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November 7, 2024

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Phillips, Christie Debate Loper Bright’s Impact on FERC Order 1920

The Supreme Court’s decision in Loper Bright Enterprises v. Raimondo is already making waves in the rehearing process on FERC Order 1920, with commissioners releasing dueling statements about what the end of Chevron deference will mean for the transmission rule. (See related story, Supreme Court Ends Chevron Deference to Administrative Agencies.) 

Commissioner Mark Christie released a statement after the court’s ruling June 28 arguing that the commission should reform the order on rehearing given the lack of Chevron deference, while Chair Willie Phillips released a statement July 1 arguing that 1920 is on firm legal footing even with the doctrine’s end. Ultimately, the issue will come down to a different commission than the one that approved the order, as three new members will have joined. 

Phillips argued that FERC’s authority to regulate regional transmission planning and cost allocation has long been recognized by bipartisan majorities of the commission and the D.C. Circuit Court of Appeals. 

“It could hardly be otherwise,” Phillips said. “Both regional transmission planning and cost allocation are practices that have exactly the type of ‘direct effect’ on commission-jurisdictional rates that the U.S. Supreme Court has held brings a matter within this commission’s jurisdiction. Indeed, our authority to regulate regional transmission planning and cost allocation is essential to the commission’s ability to ensure that customers have access to reliable, affordable supplies of electricity — our most fundamental statutory responsibility.” 

Order 1920 builds on Order 1000, which was upheld by the D.C. Circuit in South Carolina Public Service Authority v. FERC using Chevron deference. The Supreme Court held in Loper Bright that settled precedents would not be disturbed by its decision, so Order 1000 is safe. 

“Order 1000 is the sort of the foundation for this Order 1920,” Christie told RTO Insider on July 1. “But the Chevron deference is not available, and so my point is that lifeline is now not available on court challenges to Order 1920. So … we’re going to have the opportunity to do substantial amendments to 1920 when we get to the rehearing stage, and I hope that we’ll be able to do that.” 

Phillips argued that Order 1920 fits easily into the South Carolina precedent in that it does not promote particular public policies, dictate specific outcomes or include any selection mandate, and its cost allocation proposals rest on well-established principles. 

“As such, Commissioner Christie’s assertions about Loper Bright’s implications for Order No. 1920 cannot be squared with the court’s actual holding in that case,” Phillips said. “As always, I respect Commissioner Christie’s regulatory perspective on how we should exercise the regulatory ‘discretion’ that Congress vested in this commission. But his disagreement with how the commission exercised that discretion in Order No. 1920 does not provide a logical or reasonable basis for calling into question whether we have that authority in the first place.” 

Christie argued that it was clear when Order 1920 was issued that it would not work, and that was made more clear by the many petitions to strike it down, many of which came from states and their organizations, such as the National Association of Regulatory Utility Commissioners.  

But they were also joined by PJM, the National Rural Electric Cooperative Association and more. Given Loper Bright, FERC should fix its issues before it winds up before the courts, Christie said. 

“The commission still has an opportunity to amend Order No. 1920 into a true compromise that will promote sensible long-term transmission planning while protecting consumers and respecting and elevating the important role of states throughout the process,” Christie said. 

Two major issues Christie would like to see changed are the requirement that regional plans take into account the supply preferences of large customers, which he argued would spread the costs of their choices to every customer impacted by the cost allocation, and Order 1920’s language around state input in cost allocation. 

While the order requires developers to give states six months to hash out an agreement on cost allocation, FERC did not require the relevant transmission providers to file it. That was based on yet another court case, Atlantic City v. FERC, which said transmission owners have the right to file their own rates. In their requests for rehearing, parties argued FERC could get around that. 

Christie also noted that the order stops short of requiring transmission providers, which include the ISO/RTOs, from even reporting on their efforts to get states to agree to a cost allocation method. 

“It says that even if the states in a region agree, the transmission provider does not even have to file it,” Christie said. “I absolutely object to that, because that totally goes against what was promised in the [proposed rule]: that state agreements would be recognized.” 

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NERC Promises 1st ITCS Results by August

NERC last week published an overview of its work on the Interregional Transfer Capability Study (ITCS), laying out the overall strategy and technical approach for the project and outlining the documents to be released beginning this August.

The Overview of Study Need and Approach reviews the work done on the ITCS since Congress ordered the study in last year’s Fiscal Responsibility Act. The law requires NERC to deliver to FERC by December a study on the total transfer capability between neighboring regions, additions to transfer capability that could strengthen grid reliability, and recommendations to meet and maintain total transfer capability.

Work on the ITCS began after FERC approved the ERO’s plan for funding the study last August. (See FERC Approves NERC Transfer Study Funding Request.) NERC is in overall control of the study through the ERO Executive Leadership Group, which is led by NERC Chief Engineer Mark Lauby, with participation from leadership of the regional entities. The ERO also formed the ITCS Advisory Group in the early days of the project to give industry stakeholders input into the project’s direction. (See SERC to be ‘Well Represented’ in ITCS Group.)

In the overview document, the ERO emphasized the “unprecedented” nature of the task assigned by Congress, calling the ITCS “the first comprehensive study of transfer capabilities between adjacent transmission planning regions [that] will use 12 years of data, capturing a wide variety of operating conditions and historical weather events … to determine potentially deficient areas.”

