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November 20, 2024

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MISO: Wisconsin Coal Plant to Stay Online as SSR Unless Stakeholders Offer Solutions

MISO said unless stakeholders come up with an alternative it hasn’t explored, it will have to renew its sole system support resource — Manitowoc Public Utilities’ Lakefront 9 coal unit — for another year.

At a Nov. 5 technical study task force meeting, MISO’s Huaitao Zhang said the RTO continues to find steady state thermal violations during the summer months that require mitigation.

He said MISO didn’t land on any transmission reconfiguration options, operating guide substitutions or demand-side solutions that can negate the need for Lakefront 9 staying online to sustain reliability. MISO uses system support resource (SSR) agreements to keep generation operating past planned retirement dates for the sake of system reliability.

Further, Zhang said MISO has ruled out redispatch as a solution because there are limited resources in that area of Wisconsin. Local transmission owner American Transmission Co. (ATC) also discourages manual load shed as a viable mitigation, he said.

If no stakeholders come forward with an alternative that hasn’t occurred to MISO, Zhang said MISO must begin a new SSR term with the municipal utility on Feb. 1. Zhang asked stakeholders to offer their ideas over the next two weeks.

Lakefront 9 has been operating as an SSR since February 2023, after MISO discovered that thermal overloading could occur on several nearby constraints if the plant was permitted to suspend operations as scheduled. Manitowoc Public Utilities originally sought to idle the 63-MW Lakefront 9 until 2026 and to convert it to a renewable fuel source. (See FERC Again Questions MISO Reliability Payments to Wisconsin Coal Plant.)

MISO has said ATC’s planned, 138/69-kV transmission upgrades for the area, which would improve system performance and allow it to lift the SSR agreement, won’t be completed until mid-2028.

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State Funds Support Microgrids on California’s Tribal Lands

SACRAMENTO, Calif. — Energy projects designed to accelerate decarbonization and strengthen reliability in vulnerable communities are receiving significant investment thanks to the California Energy Commission’s Electric Program Investment Charge (EPIC) program.

“This summer has been the hottest summer in recorded history in California and the hottest summer recorded globally,” David Hochschild, chair of the CEC, said at the Oct. 28 EPIC Symposium. “Yet another sign that we know the great challenge of our generation is climate change, and the solutions for that, the seed planting, is here in our state in California and in particular, this program.”

Tribal leaders, entrepreneurs, grid operators and energy officials convened to discuss the benefits and challenges of the EPIC program, which invests more than $130 million annually in clean energy research and development. The program aims to expand renewable energy, advance electrification, enable a more decentralized electric grid, support local economies and improve the affordability and health of local communities.

The California Public Utilities Commission established EPIC in 2012, and the ratepayer funded program has invested $1.2 billion into clean energy research, development and commercialization.

Hochschild highlighted many of California’s climate successes thus far, including reaching 61% clean energy on the grid, 26% of new vehicle sales being electric, and building 13 GW of energy storage in the past five years and 27 GW of clean energy capacity since 2018.

“Climate change is making it harder to fight climate change,” Hochschild said, but “there’s an opportunity to do some incredible seed planting for the future, and there’s already great momentum.”

‘Clean Energy Army’

The EPIC program helps to establish microgrids for several California tribes, which serve as a “refuge” from frequent blackouts and lack of reliability.

Early EPIC funding helped launch the first behind-the-meter microgrid in California on Blue Lake Rancheria territory, and up to nine tribes have followed suit.

“Our microgrids serve as a community refuge during times of crisis,” Jason Ramos, tribal council member of the Blue Lake Rancheria Tribe, said. Before the development of the microgrid, the tribe would experience intermittent blackouts that could affect key services like the health clinic and gas station.

The program also helps to fund the Tribal Energy Resilience and Sovereignty (TERAS) project, which is helping four tribes transform one of the state’s least reliable electrical circuits, the “Hoopa 1101.” The 142-mile-long line provides electricity to the Hoopa, Yurok and Karuk tribes, who experience some of the most frequent and longest duration outages in California. The project, in collaboration with the Blue Lake Rancheria tribe and the Schatz Energy Research Center, will establish three nested microgrids along the circuit to establish better reliability.

“It’s going to be a real game changer and is something that we absolutely need in the region,” Linnea Jackson, general manager of the Hoopa Valley Public Utilities District, said. “We look forward to having energy resiliency.”

The microgrid will cover 130 distribution circuit miles and serve 2,000 customers who experience an average of 100 hours of blackouts a year, explained Peter Alstone, faculty scientist at the Schatz Center.

“Everybody deserves reliable power, and when you have blackouts that frequent, people aren’t willing to invest in electric vehicles and electrified heating,” Alstone said. “This decarbonization challenge is just not on the table in places where the power is going out. So, this microgrid is a really important investment.”

Speakers also highlighted the importance of communicating effectively with tribes. Talking “to each other versus talking at each other” will accelerate progress, said Bo Mazzetti, chair of the Rincon Band of Luiseño Indians.

“Sovereign tribal governments are great partners,” Jackson said. “I really look forward to being a part of this clean energy army.”

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Ørsted Values Latest Revolution Wind Setback at $175M

A one-in-a-thousand problem with a key foundation component is the latest setback in U.S. waters for Ørsted and is blamed for its latest nine-digit cost impairment. 

The Danish offshore wind giant revealed the new problems with Revolution Wind in its third-quarter earnings report Nov. 5 but balanced it out with some good news: It was able to reverse significant portions of previously recorded impairments on Sunrise Wind, resulting in a net impairment for the quarter of $42 million rather than $228 million. 

