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November 17, 2024

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FERC Approves 1st PJM Proposal out of CIFP

FERC on Jan. 30 approved a PJM proposal to rework several areas of its capacity market centered around aligning how resources’ capacity contributions match up to system risk analysis (ER24-99). 

The order greenlights PJM’s proposal to accredit all resources, except energy efficiency, using a marginal effective load-carrying capability (ELCC) framework and use the hourly probabilistic modeling at the heart of ELCC to calculate the RTO’s capacity needs through the Reserve Requirement Study (RRS). It also adds additional generation capability testing requirements to assess whether generators can meet their capacity performance obligations and whether resources that have not started for a month are able to properly synchronize to the grid and operate according to their parameters. (See PJM Files Capacity Market Revamp with FERC.) 

The proposal is one of two that the RTO filed following last year’s Critical Issue Fast Path (CIFP) process. The other (ER24-98) carries a Feb. 6 deadline for action on proposed changes to PJM’s market seller offer cap. (See “PJM Steams Ahead with CIFP Filing Timeline After FERC Deficiency Notices,” PJM MIC Briefs: Dec. 6, 2023.) 

FERC said that the new approach would allow PJM to capture how resources may perform during a wider range of system conditions, namely the sort of correlated outages experienced during extreme winter weather and the diminishing reliability benefit of “highly correlated resources such as solar and short-duration storage.” 

“PJM’s marginal ELCC capacity accreditation framework reasonably values resources’ capacity based on their expected incremental contribution to resource adequacy across reasonably anticipated load, weather and resource availability scenarios given the expected resource mix,” the commission said. “We find that PJM’s proposal will allow its markets to better value the ability of individual resources to address tight system conditions and emergencies, as well as resource adequacy challenges associated with correlated resource outages and an evolving resource mix.” 

While several protests took issue with the marginal ELCC approach, arguing that it relies on an assumed resource mix before generators have cleared the auction, the commission stated that such ex ante analysis has always been part of the Reliability Pricing Model, and the improvements to the accuracy of accreditation values under ELCC outweighs any disparities between the estimated and actual resource mix. 

Vistra, American Municipal Power and Ørsted argued that PJM’s explanation of how ELCC values would be calculated was vague and that additional information is needed in the tariff revisions, rather than future manual revisions.  

CIFP

PJM Board of Managers Chair Mark Takahashi | © RTO Insider LLC

The Independent Market Monitor and several generators protested PJM’s proposal to add a dual-fuel resource ELCC class, arguing that its qualification requirements are vague and unsupported, and that recognizing the reliability benefit of resources with backup fuel without also creating a new generation class for gas-fired generation with firm fuel contracts is discriminatory. 

Calpine commented that the changes were not overly complex, though it also argued that complexity should not be a reason to reject a market design. It compared the use of loss-of-load probability models to how market participants estimate future hourly energy prices. 

FERC determined that PJM’s proposal to remove generators that fail to provide dual-fuel capability after attesting that they meet the qualifications from the ELCC class, as well as the potential for referral to FERC enforcement, was adequate to address concerns that generators could claim capabilities that they could not deliver. The commission also stated that PJM had demonstrated that it could measure the reliability benefit of resources that maintain an on-site alternative fuel that can allow them to operate for two consecutive 16-hour periods, whereas the definition and benefit of a firm fuel contract remains ambiguous. 

The proposal also effectively lowers the maximum penalty generators can be assigned in a year for failing to meet their performance obligations during performance assessment intervals (PAIs). The current annual stop-loss limit is based on the net cost of new entry (CONE), which PJM stated current results in a $135,000/MW-year stop-loss limit it believes is disproportionate to the revenues a generator can receive through the capacity market. Based on the $18,250/MW-year clearing price, PJM said the stop-loss limit is 7.5 times higher than annual market revenues. 

The change to the stop-loss calculation swaps the 1.5 times net CONE component with 150% of the Base Residual Auction (BRA) clearing price. PJM said that the swap would continue to result in a maximum penalty larger than annual revenues without being overly punitive. 

The commission rejected arguments from Vistra and Constellation Energy that tying the stop-loss limit to future auction outcomes makes it difficult for market sellers to calculate the Capacity Performance quantified risk (CPQR) component of their market offers, as they would have to estimate the final clearing price in advance. It noted that market sellers already forecast several values ahead of the auction, including energy and ancillary service revenues, expected unit performance and the number of PAIs expected in the delivery year. 