Congress required that NERC base the ITCS on transmission planning regions identified in FERC Order 1000. The project team has further subdivided these regions in some cases “to provide more granular analysis of transfer capability limitations, especially under specific weather scenarios.” NERC said this approach was necessary because some of the planning regions, particularly in SPP, covered large geographic areas with significant internal transfer constraints.

According to the overview document, the ITCS report will consist of three documents. Part 1, to be issued in August, will present a transfer capability analysis for 2024 and 2033, covering both summer and winter for each year. Total transfer capability will be calculated “by determining the amount of additional transfers that can be added to base transfers already modeled while respecting contingency limits,” and will comprise two parts:

    • Base transfer level, indicating “scheduled power flows between areas in the starting case.”
    • First contingency incremental transfer capability, which simulates the amount of extra power that can be transferred during an unexpected event.

NERC will use the transfer capability limits between each neighboring region as a “critical input into Part 2,” which will be published in November. The goal for Part 2 is to identify conditions in areas that might experience energy deficiencies, such as extreme weather scenarios; determining areas where deficiencies are severe enough to justify additions to interregional transfer capability; and “prioritizing interfaces for transfer capability increases.”

The ERO will limit its recommendations to target megawatt ranges of transfer capability and will not recommend any actual transmission projects to meet its targets.

Under Part 3, which will be published in the same document as Part 2, NERC will provide recommendations to meet and maintain transfer capability based on the results of the transfer capability and energy deficiency analyses in parts 1 and 2 respectively. These may include further studies to measure progress addressing risks and ensure that recommended additions can be maintained reliably, technology that may address transfer capability limitations, and enhancements to regulatory mechanisms, policies or standards.

Congress mandated that the ERO study transfer capabilities only within the U.S.; the documents submitted to FERC this year will focus on the U.S. However, NERC said in the overview that it already concluded the study “would be incomplete without a thorough understanding of the Canadian limits and available resources.” Transfer capabilities between Canadian provinces and from the U.S. to Canada therefore will be the subject of a fourth report, to be released in the first quarter of 2025.

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PJM Consumer Advocates File Complaint on EE Market Design

Three state consumer advocates filed a complaint against PJM with FERC last month, alleging the RTO’s treatment of energy efficiency resources is unduly discriminatory and is not properly documented in its governing documents (EL24-118).

The complaint contends PJM treats EE resources differently from any other class by removing EE that clears in the Base Residual Auction (BRA) from the supply stack and adding those megawatts on top of the load forecast, a process known as the “addback.” By not counting cleared EE toward meeting the reliability requirement and instead increasing the amount of overall capacity procured by the amount of EE, the advocates argued the RTO is robbing consumers of the ability to lower their capacity costs through EE programs. 

“This places unjustified upward pressure on prices, deprives the marketplace of the benefits of energy efficiency and foists unreasonable costs onto PJM consumers to pay for that energy efficiency out of the market,” the complaint said. It was jointly filed by the New Jersey Division of Rate Counsel, Maryland Office of People’s Counsel and Illinois Citizens Utility Board. 

The advocates requested that FERC hold a technical conference with PJM, stakeholders and member states to reconsider how EE participates in the market. 

The complaint also argued that a change as significant as the addback is not appropriate for PJM to make through its manuals and should have been filed as a tariff revision. Without FERC oversight of the change, the advocates argued there has been no ruling on whether it comports with past orders requiring EE participation in capacity markets. 

“The addback should have been filed with the commission for review because it profoundly alters how an entire class of resources participates in the Reliability Pricing Model and affects capacity clearing prices,” the advocates wrote. 

The advocates’ filing joins a complaint the Independent Market Monitor filed May 31 arguing that 10 EE providers had not demonstrated their resources met the BRA participation requirements and asked the commission to either bar those market participants from receiving BRA revenues for the 2024/25 delivery year or order PJM and the Monitor to open investigations to determine their eligibility (EL24-113). (See Monitor Alleges EE Resources Ineligible to Participate in PJM Capacity Market.)

The same day, PJM sent an email to EE market participants stating that it planned to delay approval of post-installation measurement and verification (PIMV) reports and defer capacity payments until the Monitor’s complaint is resolved. A second email said the PIMV reports continue to be under review, but the RTO did not plan to subject affected entities to capacity market deficiency charges and will continue payments to those companies, subject to refund depending on the outcome of the complaint. Replacement transactions will also be allowed for EE providers. 

“Any capacity payment associated with [EE] resources for the 2024/2025 delivery year is not evidence of the validity of the PIMV report or represent evidence that PJM has or will approve the provider’s PIMV report,” the email states. “Additionally, PJM is continuing to review the sufficiency of the PIMV report during the pendency of the Market Monitor’s complaint, and any rejection of the PIMV report will result in capacity resource deficiency charges for any shortfall determined. Finally, PJM may further initiate audits of M&V plans and PIMV reports submitted by energy efficiency providers for the 2024/2025 delivery year, which could result in billing adjustments based on the outcome of such additional review.” 

Four U.S. senators sent a letter to the commission in response to the Monitor’s complaint recommending a technical conference to consider the “proper role for energy efficiency in FERC-jurisdictional wholesale electric markets.” 

The letter, signed by Sens. Angus King (I-Maine), Martin Heinrich (D-N.M.), Sheldon Whitehouse (D-R.I.) and Chris Van Hollen (D-Md.), said EE has the potential to shrink capacity procurements, delay or avoid transmission upgrades, and reduce consumer bills. 