Offshore work began this year for Revolution and is expected to begin next year for Sunrise. Onshore work for Sunrise is underway. 

It is the second setback in as many quarters for Revolution, a 704-MW wind farm that will feed into Connecticut and Rhode Island.  

With its second-quarter financial report in August, Ørsted announced that the environmental contamination at the site for Revolution’s onshore substation was worse than initially thought, so the cleanup would take longer. This pushed the projected completion date back from 2025 to 2026. (See Revolution, Sunrise OSW Projects Face New Delays.) 

During a Nov. 5 conference call with financial analysts, CEO Mads Nipper said there are potential problems with the monopile driven into the seabed for Revolution’s offshore substation. 

“Although it has been safely driven to the target depth, it may not be suitable for use as currently installed,” he said. “The cause is likely to be related to the resistance within the seabed soil.” 

This has happened only twice before with the more than 2,000 offshore wind foundations Ørsted has installed worldwide, Nipper said. 

“Using our extensive experience, our team [is] assessing the root cause and establishing the best part forward for the project.” 

As a precaution, the company has exercised its option to extend the contracted services of one of the installation vessels working on site. These ships typically command extremely high per-day charges, and Nipper said the cost was higher than anticipated. 

Ørsted is taking an impairment of $175 million because of these developments, raising Revolution’s total impairment for the first nine months of this year to $514 million. 

Aside from all this, Nipper said, the project is proceeding well.  

No new problems have cropped up with the onshore substation, and steady progress is being made offshore: 52 foundations, 20 array cables and nine turbines are in place. No further delays are expected in the commercial operation date. 

The team will suspend monopile installation from Dec. 1 to April 30 but plans to continue turbine installation through the winter. 

During the call, CFO Trond Westlie alluded to the many moving pieces of the offshore wind industry and world economy, and to their potential continued impact on the financials of Ørsted and Revolution Wind: “Let me remind everyone again that as we have had to recognize impairments on these projects in the past, any changes to the business case, including movement to the interest rates, are likely to lead to further adjustment to the impairments, as there is no headroom.” 

But things eventually should get better, he added: “It is important to keep in mind that once the projects are operational, they will contribute with significant earnings and cash flow throughout their lifetime.” 

When Nipper and Westlie completed their presentations, they fielded questions for nearly an hour, including: 

Q: Are you concerned that Donald Trump if elected would revoke the investment tax credit adders? 

A: We are assuming 40% and see minimal risk of that changing. 

Q: What portion of the components of Revolution Wind and Sunrise Wind are foreign, and what would be the impact of tariffs imposed by a new president? 

A: I cannot give you a percentage off the top of my head. Many of the major components of Revolution are already onshore, awaiting installation, and the phase-in period for any new tariffs should make their effects manageable. 

Q: Are there any other significant known unknowns with Revolution that could create problems in the next few quarters? 

A: We can never say that there are no risks left in a project until it is done. But with what we know now, we do feel comfortable calling this a robust project. 

Q: With all the problems so far with Revolution, do you think you have made enough contingencies for Sunrise? 

A: We, of course, are assessing that all the time. With our current knowledge, yes, we do. 

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FERC Approves SPP’s Winter RA Requirement

FERC on Nov. 4 accepted SPP’s tariff revisions that add a winter season resource adequacy requirement for load-responsible entities, effective Jan. 1 (ER24-2397). 

The commission said the requirement and its associated deficiency payment provide an incentive that will help ensure LREs proactively procure and maintain sufficient capacity during the winter season. SPP’s proposal extends its summer season resource adequacy (RA) requirement into the winter, replacing the existing winter obligation. 

FERC said SPP’s tariff revision addressed its November 2023 rejection of the grid operator’s first filing. The RTO added language clarifying that a resource can only be used to meet the RA requirement if the LRE “expects [it] will be available for the duration of the [season]” and has “no knowledge [that the resource] will become unavailable.” 

SPP’s new language included an exception for authorized outages, as long as the outage or outages do not exceed 30 days of either season. 

Protesters argued that the first revision didn’t include a requirement that resources in an LRE’s workbook are expected to be available. LREs could purposefully include generators they knew would be offline during the season, undermining resource adequacy, the protesters said. 

The commission disagreed with the SPP Market Monitoring Unit’s contention that the lack of a definition for “forced outage” renders authorized outage’s definition ambiguous and the filing unjust and unreasonable. It pointed to SPP’s argument that forced outages, though not explicitly defined in the tariff, are not studied and therefore cannot fall within the definition of authorized outages. 

“The definition states that authorized outages will be studied by SPP as the balancing authority,” FERC said. “The definition of authorized outages also only encompasses those outages that have received authorization from SPP and provides that the balancing authority does not authorize forced outages.” 

The commission noted that SPP extended the expectation of availability that previously applied only to the summer RA requirement, which it previously accepted. The RTO also imposed additional requirements, FERC said, in rejecting the MMU’s argument that the tariff must include further detail to ensure that SPP and its stakeholders know which situations disqualify a resource from the expectation of availability. 

“Having found SPP’s proposal just and reasonable,” FERC said, it didn’t need to “consider alternative proposals” in the proceeding. 

SPP added the winter resource adequacy requirement after increasing its planning reserve margin, saying the obligation was the culmination of a large amount of work by several stakeholder groups. (See “Board, RSC Endorse Winter Obligation,” SPP Board/Members Committee Briefs: July 24-25, 2023.) 