PJM’s proposal also revised the deficiency charges that fixed resource requirement (FRR) entities are assessed if they fail to procure adequate capacity prior to the BRA. The RTO argued that low capacity prices have created an incentive for FRR entities to pay the deficiency charges, which are based on clearing prices, rather than meet their own reliability needs. It also implements a four-year transition period to provide additional time for FRR entities to adjust to the new ELCC accreditation and a longer lead time for capacity planning. 

Commissioner Allison Clements released a partial concurrence and dissent, stating the proposal would address growing reliability risk that does not correspond with meeting peak loads. But she argued that the commission erred in rejecting a protest from the Advanced Energy Management Alliance and clean energy associations that the changes to accreditation and the RRS render the demand response performance window unjust and unreasonable.  

Clements wrote that the commission should initiate a show-cause order to examine the “clear mismatch between PJM’s existing demand resource availability window and its new understanding of system risk. PJM should be required to either adjust the availability window to reflect its new understanding of risk, or else demonstrate why its proposed changes have not rendered the current availability window unjust and unreasonable or unduly discriminatory.” 

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China Preparing to ‘Wreak Havoc’ on US, Cyber Officials Warn

Jen Easterly, director of the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA), warned members of Congress on Jan. 31 that the electric grid remains a prime target for China’s cyber warfare forces intent on causing “societal panic” in a future conflict with the U.S.

Easterly spoke during a hearing on Capitol Hill before the House of Representatives’ Select Committee on the Chinese Communist Party. She was joined by Gen. Paul Nakasone, commander of U.S. Cyber Command; FBI Director Christopher Wray; and National Cyber Director Harry Coker Jr. The hearing focused on China’s ability and willingness to disrupt critical U.S. infrastructure in order to sap Americans’ will to respond to a Chinese invasion of Taiwan.

FBI Director Christopher Wray | U.S. House of Representatives

Chinese President Xi Jinping reportedly told President Joe Biden recently that his country is preparing to reunify with Taiwan and is willing to use force to do so. Easterly told the committee that in recent years, CISA has “seen Chinese cyber actors … burrowing deep into our critical infrastructure to enable destructive attacks in the event of a major crisis or conflict.”

As evidence that “the threat is not theoretical,” Easterly and her fellow panelists cited Volt Typhoon, a cyber actor connected to China by CISA and other security organizations that was accused last year of infiltrating U.S. critical infrastructure organizations disguised as legitimate users, a technique called “living off the land.” (See NERC Issues Cybersecurity Data Request.)

Wray noted to the committee that the FBI had “shut down” Volt Typhoon in an operation announced that day but warned that cyberattacks remain a potent part of the Chinese leadership’s “whole-of-government campaign” against the U.S. Echoing Easterly’s assessment of China’s cyber plans, he called the country’s cyber posture “the defining threat of our generation.”

“China’s hackers are positioning on American infrastructure in preparation to wreak havoc and cause real-world harm to American citizens and communities,” Wray said. “If or when China decides the time has come to strike, they’re not [going to be] focused just on political or military targets. … Low blows aren’t just a possibility in the event of a conflict. Low blows against civilians are part of China’s plan.”

Wray described the threat from China’s state-sponsored hackers as overwhelming, saying in his opening remarks that even if all of the FBI’s cybersecurity specialists focused on China, the country’s “hackers would still outnumber FBI cyber personnel by at least 50 to 1.” Under questioning from Chair Mike Gallagher (R-Wis.), Wray said China’s willingness to recruit cyber criminal gangs would likely make the disparity even greater in a crisis.

Rep. Mike Gallagher (R-Wis.) | U.S. House of Representatives

Following up on Wray’s remarks, Nakasone asserted that the U.S. cybersecurity agencies are not without their own “force multiplier” in the form of partnerships with the private sector, which he described as a source of justifiable concern for his Chinese counterparts.

“They may have 50 to 1, but when we have the private sector, we outnumber them,” Nakasone said.

Rep. Kathy Castor (D-Fla.) focused on the energy sector in her question time, asking Easterly for her impression of the response from “the fractured nature of public and private entities.” Easterly responded by praising energy utilities, particularly for the high degree of participation by company CEOs in CISA’s cybersecurity activities.

“You do not see that across every sector, and that really shows that CEOs in the energy sector understand this issue and understand the need to make significant investments in cybersecurity and cyber resilience,” Easterly said. She added that the connections established during CISA’s “very aggressive” outreach to industry before and during Russia’s invasion of Ukraine in 2022 have continued to pay off as concerns rise about China’s intentions.