“FERC has, on several occasions, expressed support for energy efficiency participating in the wholesale markets. We are concerned, however, that in some regions, energy efficiency is not fully participating in wholesale markets, and other regions are considering rule changes that may negatively impact energy efficiency’s role in the future,” the senators wrote. “For instance, PJM recently announced that it was intending to suspend payments to energy efficiency providers until a complaint recently filed by the PJM Independent Market Monitor concerning energy efficiency is resolved. The status quo is becoming untenable.” 

While many EE providers have spoken out against the Monitor’s complaint and PJM’s actions on PIMV reports throughout the stakeholder process, some expressed support to RTO Insider for the consumer advocates’ complaint on the grounds that removing the addback could allow EE to demonstrate its potential as a competitive resource. Those individuals requested anonymity to discuss the pending complaints the Monitor has filed against their companies. 

In a protest to the Monitor’s complaint, attorneys representing Affirmed Energy said FERC’s Office of Enforcement has opened an investigation into the company based on a referral by the Monitor and makes identical claims to the Monitor’s complaint. It asked the commission to consider the overlap between the two in how it proceeds. 

“The reality here is that both the IMM and the Office of Enforcement are seeking now to enforce their own policy preferences for rules that do not exist. Our position, in both the complaint case and the investigation, is that Affirmed Energy fully followed the market rules,” the company argued. “The IMM claims the conduct of Affirmed Energy and other sellers violates the tariff; the Office of Enforcement makes the same claim about Affirmed Energy. They are both wrong.”  

The company said PJM has approved EE programs offered by Affirmed for the past 10 years, and the complaint follows stakeholders rejecting proposed changes to the EE market participation rules. (See “Stakeholders Reject Changes to EE Measurement, Verification,” PJM MRC/MC Briefs: March 20, 2024.) 

It argued that the complaint and investigation both delve into “fundamental policy questions” that should instead be considered through a public proceeding such as a technical conference. 

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MISO Warns Members of Rising Budgets

EAGAN, Minn. — MISO said its cost of doing business is set to escalate within the next four years, spawning bigger operating budgets and heftier member dues.

According to its own estimates, MISO said its base operating expenses could range from $412 million to $447 million by 2028, reflecting a 5.4 to 7.2% compound annual growth.

By 2028, the tariff rate MISO charges to its members could be 56 cents to 68 cents/MWh. Currently, MISO’s tariff rate is 47 cents/MWh. The RTO assumed a flat load profile of 717 TWh to make its estimate.

MISO also said project investments and other operating expenses combined could add more than $100 million to its annual budgets over four years. CFO Melissa Brown said salaries, benefits and computer maintenance comprise nearly 80% of MISO’s cost structure today and are expected to rise. She said the RTO going forward will have little opportunity to reduce costs to make up for heightened expenses.

“The labor market for MISO remains tight. A lot of our staff is getting poached, especially our experienced staff,” Brown said during the Advisory Committee’s meeting June 26. “It’s a challenge.”

The RTO’s 2024 base operating budget stands at $357 million, though it estimates it likely will end the year $5 million underbudget because of a higher-than-expected employee vacancy rate and stiff competition for staff.

Brown said MISO is recruiting new college graduates, even with the understanding those employees may leave within three to five years.

Members asked whether the RTO is using longevity bonuses for its employees.

“Right now, on the benefits side, there is nothing we’re not considering,” Brown said with a laugh. She confirmed MISO offers retention bonuses.

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MISO Leadership Issues Urgent Call for In-Service Dates

EAGAN, Minn. — MISO’s system is at the mercy of faster interconnections of new resources and retirement delays, executives said in a quarterly address to the board and stakeholders.  

MISO CEO John Bear said he wants to get to the bottom of why resources can’t be built sooner. MISO is sitting on a stockpile of about 50 GW across 316 projects that have been approved to connect to the system but are experiencing holdups in construction. According to MISO, the projects experience an average of 650 days to commercial operation.  

Bear said the mostly intermittent generation in the queue isn’t a full substitute for the baseload generation that continues to fall off its system. 

“You’ve got a mismatch of reliability attributes coming on the system,” Bear said during a June 27 board meeting. “We’ve got a lot of work to do to slow down the retirements and speed up the additions coming onto the system.”  

Senior Vice President and Chief Customer Officer Todd Hillman likened the “enormity” of MISO’s transition to a Rubik’s cube where members twist cubes to get one side monochromatic and then realize other sides remain multicolored. He said he expects hitches as utilities work out how to solve the puzzle.  

Hillman said members want to achieve decarbonization while paying attention to reliability and affordability. But he also said MISO expects anywhere from 12 GW to 14 GW of load growth in coming years from data centers alone.  

“That would be like adding 11 million homes. And these have much higher capacity factors than homes. That’s just a gigantic addition to a grid that’s already stressed,” Hillman said. He added that “poor visibility into the magnitude and timing of large load additions is putting at risk our ability to reliably accommodate them.” 

MISO said announced load additions in the footprint from manufacturing projects and data centers total more than 8 GW. Broken down, the projects account for 3 GW apiece in MISO’s South and Central regions and 2.4 GW in the North region. All projects aim to be online by 2030.  

Stakeholder Services Executive Director Suzie Jaworowski said MISO maintains and updates a list of announced load additions so members can decide how to prepare.  

Last month, MISO and the Organization of MISO States said if members don’t delay retirements or bring more resources online than typically occur historically, a potential 2.7-GW deficit next year could balloon to 14 GW in 2029. (See OMS-MISO RA Survey: Potential 14-GW Capacity Deficit by Summer 2029.)  