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Feds Accuse Tenn. Man of Substation Attack Plot

The FBI announced it has charged a Tennessee man with attempting to destroy an energy facility and attempting to use a weapon of mass destruction as part of a plot to cause civil unrest and spark a civil war.

Agents arrested Skyler Philippi, 24, of Columbia, Tenn., on Nov. 2, according to the criminal complaint. The arrest was the culmination of a plot several months in the making to rig a drone with explosives and fly it into an electric substation near Nashville to disrupt power to the area.

“Skyler Philippi believed he was moments away from launching an attack on a Nashville energy facility to further his violent white supremacist ideology — but the FBI had already compromised his plot,” Attorney General Merrick Garland said in a press release. “This case serves as yet another warning to those seeking to sow violence and chaos in the name of hatred by attacking our country’s critical infrastructure: The Justice Department will find you, we will disrupt your plot, and we will hold you accountable.”

Philippi first made it on the FBI’s radar in June 2024, when he allegedly told a “confidential human source” (identified as CHS-1 in the complaint) that he wanted to commit a mass shooting at a YMCA facility in Columbia. CHS-1 introduced Philippi to a second source (CHS-2) who lived closer to Philippi and could meet him in person. The FBI said both sources are “reliable [and have] previously provided accurate information to the FBI in multiple investigations.”

CHS-2 and Philippi continued to talk over the phone and via text for the next month about Philippi’s plans and beliefs. The suspect discussed his desire to “do the most damage [by attacking] high economic, high tax, political zones” in major cities. He said he was working on a “threat report” on the best way to disrupt the electric grid, including by attacking substations. He also asked for the informant’s help stealing a train de-railer to wreck a train in Tennessee.

In August, CHS-2 met Philippi in person, where he introduced the suspect to an “undercover employee” (UCE-1). Philippe told UCE-1 that he had ties to various white supremacist groups including Atomwaffen Division, whose founder, Brandon Russell, was arrested by the FBI in 2023 for plotting to attack electric substations in Baltimore. (See Feds Charge Two in Alleged Conspiracy to Attack BGE Grid.)

Manifesto Outlines Racial Beliefs

FBI agents said Skyler Robert Philippi planned to use a drone to plant explosives in a substation. | Metropolitan Nashville Police Department

Philippi shared portions of his “manifesto” with UCE-1, indicating his belief in “radical armed struggle [as] the only end to protecting and preserving our folk,” “accelerationism [as] a means to an end” and the need to destroy “the interconnected or otherwise globalized world.”

UCE-1 introduced Philippi to a second undercover employee, UCE-2, in September. Philippi told the two of his plans to cripple the power grid by attacking eight or more substations. He indicated he had studied previous attacks on the power grid in North Carolina and California with firearms. The complaint did not specify which attacks, but they may have included rifle damage to two substations in Moore County, N.C., in 2022 that knocked out power to 45,000 customers. (See Duke Completes Power Restoration After NC Substation Attack.)

However, Philippi told the undercover employees that he did not believe rifles could do enough damage to cause widespread outages. He said mounting explosives on a drone would be more effective. Philippi asked UCE-1 and UCE-2 to help him get the components to build the drone, which they provided to him later that month.

The three then drove to scout out substations in the Nashville area. During the drive the undercover employees introduced Philippi via phone to a third colleague, UCE-3, who Philippi asked to send him explosive materials including C-4 and black powder.

Philippi and the other agents then continued their scouting exercise, with Philippi outlining the plan for the others. The complaint emphasized his leadership of the plot, with Philippi suggesting the clothing the UCEs should wear to evade suspicion and telling them to wear leather gloves rather than latex and nitrile to avoid fingerprints.

Throughout October, Philippi worked on building the drone and obtaining more explosive materials. He ultimately was unable to build a working drone, so the UCEs helped him get another one at his request. He also asked the UCEs to build pipe bombs for him; the complaint said they replaced the black powder UCE-3 provided with “an inert substance” to prevent the bombs exploding.

Plot Disrupted in Final Stages

On Nov. 2, the UCEs picked Philippi up and gave him the drone, fake pipe bombs and the explosive he had ordered from UCE-3. The complaint did not specify whether UCE-3 provided actual explosive material. The UCEs drove him to a field where he conducted a test flight of the drone.

They then had lunch and drove to a hotel in Nashville where they “conducted a Nordic ritual” involving prayers to the Norse god Odin. The UCEs asked if Philippi still wanted to go ahead with the plan. He confirmed that he was “fully committed” and wanted to “do something big” that would be remembered in history. Philippi also revealed he had a handgun to shoot at police who tried to interfere with them.

After completing their preparations at the hotel, Philippi and the UCEs left to drive to the attack site. The UCEs left the vehicle, taking Philippi’s gun. Philippi went to the rear of their vehicle to prepare the drone and explosives, where law enforcement officers arrested him. The complaint said that when Philippi was arrested, he had powered up the drone, armed the explosive device and was preparing to attach the explosive to the drone.

Philippi’s charges carry a maximum sentence of life in prison. Prosecutors with the Middle District of Tennessee and the National Security Division’s Counterterrorism Section are handling the case, the Justice Department said.

“Dangerous threats to our critical infrastructure threaten every member of this community and will not be tolerated,” acting U.S. Attorney Thomas Jaworski for the Middle District of Tennessee said. “We will always work with our law enforcement partners to identify and stop any and all efforts to wreak this kind of havoc and will not hesitate in prosecuting those involved to the fullest extent of the law.”