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Texas Supremes Hear Arguments Over Uri’s Prices

The Texas Supreme Court heard oral arguments Jan. 30 over whether the state’s Public Utility Commission had the authority to order electric prices be set at $9,000/MWh during the 2021 winter storm or whether billions of dollars in market transactions need to be repriced (23-0231). 

Attorneys for the PUC and several market participants said state rules make it clear the commission’s top priority is the Texas grid’s reliability. Legal counsel for Luminant, the state’s largest generator, countered that the PUC exceeded its authority with the emergency pricing order. 

When the PUC issued its directive to ERCOT on Feb. 15, 2021, as generation was dropping off during the storm, the grid operator’s algorithm was setting prices as low as $1,200/MWh. Under ERCOT’s market construct, prices are designed to increase during scarce conditions to incentivize more generation to come online. 

The problem was, there wasn’t enough generation during the first two days of the storm because of frozen equipment or lack of fuel supplies. ERCOT kept prices at the $9,000 cap — since reduced to $5,000 — until Feb. 19, resorting to rolling blackouts to keep the grid stabilized. 

Allyson Ho of Gibson, Dunn & Crutcher | The Supreme Court of Texas

“Is it really your position that [the PUC’s commissioners] are tied to the mast of competition in a way that prevents them from taking that action, if we are in a world where it actually is the case that they just have to commandeer the market for a while to make sure we’re not in the Stone Ages for a few weeks?” Justice Jimmy Blacklock asked Gibson, Dunn & Crutcher partner Allyson Ho, who represented Luminant. 

Ho said the state’s Public Utility Regulatory Act prohibited the commission from setting prices by “regulatory fiat.” 

“The agency did the one thing that the [Texas] Legislature expressly said it could not do, and that is set prices,” Ho said. 

Earlier this year, Texas lawmakers attempted to fix the loophole with House Bill 1500. The legislation includes a section that requires the commission to issue a written order when directing ERCOT to take certain actions. 

Lanora Pettit, Texas Attorney General’s Office | The Supreme Court of Texas

Lanora Pettit, a lawyer with the Texas Attorney General’s office, said “the authority existed at the time” to order ERCOT to raise prices in trying to stabilize the grid. She said the PUC’s message to ERCOT was “that your algorithm’s not working the way it’s supposed to, so please go fix it and get in line with the rules we’ve already established.” 

“The understanding of everybody in the market was that [$9,000/MWh] was the price that when load was being lost, that would be charged,” Pettit said. “What happened here was not an amendment to that rule, but instead of direction to ERCOT.” 

Ho responded for Luminant, saying the order did little to bring more generation online because all plants that could run in the frigid conditions already were doing so. 

Luminant initiated the proceeding after it incurred $1.6 billion in losses when forced to buy backup power at the system cap and gas supplies at equally exorbitant prices. (See Vistra’s Winter Storm Loss Deepens to $1.6B.) 

The company won a surprise judgment from the 3rd Court of Appeals in March when it reversed the PUC’s emergency orders. The court found the commission’s actions “entirely” eliminated competition and were contrary to state law. (See Texas Court Reverses PUC’s Uri Market Orders.) 

The state Supreme Court in September agreed to review the appeals court’s ruling. (See Texas High Court to Review Decision on Uri Charges.) 

The emergency order resulted in $16 billion of market transactions that ERCOT’s Independent Market Monitor said were incorrectly priced during the 33 hours that followed the end of firm load shed. The PUC declined to reprice the transactions. (See “Monitor: $16B ERCOT Overcharge,” ERCOT Board Cuts Ties with Magness.) 

Some of the $16 billion balance has since been securitized, and some participants have been paying off debts they now might not even owe. Other transactions have been settled outside ERCOT and can’t be undone, according to legal experts. 

Two of the Supreme Court’s justices recused themselves from the proceeding. A third was absent. A decision is not expected to be rendered for several months, but the high court normally issues judgments on all proceedings it takes up. Its current term ends June 28. 

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NYISO Asks FERC for an Extension to Comply with Order 881

NYISO on Jan. 30 requested a three-year extension to comply with FERC Order 881, claiming it needs more time to implement the software and hardware updates necessary to support the required ambient-adjusted ratings (AARs) on its transmission lines (ER22-2350).

Order 881 mandates that providers assess transmission capacity based on real-time environmental conditions, such as temperature or wind, requiring the use of AARs for short-term transmission requests and seasonal ratings for long-term requests (RM20-16). NYISO says it needs more time to comply with the order because it also must undertake a multiyear effort to upgrade its Energy Management and Business Management Systems (EMS/BMS), which are critical to monitoring reliability and managing financial operations.