Bear said MISO should delve into probabilistic load forecasting. He said it’s clear its deterministic load forecasting based on historical experiences won’t keep MISO best prepared.  

Despite striking more than 20 GW in generator interconnection agreements last year, MISO experiences an average of just 5 GW per year of nameplate capacity coming online. In a separate meeting, Vice President of System Planning Aubrey Johnson also said longstanding construction lags persist and MISO and developers need to find ways to accelerate in-service dates.  

“The number of gigawatts coming online is insufficient for what we’re seeing coming,” he said during a June 25 meeting of System Planning Committee of the MISO Board of Directors. 

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Extensions Likely for MISO’s Term-limited Board Members

EAGAN, Minn. — MISO and its board are scrutinizing the steps they can take to preserve institutional knowledge on the board of directors as they confront half of the board members reaching term limits this year or next.  

Three MISO board members’ terms are ending at the end of this year; two of them are restricted by MISO’s three-term limit. Board members Phyllis Currie and Mark Johnson have been fixtures on the board since 2016 and are prevented from seeking additional terms. MISO Director Nancy Lange is up for re-election for her third and final three-year term.  

Beyond that, directors Todd Raba, H.B. “Trip” Doggett and Barbara Krumsiek will conclude their third and final terms at the end of 2025. 

However, MISO has said it’s open to retaining board members using waivers, which allow a director to stand for election to one more three-year term beyond the three-term limit. (See “Waivers May be Necessary to Retain Directors Past Term Limits,” MISO Board of Directors Briefs: March 23, 2023.) 

MISO last used a waiver for board members in 2017, when members retained Baljit “Bal” Dail for an additional three-year term to keep his IT expertise on the board. Dail served 12 years on the board. (See MISO Board of Director Briefs: Dec. 10, 2020.) 

At a June 26 Advisory Committee meeting, Alliant Energy’s Mitch Myhre, who sits on MISO’s Nominating Committee, said MISO is evaluating how it can be “proactive” about maintaining experience on the board by securing seasoned candidates and making sure terms overlap.  

Myhre said the Nominating Committee’s work to search for suitable replacements and to pursue waivers will begin in earnest this month.  

Wisconsin Public Service Commissioner Marcus Hawkins said he was worried about the potential for the board to experience a “knowledge cliff” anyway if MISO chooses to exhaust all possible term-limit extensions for term-limited members. He joked that he saw something similar occur within his homeowners’ association.  

MISO’s Nominating Committee is charged with vetting and selecting MISO Board of Director candidates, who are put to a vote of membership. The committee’s members change yearly, and the committee is composed of three board members and two stakeholders, one of whom typically is from a state public service commission. This year, directors Bob Lurie, Jeff Lemmer and Theresa Wise sit on the Nominating Committee. All three were elected at the end of 2023.  

Lurie said the committee this year is taking a “multiyear view of the search,” with MISO having so many important reliability initiatives ongoing simultaneously and the impending exodus of board members.   

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Galt Power Fined $1.5M Following Anti-Manipulation Investigation

FERC has approved a $1.5 million civil penalty on Galt Power following an investigation finding manipulation violations in the creation of renewable energy credits (RECs) (IN20-5). 

The commission’s Office of Enforcement determined that Galt, a wholesale power marketing company, conducted prohibited “wash” trades — transactions designed to cancel each other out, carrying no financial risk — to generate RECs in Massachusetts.  

“Galt repeatedly prearranged its two schedules between ISO-NE and NYISO for the same volumes during the same time intervals, a hallmark of wash trades,” the Office of Enforcement found.  

The office determined that Galt generated RECs by sending power from two New York wind farms from NYISO to ISO-NE, while scheduling imports to NYISO from ISO-NE that would kick in when the prior transactions were projected to lose money.  

“Galt willingly lost money on the NYISO-to-ISO-NE transactions to obtain Class I RECs but did not absorb those losses or flow the power on net. Instead, it scheduled the ISO-NE-to-NYISO transaction to mitigate or eliminate any losses,” the office found.  

The office also found that Galt made false statements concealing the wash trades to APX, the operator of the NEPOOL Generation Information System.  

“We do not want to let them know about hedge transactions,” read one internal email from an APX employee. 

Following the office’s findings, Galt has agreed to pay a $1.5 million fine to the U.S. Treasury, along with about $372,000 to the state of Massachusetts for disgorgement and interest. The company also will be required to submit two annual compliance reports.  

According to the agreement, Galt “neither admits nor denies the alleged violations.” 

FERC accepted the agreement June 28, finding it “is a fair and equitable resolution of the matters concerned and is in the public interest.” 

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ERCOT, IMM Share Details on Ancillary Services Study

ERCOT staff have made a pair of preliminary recommendations as part of their collaboration on an ancillary services study that is due to Texas regulators before the end of the year. 

Jeff Billo, ERCOT director of operations planning, told the Stakeholder Advisory Council on June 24 that staff have been “thinking through this stuff” and running the analyses. ERCOT is working with the Independent Market Monitor and Public Utility Commission staff on the study. 

Jeff Billo, ERCOT | © RTO Insider LLC 

“We really think that we have the right services and the right methodology for quantifying those services today,” Billo said. Unsurprisingly, he said ERCOT plans to use the current mechanisms and is not proposing any changes to those products. 

