on Reactive Power Compensation.) 

Order 888 assumed a resource mix that overwhelmingly comprised synchronous generators, but as FERC pointed out in its NOI, much of the new generation coming onto the grid consists of nonsynchronous inverter-based resources such as wind and solar facilities. The commission said it was “facing challenges in evaluating proposed reactive power rate schedules” because most of the filings for such schedules were made by owners of nonsynchronous resources. 

The NOPR also mentioned Order 2003, which said generators are not owed compensation for providing a standard range of reactive power as that is a condition of interconnection (ER23-523). FERC cited Order 2003 last year in approving a request from MISO transmission owners to eliminate it and voltage control charges from their own and unaffiliated generation resources. (See FERC Ends MISO Compensation for Reactive Power Supply.) 

Responding to comments that argued “that separate reactive power compensation is necessary to maintain reliability,” FERC observed that providing reactive power is “already required by a generating facility’s interconnection agreement” and suggested that requiring additional payment would not affect this. 

The commission also noted that some commenters said the payments they received for reactive power helped them obtain financing to make needed improvements to generating facilities. In response, FERC argued that “resource developers continue to develop new generating facilities in regions without such payments.” Rather than recovering reactive power costs through transmission rates, the commission suggested that entities use “energy and capacity sales, since competition between generating facilities may incentivize efficiency.” 

Comments on the NOPR are due 60 days after its publication in the Federal Register, with replies due 90 days after publication.