NYISO was slated to implement Order 881’s enhancements by the second quarter of 2025 but now is asking for an extension of no later than Dec. 31, 2028, arguing it is infeasible to both comply with the commission’s order and deploy the nine EMS/BMS software modifications necessary to support the order’s requirements. (See “Ambient-adjusted Ratings,” NYISO Management Committee Briefs: Nov. 29, 2023.)

The ISO had been upgrading its EMS/BMS software but now contends meeting the current deadline requires a substantial reallocation of resources and personnel, which, it states, “would jeopardize the timeline and quality assurance efforts required to successfully complete a critically important technology upgrade.” It added that it cannot use these operating systems past their June 2026 vendor support date “without risking significant software failures.”

Moreover, NYISO pointed out transmission owners (TOs) cannot fulfill their own Order 881 obligations until the ISO has the requisite software and protocols in place. But it assured FERC that if granted an extension, it would maintain certain dynamic line rating functions to still give TOs the ability to modify real-time transmission line ratings.

In an attached affidavit, Rana Mukerji, senior vice president of market structures at NYISO, wrote that a compliance extension was needed because certain modifications “were not anticipated in the initial scope for this technology upgrade project and the initial project schedule.”

He cautioned that, in his experience, without an extension, “coding two sets of major modifications in parallel within the same systems significantly increases the possibility that one or both software changes result in increased implementation times and errors.”

Mukerji added, however, that if given an extension, it still would take two-and-a-half to three years to complete and implement the EMS/BMS upgrades.

NYISO asks FERC to respond by March 29, because the ISO plans to begin its 2025 project prioritization process in April and wants to know if it can proceed with the EMS/BMS project in the coming year.

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FERC Releases Latest Version of ISO/RTO Metrics Report

FERC on Jan. 30 released the latest iteration of its Common Metrics Report on ISO/RTO markets, which evaluates the performance and benefits of organized markets. 

The commission has released these reports every few years since Congress’ Government Accountability Office suggested it do more to track the performance and benefits of ISO/RTOs back in 2008. The report shows the different fuel mixes from FERC’s six jurisdictional organized markets and how much they each rely on demand response. 

Some past reports have included similar data from utilities outside of ISO/RTO footprints, but none of them responded to FERC’s efforts this time. 

The highest share of DR is in CAISO at 10%, while MISO, NYISO and PJM each have 3-6%. ISO-NE and SPP both reported less than 2%. DR in SPP grew significantly in 2022, hitting about 2% after minimal levels in earlier years. 

ISO-NE and MISO added generation in each year from 2019 to 2022, while both PJM and NYISO lost capacity overall during that time. 

FERC staff collected information on 29 common metrics across the six ISO/RTOs split across three broader categories: administrative and descriptive metrics; energy market metrics; and capacity market metrics. 

CAISO, ISO-NE, MISO and NYISO all had actual reserve margins below their expected levels between 2019 and 2022, with MISO seeing the biggest gap. Only PJM had higher actual reserve margins than expected in all four years, while SPP flipped between both categories every year. 

Every organized market reported that natural gas was their single largest fuel type from 2019 to 2022 with NYISO seeing the biggest increase in the fuel — from 58% to 64% — while ISO-NE, MISO and PJM each reported a modest increase. CAISO saw natural gas share fall from 49% to 41% over the period, while SPP saw a more modest drop from 43% to 40%. 

“The decline in the share of natural gas-fired capacity in these regions is likely driven by the relatively large increases in wind and solar generating capacity, instead of natural gas retirements,” the report said. 

MISO, PJM and SPP all had a significant amount of coal in the fuel mixes, and all saw it drop. Coal in PJM fell from 30% in 2019 to 25% in 2022, MISO saw it fall from 41% to 37% and SPP from 25% to 22%. The other markets all reported less than 3% coal in their markets. 

SPP and CAISO had the highest shares of installed wind and solar generating capacity, with the two renewables representing 31% of capacity in SPP and 30% in the California ISO. 

“The largest relative increase in generating capacity of these resource types occurred in SPP, where the share of wind and solar capacity increased from 24% in 2019 to 31% in 2022,” FERC said. 

The report also included how often each market had to issue Energy Emergency Alerts across the four years studied, with CAISO seeing 16, MISO 10, PJM six, SPP five and ISO-NE one. 

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FERC to Return $13.6M to BP from 2008 Enforcement Case

FERC issued an order Jan. 31 approving the return of $13.6 million in penalties it had collected from BP over a case of alleged manipulation of Houston Ship Channel natural gas prices after Hurricane Ike in 2008.