Billo said the first preliminary recommendation covers the frequency control portion of ancillary services: regulation, responsive reserve service and the frequency-response portion of ERCOT Contingency Reserve Service (ECRS). Staff’s other recommendation is to examine the benefits of determining some portion of AS quantities closer to the operating day based on daysahead forecast conditions rather than an annual calculation. 

Some ERCOT stakeholders and the IMM have objected to the heavy use of ECRS since its first use last year, saying it has added billions of dollars in costs to the energy-only market. The grid operator procures capacity resources that can be brought online within 10 minutes and sustained at a specified level for two consecutive hours. (See “Contentious NPRR Revising ECRS Passes over Monitor’s Objections,” ERCOT Board of Directors Briefs: June 17-18, 2024.) 

Billo reminded TAC of where ERCOT was in 2021, when he told the committee that staff were going to a conservative operations approach, setting aside larger amounts of operating reserves than before.

“[I said we] were going to not walk up right to the edge of the cliff, but we were going to take a few steps back, and we were going to operate with higher reserve margins in real time,” he said. “The idea there is that we’re operating with a lower risk compared to how we historically operated, and that has also driven a change in the amount of ancillary services that we’re getting.” 

ECRS and other products have become necessary with the increased addition of renewable resources and the resulting growth in load variability, Billo said. He said ECRS was needed to address increasing net load ramps causing greater intra-hour risk and fewer online reserves available to recover frequency after a large unit trips. 

“We see the greater exposure when we have forecast misses and so that’s why you’ll see, during especially those ramp times, that we’re getting higher amounts of ECRs to cover that kind of higher exposure,” Billo said. 

Also playing a role in the increased use of AS was the public’s anxiety over ERCOT’s ability to meet demand following the disastrous and deadly 2021 winter storm that nearly brought down the Texas grid. 

“I think that prior to Winter Storm Uri, there were lots of times where we had watches or we went into [energy emergency alerts] and the public didn’t really notice and didn’t really care,” Billo theorized. “Post-Uri, I think as we saw in 2021, there were times where we would go into a watch and that there’d be a lot of attention on that from the public, but also from state leadership. I think the message that we got … was, ‘ERCOT, we don’t want you to go into a watch and an EEA as much as you have in the past.’ 

“In my mind, that is a criteria change for how we operate the system and the amount of reserves we’re procuring,” he added. 

The IMM’s deputy director, Andrew Reimers, told TAC the IMM’s study is intended to estimate the reliability value of different levels of reserves to inform AS procurement targets. He said the Monitor is focusing on reserves that are responsive within minutes to hours.  

The IMM is using 10,000 random draws of a Monte Carlo simulation for each hour in the study period to determine how reserve levels influence loss-of-load projections, given probabilistic distributions of unplanned outages and net load forecast errors. Its staff are using historic hours from June 2023 to June 2024 to compare the capacity at risk to different reserve levels. 

“The timeline is definitely a challenge,” Reimers said. “We’re trying to triage this to do the best study that we can given the relatively limited amount of time we have to go on. Ultimately, that means prioritizing what we can getting the results that we can and then figuring out what things have to be left for future work.” 

“We’ve had a lot of really good conversations with the IMM. I don’t know if by this September that we’ll agree on all of the details, but conceptually, I think we agree on the framework,” Billo said. “Some of the things we still need to think through are around data. It’d be great if we used 10 years of data, but the forecasts have improved. I’m trying to quantify what my risk is of a forecast error; I really don’t want to use forecast data from 10 years ago.” 

Billo asked for stakeholder input before he presents a study update to the Board of Directors during its Aug. 19-20 meetings. An AS workshop will be held after the Aug. 28 TAC meeting and a final report posted to the commission before October. 

The PUC also plans an AS workshop in the latter half of October. It’s asking for TAC feedback on which ERCOT and IMM information presented Aug. 28 would be most helpful in filing comments at the commission (55845).  

The study is a requirement of legislation passed last year by Texas lawmakers. It directs the PUC to review the type, volume and cost of AS and determine whether those services are necessary in the ERCOT market. The law also requires the commission to evaluate whether additional services are needed for reliability. 

Separately, ERCOT staff will begin discussions with stakeholders in July on the grid operator’s 2025 AS methodology. (Billo said ERCOT won’t have time to incorporate learning from the PUC study’s results.) 

Staff plan to present its proposal during the October board meeting, allowing for PUC review before next year. ERCOT’s annual requirement to update its AS methodology now includes commission approval. 

Members Endorse 7 Changes

TAC approved a protocol change (NPRR1190) that would recover demonstrable financial loss arising from a manual high dispatch limit (HDL) override to reduce real power output, should the output be used to meet qualified scheduling entity load obligations. 

The change’s approval came after an attempt to table NPRR1190 until further IMM review came up short. The measure passed 22-6 with an abstention. 

The consumer segment provided all six opposing votes over concerns that the change incorrectly expands the opportunity for entities to receive compensation for scheduled-but-not-provided energy under out-of-market ERCOT actions. Supporters noted the infrequent occurrence of the conditions covered by the NPRR and the language that prevents recovery of lost opportunity costs stemming from an HDL override, according to the committee’s report. 

The motion to table failed 8-19 with a pair of abstentions. The consumer segment favored tabling. 