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NERC Releases Final ITCS Draft Installments

In the final installments of the Interregional Transfer Capability Study (ITCS), released this week, NERC called for “a diverse and flexible approach” to meeting the future transfer needs of the U.S. electric grid.

NERC released the second and third draft ITCS installments on schedule Nov. 4. Part 1 of the study, released in draft form Aug. 28, comprised a transfer capability analysis summing up the current transfer capabilities between transmission planning regions in North America. (See NERC Examines Transfer Capability in Draft ITCS Installment.)

Part 2 includes recommendations for prudent additions to transfer capability that could strengthen grid reliability, while Part 3 lays out recommendations to meet and maintain total transfer capability. The three installments will be combined and submitted to FERC by Dec. 2 as ordered by Congress in the Fiscal Responsibility Act of 2023. (See Lawmakers, White House Promise More Work on Permitting After Debt Deal.) FERC will post the report for public comment and then submit a report to Congress along with recommendations for statutory changes.

A fourth document will follow in the first quarter of 2025, covering transfer capabilities and prudent additions from the U.S. to Canada and between Canadian provinces. While this plan goes beyond Congress’ mandate, NERC said earlier this year that the study “would be incomplete without a thorough understanding of the Canadian limits and available resources.”

“The ITCS emphasizes a balanced approach — one that identifies the unique needs of each region and determines where targeted and meaningful investments can make a real difference in ensuring reliability and resilience,” NERC Director of Reliability Assessments and Performance Analysis John Moura said in a statement. He added that NERC would continue “to ensure the [electric grid] is prepared for tomorrow’s challenges without taking a one-size-fits-all approach.”

NERC’s recommended prudent additions were based on the transfer capability analysis in Part 1, which used the transmission planning regions identified in FERC Order 1000 to create two different base cases covering summer 2024 and winter 2024/25. The model mapped existing interfaces, along with potential new interfaces that might be constructed in the coming decade, and used historical weather data to estimate load and resource availability for the future.

NERC defined “prudent additions” as “transmission enhancements … to mitigate grid reliability risks under the most challenging conditions.” Economic issues and cost-benefit analysis were not considered in the analysis.

ITCS authors selected the 2033 resource mix as the basis for their projections, even though interregional transmission projects typically need at least 10 years for construction, because “forecasting demand and resources beyond that time frame becomes increasingly speculative and uncertain.” The impact of added transfer capability during extreme events was then evaluated using a six-step process:

    • identify hours of resource deficiency through calculating available generation and storage, subtracting load and factoring in existing transfer capacity;
    • quantify maximum resource deficiency by calculating the yearly maximum resource deficiency across 12 weather years;
    • identify and prioritize constrained interfaces;
    • allocate additional transfer capability across constrained interfaces;
    • iterate incremental additions until all resource deficiencies are resolved, if possible; and
    • finalize prudent levels of transfer capability.

The authors recommended a total of 35 GW of additional transfer capability across the planning regions studied, with the greatest amount — 14,100 MW — found in ERCOT across the SPP-South connection (4,100 MW) and two entirely new connections to Front Range (5,700 MW) and MISO-South (4,300 MW). NERC noted that even with these prudent additions, it was still not possible to resolve all energy deficiencies “due to wide-area resource shortages.”

The same was true in the California-North region, where the report recommended 1,100 MW of additions on the Wasatch Front connection.

NERC described “various options” that entities can use to mitigate the risks identified in the report and address the recommended additions. Among these are the development of internal resources such as generation and storage, which can reduce the need for external transfers; building new transmission lines or increasing transfer capability with neighboring regions; and demand-side management and resilience initiatives.

“While the study highlights specific needs to improve resilience under extreme conditions, NERC encourages flexibility in meeting these needs through various pathways,” the ERO said, suggesting “enhanced collaboration with regional planning entities, careful alignment with FERC and state policies, and consistent stakeholder engagement to effectively assess, refine and execute strategies.”

In addition, NERC emphasized that “a one-size-fits-all approach may not be solely effective” in overcoming transmission constraints; in particular, the ERO said that a blanket universal transfer capability minimum across regions “could lead to inefficient investments” in areas where transmission capability is already adequate or excessive.

NERC said it hoped the ITCS would “foster collaboration between utilities, regional planning organizations and state regulators” to tackle the transmission challenges facing the grid. It also suggested revisiting the ITCS in the future to account for advances in technology and changes to the resource mix.

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Wash. Gov. Approves Controversial Wind Farm

Gov. Jay Inslee has approved a revised plan for the largest wind turbine farm in Washington, stretching across 24 miles in the Horse Heaven Hills in the southeastern part of the state. 

His approval leaves intact more than three-quarters of the originally requested number of turbines. The proposed turbine farm has drawn criticism for its possible impact on Native cultural sites and on wildlife in the area, as well as its visibility from the Tri-Cities of Richland, Kennewick and Pasco. 

The project has provoked contentious disagreement among several environmental groups, with wind and solar proponents on one side and wildlife preservationists on the other, who raise concerns about the effects on ferruginous hawk nests. 

The state’s Energy Facility Site Evaluation Council (EFSEC) approved the recommendation 4-3 in September. EFSEC posted on its website an Oct. 18 letter from Inslee (D) that said he considered “impacts on habitat, wildlife, tribal cultural resources, public safety and visual aesthetics. I believe this project is appropriately sited. … I also find that the council thoroughly and adequately responded to issues and concerns raised by tribal partners, the community and other stakeholders relating to this project.” 

Opponents of the project have until Dec. 17 to appeal the decision to the state’s courts.  