The commission collected $24.36 million in fines, plus interest, from BP for allegedly keeping natural gas prices at the Houston Ship Channel lower than those at the Henry Hub in Louisiana and losing money in physical trades, which benefited its financial positions and led to overall profits. FERC first issued a show cause order in the case in 2013, and years of litigation followed until a decision from the Fifth Circuit Court of Appeals came down in October 2022.

The commission had argued it should have jurisdiction over any transaction that impacts the interstate natural gas markets it polices, but the court disagreed.

BP only shipped gas over intrastate pipelines regulated by the Texas Railroad Commission in the alleged scheme, but some of that natural gas previously had crossed state lines, meaning it fell under FERC’s jurisdiction. The court said only that interstate gas could be part of the federal regulator’s enforcement action.

BP and FERC’s Office of Enforcement entered into a settlement that trimmed the penalty to $10.75 million, following the court’s findings, which meant the firm had paid an extra $13.6 million.

The oil major agreed it would not seek recovery of $250,295 of disgorgement of unjust profits, which ultimately was paid to three Texas Low Income Home Energy Assistance Program (LIHEAP) programs.

BP made a filing in November arguing FERC itself should issue an order requiring it be repaid for the $13.6 million. The order Jan. 31 directed the director of the Financial Management Division in the Office of Executive Director to wire BP the money.

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Group Looks to Create ‘Actionable’ West-wide Transmission Plan

Backers of the recently formed Western Transmission Expansion Coalition want to fill a void in the Western Interconnection by producing an “actionable” interregional transmission study — one that starts with a holistic view of the region’s needs.

“The idea here is that we’re looking at that entire collective footprint, and not just the subregions,” Sarah Edmonds, CEO of the Western Power Pool (WPP), said during a Jan. 29 call to update stakeholders on the WestTEC effort, which was launched last October. (See Plan Seeks to Boost Prospects for New Transmission in the West.)

Edmonds explained the meaning of “actionable.”

“We want to provide high-confidence information to the industry so that if there are parties who are interested in advancing transmission build solutions, they can take the information out of our study, knowing that the study has a high-confidence factor built by all of the different participants,” including states and tribes, she said.

Edmonds reaffirmed that WestTEC won’t try to tackle the especially thorny subjects of transmission cost allocation, siting and permitting, despite the wishes of some stakeholders who provided comments on the effort’s concept paper. (See Western Transmission Initiatives Differ on Dealing with Cost Allocation.)

“We don’t deny that cost allocation, permitting and siting are complicated matters and that, in many ways, this study is the easiest part of a journey towards transmission solutions,” she said. “So when we say ‘high confidence,’ we’re really hoping that the study itself will really grease the skids for future conversations around all of those things.”

Former FERC Chair Richard Glick, now a principal at GQ New Energy Strategies and a consultant for WestTEC, spoke on the call, emphasizing the need to stay focused on the planning end of transmission development.

He pointed to the region’s growing concerns around resource adequacy, rising demand from electrification and increasing instances — and “ferocity” — of extreme weather events. Glick noted also that the Department of Energy’s most recent National Transmission Needs Study noted that the Northwest and Southwest could require an additional 30% of transmission capacity by 2035.

“As I think most people have seen, there’s been some frustration that the current approach to regional transmission planning in the West — particularly outside of the California ISO — has not been very effective,” he said.

Issues of cost allocation and siting are being picked up elsewhere, Glick said. Western state officials have started moving to address regional transmission cost allocation, as evidenced by the state-led Western States Transmission Initiative.

And given the scale of federal ownership of land in the West, siting and permitting are being addressed at the federal level.

“I know the Department of Energy now is taking the lead in terms of being the lead siting agency at the federal government,” Glick said. “There’s a number of bills pending in Congress right now that would attempt to facilitate and improve the transmission siting environment that currently exists.”

‘Biggest Tent Possible’

Inclusivity was a key theme during the call.

“WestTEC is about expanded engagement,” Edmonds said, noting the organization has sought to become West-wide and move beyond the participation of just transmission-owning utilities.

Ben Fitch-Fleischmann, director of markets and transmission at the Interwest Energy Alliance, lauded WestTEC for providing a seat at the table for trade associations such as his. He noted the group’s roster already includes utilities, independent power producers, the region’s three transmission planning entities, National Laboratories, state agencies, tribal representatives and the Western Interstate Energy Board.

“So aiming to pitch the biggest tent as possible,” Fitch-Fleischmann said.