Members also endorsed three other NPRRs, an Other Binding Document revision (OBDRR) and single changes to the Planning Guide (PGRR106) and the Verifiable Cost Manual (VCMRR) that, if approved by the Board of Directors, would: 

    • NPRR1215: clarify that the day-ahead market’s energy-only offer credit exposure calculation zeros out negative values, with any zeroed-out values being included in the calculation of the percentile difference. 
    • NPRR1216, OBDR051 and VCMRR039: align the protocols with the PUC’s order establishing an emergency pricing program for the wholesale market. During an emergency offer cap (ECAP) effective period, the systemwide offer cap is set to the ECAP, with a value equal to the low systemwide offer cap. 
    • NPRR1225: update the protocols to align with the PUC’s declaratory order on ERCOT’s settlement systems. The grid operator added revisions to meet the commission’s order that exclusions be effective March 4, 2024, when the transfer of Lubbock Power and Light retail customers to retail electric providers began. 
    • PGRR106: clarify which transmission projects are included in the Transmission Project Information and Tracking report. 
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BNEF: ICE Phaseout by 2035 Critical to Reach Net Zero by 2050

Electric vehicle sales may have slowed in the U.S., but elsewhere, EV markets are robust and growing, according to BloombergNEF’s new Electric Vehicle Outlook 2024 report. 

About 20% of all vehicles sold worldwide this year will have a plug ― either battery electric or plug-in hybrid ― with sales predicted to rise to one-third by 2027, said Colin McKerracher, head of clean transportation at BNEF, speaking during a June 26 launch webinar for the report. But even more growth, government support and private investment will be needed to hit national and global targets for EV adoption and critical reductions in transportation emissions.  

“Internal combustion engine vehicle sales peaked in 2017 ― that’s seven years ago ― and they are now down 30% from their 2017 peak,” McKerracher said. BNEF does not expect sales of ICE vehicles to regain their 2017 peak, but also doesn’t see them disappearing. 

The report looks at two scenarios. In the “economic transition” scenario, EV adoption is driven by technological, economic and market forces, with no new polices or additional government support, and “most countries do not achieve a full phaseout of combustion engine sales,” he said. 

BNEF’s second, net-zero scenario looks at what will be needed to get to a “net zero-capable fleet” by 2050 and keep global climate change under 2 degrees Celsius. A phaseout of ICE sales by 2035 would be required, and in some markets even sooner, McKerracher said.  

The emission reductions needed for a global net-zero target would “rely on hundreds of millions of electric vehicles on the road by 2050, even approaching 1 billion,” he said. “If that market doesn’t deliver that, then most of those climate targets will be unreachable.” 

President Joe Biden wants 50% of all U.S. auto sales to be electric by 2030 and has pledged to cut the nation’s GHG emissions 50 to 52%, also by 2030. EVs made up about 7% and PHEVs 2% of U.S. auto sales in 2023, according to the U.S. Energy Information Administration.  

By comparison, BNEF’s figures show global EV markets moving in the right direction but still falling short of the growth needed for net zero, McKerracher said. By the end of 2023, light-duty passenger EVs made up about 18% of all vehicles in the fleet, while electric vans and trucks accounted for only 4%. Buses are a major wedge for transportation electrification, coming in at 26% of the existing fleet. 

China’s ongoing dominance and the lackluster status of the U.S. in both BNEF scenarios expose some of the challenges facing wider EV adoption in the U.S. ― including the increased power demand from EVs ― and potential blind spots for domestic automakers. 

For example, while Chinese automakers are racking up sales from a range of lower-priced EVs aimed at middle- and lower-middle-income customers ― and making inroads in emerging markets ― the U.S. market is saturated with higher-priced electric SUVs.  

Chinese automakers also are ahead in sales of plug-in electric vehicles (PHEVs), which have become one of the fastest-growing segments in global markets, due in part to newer models with longer electric battery ranges. The average electric range for Chinese PHEVs is 55 miles, BNEF says, while in the U.S., most PHEVs now available have electric ranges well under 40 miles, according to a recent analysis by J.D. Power. 

The difference, McKerracher said, is that U.S. and European PHEVs are designed to meet government-mandated standards for cutting vehicle emissions. Newer PHEVs, with longer electric ranges and larger batteries, “are also aimed at actually satisfying a customer’s needs,” he said.  

The Miles Matter

Another significant insight from the study is that worldwide EVs and PHEVs are driven more miles than ICE vehicles. 

“When you talk about energy impacts and emission impacts, what matters is the total kilometers, not the total number of cars on the road,” McKerracher said.  

One factor here is that taxi and ride-share drivers around the world are buying EVs and putting tens of thousands of miles on them per year, he said. Looking again at China, McKerracher said, “The vast majority of professional drivers in taxi and ride-hailing applications are driving EVs now. The working drivers who really care about total cost of ownership are switching to electric way, way faster than the private owners.”  

The U.S. is the exception to the global trend: EVs and PHEVs here are driven fewer miles than ICE vehicles, except in California. McKerracher speculated that EV drivers there may have better access to charging infrastructure and be past the early adopter stage in which households may have more than one car and drive a new EV less than their ICE. 

More miles driven also means more electricity used. Ryan Fisher, BNEF’s lead for charging infrastructure, said that by 2050, the additional electricity needed to power EVs worldwide could equal twice the total annual electricity demand of the U.S. ― or about 11 to 12% of global power demand. 

The exact cost of building out the grid to meet that demand will vary and may be hard to split out from grid capital expenses in general, Fisher said. In its economic transition scenario, BNEF sees global grid spending for EV charging rising from 5% in 2025 to a high of over 15% in 2040 and then falling back to 5% by 2050. Costs are less in the net-zero transition, staying between about 4 to 11%. 