Inslee has pushed new wind turbine projects and solar panel farms as part of his campaign to trim the state’s carbon emissions. His Oct. 18 letter hinted at his impatience with the Horse Heaven Hills project taking most of 2024 to be approved. 

“We will not meet our state’s urgent clean energy needs if the path to a final recommendation from the council spans multiple years and contains conditional micro-siting process requirements that further prolong final siting approval for a significant portion of the primary project components,” Inslee wrote. “Timely and efficient action by the council is essential to our mission to mitigate the impacts of climate change and provide adequate green energy alternatives. I strongly encourage the council to identify opportunities to increase its efficiency and provide for more timely decision-making. You can expect my office to engage with you on this critical issue before the end of my administration.” 

Project developer Scout Clean Energy of Boulder, Colo., originally made plans for two scenarios, calling for a maximum of 147 of the 670-foot-tall wind turbines or 222 of the 500-foot turbines along a 24-mile east-west stretch along the hills. However, EFSEC decided in February to implement two-mile buffer zones around 60 to 70 ferruginous hawk nests in that area and remove turbines along the north slopes of the hills. 

The company says those buffer zones cut Scout Clean Energy’s number of turbines by roughly half. At that time, the company said those changes would trim the projected 1,150 megawatts of wind power to 236 megawatts. 

Inslee sent the February recommendations back to EFSEC, wanting to increase the number of turbines back to the original estimates. In recent months, EFSEC trimmed some ferruginous hawk buffer zones to 0.6 mile around the nests. In 2021, the Washington Fish & Wildlife Commission changed the status of ferruginous hawks from threatened to endangered. 

The recommendations from September call for a 0.6-mile buffer around the nests, plus a 0.25-mile buffer around historic Native American fire sites, plus a one-mile buffer alongside Webber Canyon, another culturally sensitive spot for the Yakama Nation. 

If the 500-foot turbines were installed, that would trim the number of turbines by approximately 50, from 222 to roughly 172. If the 670-foot turbines were installed, that would cut the number of turbines by approximately 34, from 147 to roughly 113. More precise figures will be calculated later. 

Scout Clean Energy’s original proposal also included two 500-megawatt solar panel farms on the east and west sides of the 24-mile stretch. EFSEC ordered the eastern solar farm removed because of its proximity to sensitive Native cultural sites. 

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SPP Board/Regional State Committee Briefs: Oct. 28-29, 2024

Directors Approve 2025 Budgets, Net Revenue Requirement

LITTLE ROCK, Ark. — SPP’s Board of Directors approved the RTO’s 2025 operating and capital budgets and its net revenue requirement (NRR) on Oct. 29 following a unanimous endorsement by the Members Committee.

The budget includes $296.3 million in expenses, a 7.6% increase ($21 million) from this year’s budget. SPP’s headcount has exceeded 650 to meet an increasing workload, thanks to Western Interconnection market services and FERC orders 881 and 841.

The NRR is budgeted for $204 million, a 6.2% increase from the current $192.1 million. Staffing and related expenses account for about two-thirds of the NRR. SPP’s tariff limits the NRR to a ratio of estimated annual transmission usage, the effective administrative fee. Currently capped at 46.5 cents/MWh, SPP has filed a board-approved increase to 51.5 cents/MWh.

The capital budget was initially set around $35 million, more than doubling the 2024 allocation of $17 million. However, SPP identified projects that could be deferred or eliminated to reduce that spending to $22.1 million.

Independent Director Stuart Solomon, who chairs the Finance Committee, commended staff and the committee for putting together “one of the best budget documents” he has ever seen.

“I think you’ll agree with me that they met the goal of balancing necessary expenses with affordability and member value,” he told stakeholders during the board’s October meeting.

“We started way back in February of this year with a particular goal in mind: to try to bring greater alignment between SPP strategy, our operating plan, the identification of the necessary resources to effectuate that operating plan and, ultimately, the delivery of the budget,” CFO David Kelley said.

Kelley and Solomon both pointed to the NRR’s run rate, or the cost to operate the RTO year to year, as a metric to watch. The NRR’s budgeted run rate next year is a 4.5% increase from 2024.

“I think that’s impressive, given the increasing costs that all of us are experiencing and the amount of new work and requirements that SPP and SPP staff is dealing with,” Solomon said.

Members expressed support for the budget but cautioned SPP about not forgetting who ends up paying for the budget increase.

“We appreciate the additional focus on controlling costs in this particular budget,” Oklahoma Gas & Electric’s Emily Shuart said. “That said, I do want to be transparent about our expectations going forward, and that we don’t find the 4.5% year-over-year increases sustainable or representative of the budget constraints that members like OG&E are facing. This budget is just one cost stream associated with membership that our customers end up bearing.”

“We understand that these are real dollars that we’re asking you all to spend and they show up on ratepayer bills at the end of the day,” Kelley said. “I can assure you that everyone throughout the SPP organization understands that, and we understand that we have to keep costs as low as reasonably possible.”

Dec. 16 Key Date for Markets+

SPP’s Antoine Lucas, vice president of markets, told stakeholders that staff are targeting Dec. 16 to begin building out its Markets+ offering in the Western Interconnection.

The RTO hopes its response to FERC’s deficiency letter will have met with the commission’s approval by then and that it has also executed Phase 2 funding agreements with interested market participants. (See SPP Dispels Concerns over Markets+ Deficiency Letter.)

“With those two things, we have everything that we need to move forward with the actual development of the market and the execution of Phase 2,” Lucas said Oct. 28 during staff’s quarterly stakeholder briefings, alluding to the market’s development and delivery.