WestTEC will seek to prioritize inclusivity through its proposed governance and committee structure, which would include the Steering Committee, Regional Engagement Committee (REC) and WestTEC Assessment Technical Team (WATT).

The Steering Committee, which will oversee the effort, will be “substantially West-wide in its representation,” Edmonds said. The committee will include representatives from transmission-owning utilities from across the West, the region’s three planning groups — CAISO, NorthernGrid and WestConnect — and WECC.

The REC would seek “a broad membership to make sure we’re aligned with state policy and consumer interests,” according to Fitch-Fleischmann. Its job will be to review the work of the WATT, gain insights from the region and provide feedback.

“We need to ensure we get timely input from a wide range of governmental agencies, public interest perspectives and the like to make sure we can engage with the broader public,” he said.

The WATT will be charged with getting into the weeds around the study.

“This is not a committee where we’re looking for another warm body,” said Chelsea Loomis, WPP manager of regional transmission planning services. “We need people who can really hit the road and contribute with data that will support the study scope. We need to make sure that we are developing the scenarios that support the execution of that study scope. This will be a very busy group.”

Members of the WATT also recently selected consultants to assist in modeling for the study: Energy Strategies, with support from Energy+Environmental Economics.

WestTEC is seeking funding to support its work, just like another big effort taking shape in the Western electricity sector: the West-Wide Governance Pathways Initiative. Edmonds said WestTEC recently completed an application for a DOE grant that seems “tailor made” for its work.

“But I really want to emphasize that it is not a condition for us moving forward,” she said. “We’re going to find a way to fund this amongst ourselves, and if DOE funding comes along, that will be very helpful. But we’re not waiting around for that determination.”

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Parties Split on Biden Administration Deal on Snake River Dams

House Republicans on Jan. 30 lambasted a deal that the Biden administration struck between Oregon, Washington and four tribes on four dams along the Snake River, claiming it will lead to their breaching and threaten power reliability and other industries. 

The administration announced the deal in December, and Democrats on the House Energy and Commerce Subcommittee on Energy, Climate and Grid Security argued it would end uncertainty around the four Bonneville Power Administration (BPA) dams, which had been under litigation for decades because of their impact on salmon and other fisheries. 

The Columbia River System is the “beating heart” of the Northwest, and removing the four dams would imperil electric reliability in that region and the broader West, committee Chair Cathy McMorris Rodgers (R-Wash.) said. 

“While the administration will say only Congress has the authority to breach the dams, they wasted no time entering into commitments that bypass Congress and agreeing to spend more than a billion dollars to achieve their political goal, again without congressional approval,” she added. “What’s worse is, despite my repeated calls for transparency, the White House actively and deliberately left out voices of those who depend on the river system the most. Dozens of stakeholders and utility companies practically begged to be heard in this process, only to be turned away, shut out and ignored.” 

The Columbia River is home to 13 species of salmon that are endangered, and the tribes who live along it have depended on their annual runs for thousands of years, said subcommittee Ranking Member Diana DeGette (D-Colo.). 

“Construction and operation of the dams, private dam building and population growth have negatively impacted wild fish populations,” DeGette said. “This has led to years of litigation and court rulings, which have found operation of the dams violates the Endangered Species Act.” 

Treaty obligations to the tribes allow them to harvest 50% of the salmon catch; the fish’s declining numbers violated those obligations, said Yakama Nation Tribal Council Member Jeremy Takala. “My people’s tribal treaty rights demand it, as the U.S. Supreme Court recently affirmed treaty fishing rights include the right to actually catch fish, not just to dip our nets in empty waters without salmon.” 

Takala was involved in the negotiations on behalf of his tribe that led to the deal, which came out of a recent court case. 

“In 2021, a group of plaintiffs filed a motion for the most recent district court litigation seeking to further alter hydropower operations in the basin,” said White House Council on Environmental Quality Chair Brenda Mallory. “The United States government had a choice: defend and face the prospect of another injunction, or work with the plaintiffs and others in the region to find a path forward that could lay the groundwork for an enduring partnership with mutually beneficial solutions. We chose partnership.” 

The CEQ convened an interagency group and engaged mediators to facilitate a dialogue with tribes and states in the region, which last fall led to a Presidential Memorandum of Understanding on preserving fish stocks in the region. In December, the White House announced the deal with the “six sovereigns” (the two states and four tribes), which includes more fishery restoration efforts, funding for clean energy development by the tribe and a pause of at least five years in the ongoing litigation, with the possibility of another five. 