In either case, making those investments may require “special finances to come in loans, for example, from different government bodies to support this big infrastructure growth, to basically give us those incentives and upgrades we need in those later years,” he said. 

He also pointed to EV chargers as potential grid assets, with the global fleet of chargers eventually providing as much as 10 TWh of storage. 

Battery Oversupply

The big story in the EV supply chain is the rapid drop in battery prices in China and a resulting oversupply, which is driving increased competition in the market, both in China and worldwide, said Yayoi Sekine, who leads BNEF’s energy storage team.  

A key driver is the move away from lithium batteries with its more expensive nickel and cobalt chemistry toward lithium, iron and phosphate (LFP) batteries. Sekine sees LFP “taking over the battery market” between now and 2030, with the technology gaining ground based not only on cost, but on “improvements in performance in low-temperature environments, as well as things like improvements in fast-charging capabilities.” 

China continues to dominate in the battery market, controlling “upwards of 85%” of all parts of the supply chain, Sekine said. The average price for LFP batteries in China is $53 per kWh, versus $95 per kWh worldwide. 

“There’s a lot of competition in [the Chinese] market, and a lot of battery cell manufacturers are willing to squeeze their margins to sell into this market at higher volumes,” she said.  

Worldwide, BNEF projects that by 2025, global battery production will reach 7.9 TWh of capacity, which could be four times more than demand. Sekine said lower prices and oversupply could stoke some additional EV demand, but not enough “to absorb all the overcapacity we see in the market.” 

Similarly, Sekine noted the EV battery supply chain is being overbuilt, with billions going into battery cell manufacturing but much less toward mining and refining of the critical minerals needed for batteries. At present, the investments for battery factories announced worldwide average $155 billion per year between now and 2030, which is about 2.4 times what would be needed for BNEF’s net-zero scenario, she said. 

Investments in mining and refining totaled about $7.2 billion in 2023, about half of the $15 billion per year that will be needed by 2025, she said. 

Tariffs and Trump

The webinar closed with a few minutes for audience questions, with the impact of EV tariffs in the U.S. and Europe and the potential impact of Donald Trump returning to the White House in 2025 being hot topics. 

Biden announced a 100% tariff rate on Chinese EVs in May and raised tariffs on Chinese EV battery cells from 7.5 to 25%. The European Commission has set tariffs ranging from 17 to 38% on imported EVs, on top of its existing 10% tariff on cars, according to Reuters. The European tariffs are scheduled to go into effect in July.  

With the steep drop in battery prices in China ― allowing for lower-priced EVs ― some Chinese automakers could absorb the lower European tariffs without raising their prices, McKerracher said. Higher tariffs will be more difficult to absorb and could have a “negative near-term impact for EV adoption,” he said. 

“I think the big picture is that this does push more localization,” McKerracher said. “The fragmentation of the global auto market means more automakers will have to localize production, and you’re already starting to see that effect.” 

The impact of the tariffs could also dissipate as Chinese automakers move manufacturing hubs to other countries, he said, as has occurred with solar cells and panels. Leading Chinese automaker BYD plans to build a factory in Mexico and began building a plant in Brazil this year, according to a June 21 report in Electrek.  

On the election, McKerracher said a Trump administration likely would be “significantly less favorable” to EVs. “They will probably go after some of the things that are helping drive EV adoption … like [Corporate Average Fuel Economy] standards, as well as California’s waiver [from EPA] to set its own standards.” 

On the Inflation Reduction Act, McKerracher questioned the conventional wisdom that the law has driven so much investment ― and new jobs ― into red states, that its tax credits and other incentives would not be repealed. 

“I don’t know if that rationality will hold,” he said. Trump has been railing against EVs in his recent campaign speeches, McKerracher said, “so, whether that jobs argument and the investment argument are stronger than a more ideological or partisan one, it’s hard for us to say right now.” 

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NEPOOL Holds Summer PC Meeting amid New England Heat Wave, Climate Protests

BRETTON WOODS, N.H. — Government officials, RTO leaders, industry representatives and climate protesters from New England and beyond descended upon the Mount Washington Hotel in New Hampshire’s White Mountains for the 21st annual NEPOOL Participants Committee summer meeting June 25-28.

During a multiday stretch of extreme heat just days prior to the meeting, the ISO-NE grid hit its highest demand of the year at 23,324 MW, which caused the RTO to issue an abnormal conditions alert that extended across three days. The outage of a large generator as the system approached the daily peak on June 19 forced the RTO to dip into its operating reserves to stabilize the grid.

The peak loads throughout the heat wave were significantly reduced by the recent progress of behind-the-meter solar in the region. Preliminary data from ISO-NE indicate BTM solar reduced the peak on June 20 by about 2,500 MW, while also shifting the peak later in the day.

But the proliferation of distributed renewables is not without its challenges for grid operators. Previewing the RTO’s preliminary 2025 budget, ISO-NE CFO Robert Ludlow projected a 13.5% increase — a $37 million bump — in ISO-NE’s annual revenue requirement, largely because of increasing demands of the clean energy transition.

This increase would result in a 17.1% increase in the per-kilowatt-hour rate charged to consumers, or an approximately 25-cent increase in the monthly charge to the average ratepayer.

“The main driver of the 2025 budget is the need to add personnel to the organization to address the modeling, analysis, processing, operational and communication needs directly resulting from the clean energy transition,” Ludlow said.