He said staff have been working “extensively” with Western stakeholders in developing the market protocols. The Markets+ Participants Executive Committee will vote on the new protocol language during its Nov. 12-13 meeting in Portland, Ore.

SPP has also filed its response to FERC’s deficiency letter for the Western expansion of its RTO. It submitted the tariff in June as it seeks to become the first grid operator with markets in both the Western and Eastern Interconnections. (See FERC Issues Deficiency Letter for SPP’s RTO West Tariff.)

Summer Ops Report

Despite summer weather that extended into October, SPP’s Bruce Rew, senior vice president of operations, said demand was high but did not reach record levels. Demand peaked at 54.39 GW in July, short of 2023’s record peak of 56.18 GW.

SPP registered 18 days with loads over 50 GW, one less than 2023 but the third straight year with double-figure 50-GW days. There were only 11 50-GW days total in 2019-2021.

The RTO issued 24 resource alerts or conservative operations calls this year, down from 40 the year before. It did issue a Level 1 energy emergency alert for two and a half hours on Aug. 26, when elevated temperatures and low wind generation resulted in high net load obligations that reached August 2023 levels. Forced outages approached 9 GW, near all-time highs. (See SPP Issues EEA 1 as Heat Scorches Midwest.)

RSC to Engage on Order 1920

The Regional State Committee agreed during its Oct. 28 meeting to collaborate on a cost-allocation process as part of FERC Order 1920’s requirement for a six-month engagement period with relevant state entities or commissions.

The order requires transmission providers to use a 20-year horizon in planning their long-term regional needs.

SPP’s engagement period began Oct. 28 and will end May 5, when the RSC meets in Omaha, Neb. The grid operator has to make a compliance filing next August.

“The six-month engagement period … is requiring that we offer to provide a forum for negotiation of a cost-allocation methodology and/or the state agreement process,” SPP attorney Tessie Kentner said. “The order does specify that if there is an existing mechanism in place, such as the RSC, that can also be used.”

Incoming RSC President Pat O’Connell, New Mexico Public Regulation Commission | © RTO Insider LLC 

Outgoing RSC President John Tuma, a member of the Minnesota Public Utilities Commission, said SPP’s willingness to work with the states is why Minnesota joined the committee.

“You have created a culture within SPP [in which] states are equal partners in this effort and working together to accomplish good things within the RTO structure,” Tuma told SPP CEO Barbara Sugg. “Minnesota values that. We saw the value of RTOs to reduce the cost of energy and providing stable regional grid for us, and so that’s why we joined.”

The RSC also elected its officers for 2025:

    • President: Pat O’Connell, New Mexico Public Regulation Commission
    • Vice president: Chuck Hutchison, Nebraska Power Review Board
    • Secretary/treasurer: Kim David, Oklahoma Corporation Commission

“I’ve been involved in RSC for a couple years. What I’ve found is it’s always an opportunity for improvement and there’s always a new challenge, or new challenges, every year,” O’Connell said. “I’m looking forward to the challenge. Thanks to all for the trust in me and the situation we’re in now, because it looks to be a very easy job.”

Annual Membership Elections

During SPP’s annual meeting of members, the membership re-elected board Chair John Cupparo and independent Directors Susan Certoma and Ben Trowbridge to three-year board terms that begin in January.

Certoma will be serving her third term, and Cupparo and Trowbridge their second.

The membership also elected eight utility representatives to three-year terms on the 23-person Members Committee, where they will serve as proxies for their sectors:

    • Investor-owned utility sector: Tim Wilson (Liberty Utilities) and Denise Buffington (Evergy)
    • Cooperative sector: Zac Perkins (Tri-County Electric Cooperative) and Mike Wise (Golden Spread Electric Cooperative)
    • State agency sector: Robert Pick (Nebraska Public Power District)
    • Independent power producer/marketer sector: Kevin Smith (Tenaska Power Services) and Brett White (Pine Gate Renewables)
    • Public interest/alternative power sector: Christy Walsh (Natural Resources Defense Council)

Most of those elected are incumbents. Pick and Buffington are new, but Buffington is serving the remainder of former co-worker Kayla Messamore’s term before beginning her own Jan. 1. White is filling the remainder of former member Rob Janssen’s term, which ends after 2025.

The membership also approved a bylaw change brought forward by the Corporate Governance Committee that will revise the selection of Members Committee representatives. With FERC’s approval, sector members will be able to nominate committee representatives, who will then be submitted to the CGC for nomination to the membership.

The CGC said that sectors selecting their representatives on the committee would best represent the interests of each sector and would encourage greater collaboration and engagement between the sectors.

More Time to Cure RAR Obligations

The board approved a revision request (RR632), previously endorsed by the RSC and Markets and Operations Policy Committee, that gives load-responsible entities several more weeks to address deficiencies in meeting their resource adequacy requirement.

LREs would have from March 15 to May 15 (an additional 30 days) to cure summer season deficiencies and from Sept. 15 to Nov. 15 (15 extra days) to resolve winter season deficiencies.

The board’s consent agenda included SPP’s annual violation relaxation limit analysis; converting the Reliability Compliance Advisory Group to a user forum, removing the formal requirements of a chair and recorded minutes; member nominations to the Finance, Strategic Planning and Human Resources committees; and revising the SPC to mirror the sector-based composition of the Members Committee.