BPA has been working for decades to improve the environment for salmon and other fish. The deal includes additional funding to improve fisheries over the coming decade, said CEO John Hairston. BPA filed a rate impact statement showing that those additional funds would only add an average of 0.7% to customers’ monthly bills through 2035. 

National Rural Electric Cooperative Association CEO Jim Matheson disputed the relatively low cost estimates coming out of BPA. 

“If you want to build replacement power when you breach these dams — which I don’t think you can do and have the same comparable resource, by the way — you’re going to spend a lot of money, and it will have a big impact,” Matheson said. 

The four dams are also highly complementary to the region’s wind resources because they all have technology that allows them to ramp up and down quickly depending on how hard the wind is blowing, Matheson said. 

The agreement filed in court recognizes that Congress must enact legislation to actually breach the dams, but Matheson argued the deal was piling more and more compliance costs on them. 

“This settlement effort is a way to force Congress’ hand and put Congress in a position where breaching is more likely,” he said. 

Matheson declined to use the word “secret” that was often repeated by Republicans at the hearing about the negotiations, but he did note that just six parties were in the room with the federal government, and so far NRECA and other industry representatives’ letters taking issue with it have not been answered. 

The Yakama Nation’s Takala opened his testimony by calling claims about secret negotiations with “radical environmental groups” as claims “fueled by fear and misinformation.” 

“This agreement is a historic opportunity to help save our salmon and secure a just and prosperous future for everyone in the Columbia Basin,” Takala said. “First, for clarity, the Yakama Nation is not a radical environmental special interest group.” 

Its rights to salmon from the rivers are guaranteed by the treaty the tribe signed with the federal government in 1855, he added. 

“Since time immemorial, the strength of our Yakama Nation and its people have come from the Nch’í-Wána — ‘the big river,’ or the Columbia River — and its tributaries and from the fish, game, roots and berries nourished by their waters,” Takala said. 

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FERC Approves New Relay Standard

FERC has approved a new reliability standard intended to prevent conflict between registered entities’ protective relay settings and grid operators’ ability to protect reliability, nearly a year after NERC’s Board of Trustees approved the standard. 

NERC’s board adopted the standard, which was developed as part of Project 2021-05 (Modifications to PRC-023), at its meeting in Tucson, Ariz., last February. (See “New Standards Sent to FERC,” NERC Board of Trustees/MRC Briefs: Feb. 15-16, 2023.) The commission gave its assent to PRC-023-6 (Transmission relay loadability) Jan. 25 in a delegated letter order (RD23-5).  

As explained in NERC’s petition for approval, the new standard is intended to retire “redundant and unnecessary language that has contributed to confusion regarding” the applicability of previous versions of the standard to power swing blocking (PSB) relays. PSB, also called out-of-step blocking, is installed in long-distance transmission relays to prevent tripping during stable power swings.  

Project 2021-05 was initiated after stakeholders expressed concerns that the standard “could lead to increased reliability risk by entities limiting or disabling their [PSB] elements.” The specific issue, according to NERC, was requirement R2, which mandated that transmission owners, generator owners and distribution providers set their PSB elements “to allow tripping of phase protective relays for faults that occur during the loading conditions used to verify transmission line relay loadability.” 

NERC told FERC in its petition that the team for Project 2021-05 determined that this requirement is redundant because R1 addresses the same “fault condition” as R2 and “requires the same entity response.” R1 provides a set of criteria for entities to use to “prevent [their] phase protective relay settings from limiting transmission system loadability … for all fault conditions.”  

The team observed that noting a specific fault condition, as R2 does, is unnecessary because R1 already covers all conditions. In addition, R2 “does not support directly the purpose of the … standard,” which mandates that protective relay settings not interfere with “operators’ ability to … protect system reliability and [shall] be set to reliably detect all fault conditions and protect the electrical network from these faults.” 

NERC’s petition also noted that PRC-027-1 (Coordination of protection systems for performance during faults) “addresses the same reliability concern as … R2 in a much clearer and more comprehensive fashion.” That standard requires entities to coordinate their protection systems to ensure they operate in the intended sequence when faults occur. 

The ERO said that in the event that a PSB relay did not allow tripping, “an unintended sequence of tripping” could result in other relays tripping through backup protection systems.” This would mean the coordination was not designed properly, a violation of PRC-027-1. NERC considered this further evidence that the older standard’s requirement was unnecessary, because an entity could still be audited for the PSB failing to trip.  

In approving the standard, FERC noted it received no comments, protests or motions to intervene when the ERO’s petition was published in the Federal Register. The new standard will take effect on April 1, 2024, the intended effective date of PRC-023-5. The latter standard was approved in May 2021 to replace the currently effective standard PRC-023-4, but NERC asked FERC in its petition to let the new standard supersede it.  