The preliminary budget proposal comes on the heels of a 21% revenue increase for 2024, which also was based on needs associated with the changing resource mix. (See ISO-NE Proposes 21.5% Budget Increase for 2024.)

Ludlow said the energy transition creates new technology and cybersecurity needs and requires better modeling and forecasting “to account for net load characteristics and trends that have rapidly evolved in recent years and are anticipated to change even more significantly in the coming decades.”

ISO-NE’s ongoing work to significantly reform its capacity market, along with a greater focus on long-term transmission planning, also contributed to the proposed budget increase, Ludlow said. (See Stakeholders Support ISO-NE Long-term Tx Planning Filing, with Caveats.)

Recommendations from the External Market Monitor

David Patton of Potomac Economics, ISO-NE’s External Market Monitor, presented his annual report on the markets along with several recommendations for improvements.

“We find that the markets performed competitively but identify key improvements that will be increasingly important in the coming years,” Patton said, adding that there was “no market power abuse or manipulation affecting clearing prices.”

He noted that New England has high energy costs relative to other RTOs because of higher gas prices, along with higher capacity costs “because of over-forecasted demand ahead of the [Forward Capacity Auctions], which are slow to correct in the” capacity market.

Congestion costs remain extremely low in the region because of transmission investments made in the past 10 years, although this has led to significantly higher transmission costs, Patton said.

Patton added that ISO-NE’s wholesale markets are “fundamentally robust and structured to handle” the increasing influx of intermittent renewable generations because of “efficient shortage pricing” and the ongoing work to improve the accreditation of resources in the capacity market.

He said ISO-NE could drive more efficient prices by adopting a “look-ahead dispatch model to optimize multiple hours into the future.” Such a model could provide important signals for slower-ramping resources to prepare to come online and for storage resources to optimally dispatch, Patton said.

Patton also provided a pair of recommendations based on the assessment of a capacity deficiency event in July 2023, which was triggered by the shutdown of a Hydro-Québec transmission line because of nearby wildfires. (See Canadian Wildfires Trigger ISO-NE Capacity Deficiency.)

While ISO-NE curtailed some exports during this event, the structure of the Pay-for-Performance (PFP) pricing enabled some generators to profit while simultaneously exporting their power to neighboring regions. To close this loophole, the Monitor proposes charging all exports the PFP rates, effectively canceling out any PFP profits they could make from New England for exported power.

He also said ISO-NE should adjust how it scales PFP prices, arguing that “fixed, escalating PFP rates and shortage pricing together set prices much higher than efficient levels during most shortages, incenting suppliers to self-commit high-cost units inefficiently and retire longer-lead-time units inefficiently.”

With winter risks projected to surpass summer risks in the 2030s, Patton said ISO-NE’s proposed transition to a prompt and seasonal capacity market will help the region cope with winter challenges. However, he stressed the importance of ISO-NE’s ongoing resource capacity accreditation (RCA) changes to mitigate winter reliability risks.

Patton said the RCA project should rely on “conservative assumptions” related to LNG inventories to account for historical inventory variability associated with LNG prices. He said this would increase incentives for generators to enter firm fuel contracts.

Finally, Patton said ISO-NE’s proposed accreditation model does not explicitly include fuel inventories, and that this could lead to reliability issues during extended winter cold snaps. Failing to model fuel inventories would cause the capacity market to significantly overestimate the winter value of storage resources and undervalue the contributions of offshore wind, Patton said.

The inventory recommendation spurred some concern from NEPOOL members representing storage companies, who have stressed that the accreditation framework already outlined would result in a major reduction in capacity revenue for storage resources, potentially undermining state policy objectives regarding storage. (See ISO-NE: RCA Changes to Increase Capacity Market Revenues by 11% and Panel Provides Update on Energy Storage in Mass.)

Operations Report

ISO-NE COO Vamsi Chadalavada reported that the May energy market value was up by about 12% compared to May 2023, and by about 9% relative to this April.

His report also noted that 832 MW of solar and battery storage projects were added to the ISO-NE interconnection queue, which now totals over 47,000 MW.

New England power sector emissions for this year are tracking at a similar level as 2023 emissions, at just over 10 million metric tons of CO2 equivalent through mid-May. Coal and oil emissions are down significantly, while natural gas emissions have increased, Chadalavada’s report said.

NEPOOL

Estimated ISO-NE emissions through May 19 | ISO-NE

Climate Activists Join the Party

NEPOOL members were joined at the Mount Washington Hotel by several climate activists from the organization No Coal No Gas. They attended because “FERC sent us,” they said.

The commission recently denied No Coal No Gas’ petition of the results of FCA 18, ruling that the activists’ concerns about a structural bias of the auction in favor of fossil fuels were outside the scope of the proceeding (ER24-1290). (See FERC Accepts Results of New England Capacity Auction.)

Instead, these concerns should be raised in the stakeholder process, FERC wrote. Because NEPOOL is the official stakeholder advisory group for ISO-NE, the activists pitched in for a hotel room to bring their concerns to the summer meeting, they said.

The activists largely refrained from interfering with the NEPOOL goings on, instead distributing informational fliers in front of the meeting room about their capacity market concerns and sat at the periphery of the catered dinner and open bar eating trail mix.

They did, however, take aim at NEPOOL’s annual golf tournament. Eluding security guards by taking cover in the marshes surrounding the golf course, the activists left notes and planted coins and saplings in golf holes to express their disapproval of the grid’s continued reliance on fossil fuels and the lack of public transparency into NEPOOL meetings.