It also included another RR (RR649) that aims to add value to the network resource interconnection service (NRIS) product by creating an expedited process for designating new network and designated resources outside of the aggregate transmission service study process. It also revises the generator interconnection study process for new NRIS requests, defines deliverability areas and allows existing resources that meet eligibility requirements to use the expedited process.

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PJM MRC Briefs: Oct. 30, 2024

Stakeholders Endorse Issue Charges on ELCC

VALLEY FORGE, Pa. — The PJM Markets and Reliability Committee on Oct. 30 endorsed two issue charges sponsored by LS Power addressing the transparency and functionality of PJM’s marginal effective load-carrying capability (ELCC) accreditation methodology. 

Both were approved by acclamation. (See “LS Power Issue Charges on Accreditation Transparency, Unit-specific Performance,” PJM MRC Briefs: Sept. 25, 2024.) 

LS Power’s Tom Hoatson outlined several design changes that could be made to the methodology, including reflecting higher potential output in the winter when awarding capacity interconnection rights (CIRs), increasing granularity to allow unit-specific accreditation and recognizing improvements made to generators that may increase their performance. 

Hoatson said that because the current approach determines a resource’s accreditation by looking at how it performed during emergency conditions, if a generation owner makes improvements to a unit that underperformed during a performance assessment interval, it could be years until its accreditation could be updated, after another emergency occurs. 

“You’re not able to improve your accreditation unless you have another Winter Storm Elliott event,” Hoatson said, referring to the December 2022 winter storm. 

There is also an incongruence between the risk modeling approach PJM implemented following the Critical Issue Fast Path process last year, which concentrated risk in the winter, and the use of summer ratings to determine the expected output for some generators, Hoatson said. While the issue charge is not seeking a sub-annual market design, he said there is potential to better align risk modeling and accreditation. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, said there are circumstances beyond a generation owner’s control that result in a resource being labeled as underperforming and there should be a mechanism to allow for steps to be taken to improve accreditation following an event. 

“This is a must-have for many of us, and I think this will help PJM retain a lot of resources in the future,” he said. 

The issue charge aims to file a proposal with FERC in the first quarter of 2025 to be implemented to whichever auction may be held in December of that year, Hoatson said, noting that PJM has requested a delay of the 2026/27 Base Residual Auction (BRA) and several to follow. 

PJM’s Adam Keech said that for any changes to be implementable for an auction conducted in December 2025, a filing would need to be submitted in March or April. While that timeline is doable, he said it’s important that stakeholders keep the tight turnaround in mind. 

“There’s not much time to get changes in for that auction; we are happy to move through this in an expedited fashion,” he said. 

The second issue charge seeks to add transparency to the ELCC process by encouraging more data sharing with generation owners, publishing assumptions underlying class ratings and establishing a date certain for the posting of planning parameters associated with ELCC assumptions. It also envisions a model that stakeholders could use to estimate accreditation of resources they own or representative stand-ins, as well as the ability to modify assumptions to create accreditation sensitivities. 

“Given the large adjustments recently announced to near-term load growth expectations and continued retirement declarations, it has become increasingly important to determine whether and how the accreditation approach as currently implemented will incent needed investment in new and existing resources to maintain resource adequacy,” the issue charge states. 

Vote on Issue Charge to Establish SATA Rules Deferred

Stakeholders deferred action on an issue charge brought by PJM to explore rules to govern battery storage as a transmission asset (SATA) after several argued that members may be inundated with other issues over the coming months. (See “PJM Proposes Reopening Discussion of Storage as a Transmission Asset,” PJM MRC Briefs: Sept. 25, 2024.) 

The motion made by Adrien Ford, Constellation Energy director of wholesale market development, delays action on the issue charge any earlier than February and requires completion of education on the subject at the Operating Committee as well. Ford said stakeholders are being asked to consider numerous issue charges at once and it’s important that the issue charge is written correctly to avoid having to go back to the drawing board, which requires education before moving forward. 

Delaying action was broached by Erik Heinle of Vistra, who noted that stakeholders are also juggling PJM’s Reliability Resource Initiative — which would create a special application window for high-capacity factor resources to enter the second transitional interconnection queue — and a possible Federal Power Act Section 205 filing to revise aspects of the capacity market. 

“When I look around at the most burning issues right now, we’re at a place where we’re trying to put the fires out … and I don’t know that this fits in, so I’m wondering if it makes sense to push this back six months,” he said. 

PJM Director of Stakeholder Affairs Dave Anders said the issue charge sought to delegate the work to the OC in an effort to avoid adding to the workload of other committees already working on other major topics. Heinle responded that members tend to have the same staff working on issues across PJM’s working groups, and, regardless of the venue, another issue charge would add to their responsibilities. 

The RTO also opted to avoid discussion of dual use for storage assets — allowing them to simultaneously act as both transmission and market resources — because of the extensive stakeholder engagement that may entail. 

“Dealing with that dual-use aspect will probably be more time consuming, and we would like to move forward with the operational aspect of it,” Anders said. 

Independent Market Monitor Joe Bowring stated that “there is no logical difference between storage as a transmission asset and a generating unit as a transmission asset. Storage is a competitive market resource in PJM. The MMU opposes the inclusion of competitive market resources in transmission owner rate base because it creates a slippery slope towards rate base rate of return regulation which some are already promoting more broadly.” 

Gregory Poulos, executive director of the Consumer Advocates of the PJM States, said advocates broadly support expanding implementation of storage, and while there are some who are frustrated that the issue charge precluded dual use, they support it. He said some advocates may seek further changes to the rules for market-oriented storage resources through the Public Interest and Environmental Organization User Group. 