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FERC Approves ISO-NE’s Day-Ahead Ancillary Services Initiative

FERC on Jan. 29 approved ISO-NE’s proposal to create a day-ahead ancillary services market and retire the current Forward Reserve Market (FRM), effective March 1, 2025 (ER24-275).

Dubbed the Day-Ahead Ancillary Services Initiative (DASI), ISO-NE and NEPOOL jointly filed the proposal at the end of October. The new market will procure operating reserves and fill any gaps between the amount of energy procured in the Day-Ahead Energy Market (DAEM) and the load forecast.

“We are pleased with the approval by FERC to create a day-ahead ancillary services market that, together with today’s Day-Ahead Energy Market, creates a single, jointly optimized day-ahead market,” ISO-NE told RTO Insider in a statement.

With climate change increasing weather variability as the resource mix shifts toward weather-dependent resources, DASI will “encourage reliable resource performance and prepare the system on a day-ahead time frame with the flexibility needed to manage these new operational uncertainties,” ISO-NE said.

ISO-NE and NEPOOL noted in their joint filing that the existing DAEM “only procures energy to meet bid-in demand, and if the load forecast exceeds the amount of cleared energy from physical suppliers, there remains what the ISO refers to as a day-ahead ‘energy gap.’”

The RTO currently relies on out-of-market solutions to identify resources to fill these energy gaps and provide operating reserves.

“This process results in both under-compensation to those resources identified to provide these capabilities during the operating day and no specific financial obligation or incentive for such resources to be prepared to perform in real time in accordance with the operating plan,” the proposal said.

The ancillary services market will be run in conjunction with the existing DAEM; it will procure 10-minute spinning and non-spinning reserves and 30-minute operating reserves. It will also include an “Energy Imbalance Reserve” product, which is intended to fill energy gaps between the DAEM and the load forecast.

“DASI will provide targeted compensation and clear financial obligations and incentives for the flexible resources on which the region currently relies, and on which it will increasingly rely as the region heads into the future,” the filing said.

DASI will replace ISO-NE’s FRM, which provides forward seasonal payments for resources to provide 10-minute non-spinning reserves and 30-minute operating reserves. ISO-NE has said the FRM is incompatible with the implementation of DASI.

ISO-NE noted that an analysis of projected DASI revenues based on a 2019-2021 study period found that the initiative would increase annual wholesale market costs by about $104 million, or about 1.1%. The study indicated that the ancillary market would generate “substantial revenues” for storage resources, ISO-NE added.

The joint filing was supported in comments by the New England States Committee on Electricity, the Electric Power Supply Association, the National Hydropower Association and the New England Power Generators Association.

Meanwhile, LS Power expressed concern that replacing the FRM with DASI could decrease revenue for flexible resources.

“The overall DASI proposal will cut revenues for flexible generation by as much as 94%,” the company wrote in its comments, adding that DASI could introduce “unreasonable and undercompensated risks” for peaking resources.

In response, ISO-NE disputed LS Power’s revenue calculations. The RTO noted that its impact assessment found that total net revenues for ancillary service suppliers would decrease by only about $5 million annually, adding that this assessment “may understate the revenues that will be earned by reserve-capable suppliers, compared to those currently earned through the FRM.”

The DASI filing requires ISO-NE’s Internal Market Monitor “to issue ad hoc reports on the competitiveness of any major market design change within one year of the effective date of operation, and on its performance within three years.”

The RTO recognized requests from stakeholders for longer-term reserves and wrote that it plans to kick off discussions on longer-term products for the real-time and day-ahead markets in 2025.

FERC found that DASI will “materially improve operating reserve resource readiness, efficiency and day-ahead price formation in ISO-NE without undue increases in wholesale market costs.”

The commission expressed skepticism of the concerns raised by LS Power, writing that the company “does not demonstrate that revenue levels under DASI, which result from market-determined clearing prices, will not be just and reasonable for the purpose of procuring and compensating operating reserves.”

In a concurring statement, Commissioner Allison Clements expressed strong support for the changes.

“The DASI reforms appear to be an important step forward for ISO New England’s ancillary services market and one reflecting the region’s evolving operational needs as its resource mix changes,” Clements wrote.

“For a proposal of this complexity to have near universal support in the record and unanimity in the stakeholder process is a testament to the hard work and productive collaboration of many in New England,” she added. “It is worth taking a moment to give credit where credit is due.”