Calpine’s David “Scarp” Scarpignato said he is concerned about the prospect of creating a class of regulated transmission assets that could be dispatched to address transmission constraints and the impact that could have on PJM’s markets. He questioned how it could be determined which type of resource would be dispatched under various circumstances. 

“You can’t have somewhat regulated resources being paid for and then expect competitive resources to jump in or participate,” he said. 

CIR Transfer Proposal Discussed

The MRC discussed a proposal to create an expedited process for studying resource interconnection requests that would be using CIRs from deactivating generators.  

A page turn of draft tariff language is scheduled to be conducted during a special session of the MRC on Nov. 14. (See PJM Stakeholders Endorse Coalition Proposal on CIR Transfers.) 

The package is the continuation of the stakeholder coalition endorsed by the Planning Committee on Oct. 8, which won out over proposals from PJM and the Monitor. 

The defining feature relative to the PJM approach is permitting any resource type to receive CIRs and take advantage of the expedited process; the RTO would have categorically excluded storage resources and applied a material adverse impact standard, which opponents argued would effectively limit it to resources of the same fuel type. The process would be limited to projects sited at the same substation and at same voltage as the retiring unit. 

Donnie Bielak, PJM director of interconnection planning, said the RTO’s primary concerns with the coalition package were addressed by the inclusion of a wider set of studies that would be conducted on the impacts a project may have on the grid. Projects’ significant network upgrades would be bounced to the standard interconnection queue, while those with minor upgrades or none at all would be permitted to proceed in the parallel queue. 

The studies would be conducted on the latest phase 2 or 3 model in the wider queue, which Bielak said would result in minimal disruption to the processing timeline for other projects. 

Bowring said allowing bilateral trading of CIRs would create market power for retiring resource owners and could slow resource replacement by allowing those rights to be held for a year before they are transferred. He added that there would be no consideration of the reliability value of the replacement resource nor a requirement that it offer into the capacity market. The Monitor’s proposal would have allowed resources to move to the front of the queue if they resolved a reliability issue and committed to a specific in-service date and being a capacity resource. 

The Monitor’s proposal would have created a PJM-administered process where generation owners could propose new projects to mitigate any transmission violations prompted by a resource deactivation. Any CIRs not transferred through that process would be made available to others in the interconnection queue. 

Elevate Renewables’ Tonja Wicks said this would not be a process where generation owners are handing CIRs over to the highest bidders. Instead, they would be intending to replace their resources with new units at the same location to bring new assets online as quickly as possible. 

PJM Revives Proposal to Sunset Clean Attribute Procurement STF

Clean Attribute Procurement Senior Task Force (CAPSTF) facilitator Scott Baker, PJM business solutions engineer, presented a proposal to sunset the group as states gravitate toward a clean attribute trading program outside of FERC jurisdiction. 

PJM had broached terminating the group during the MRC’s October 2023 meeting, stating that the task force had run its course when its three proposals were rejected without a clear path forward. PJM dropped its recommendation to sunset at the next meeting, and the committee voted against a motion to close the task force. (See “Vote to Close Clean Attribute Group Fails,” PJM MRC/MC Briefs: Nov. 15, 2023.) 

The task force was formed in April 2022 following MRC approval of an issue charge to consider changes to PJM market design to facilitate the creation of a regional, voluntary market for trading clean resource attributes. The discussions yielded three packages, all of which failed to receive majority support in a poll conducted in May 2023. Following that poll, several states formed the Forward Energy Attribute Market (FEAM) Working Group to discuss possible market design and jurisdictional issues. Though the working group was not affiliated with PJM or the Organization of PJM States Inc. (OPSI), its meeting documents can be found on the latter’s website. 

According to a legal and jurisdictional analysis consensus report presented in May 2024, both state-defined renewable energy credits and clean energy attribute credits could be sourced from any qualifying resource and traded among voluntary buyers, such as companies and municipalities with clean energy targets. 

The report states that the credits would not be bundled with the sale of energy and therefore would not fall under FERC’s jurisdiction. It would also not require that states recognize each other’s definitions for qualifying credits, nor would it transfer one state’s authority to another — thereby not requiring congressional approval to establish. Instead, it might take the form of a designated contracts market subject to the U.S. Commodity Futures Trading Commission. 

1st Read on 3rd Phase of Hybrid Resource Rules

PJM’s Maria Belenky presented a package of governing document revisions to expand the RTO’s rules for hybrid resources to include non-inverter-based generation paired with storage.  

The Market Implementation Committee endorsed the revisions Oct. 9. (See “Third Phase of Market Rules for Hybrid Resources Endorsed,” PJM MIC Briefs: Oct. 9, 2024.) 

The hybrid rules would not be applicable to combinations of non-inverter and intermittent generation units, which would be classified as co-located resources. Belenky said PJM is not foreclosing a future pathway for an additional stakeholder discussion on creating a hybrid model for such resources. The rules for non-inverter-based hybrid participation in the energy and ancillary services markets would be based on the Energy Storage Resource Participation Model detailed in Manual 11. 

The revisions would also specify that a hybrid with any component that is subject to the requirement that resources offer into the capacity market would also be subject to the must-offer rule. Hybrids with no component subject to the rule would not be mandated to participate in the market. 

They would also make clarifications to the existing hybrid rules and align language across the governing documents and manuals. That includes defining how generation owners may determine whether the storage component of a hybrid would be offered as a closed loop, incapable of charging from the grid, or an open loop. Belenky said that if the battery is physically or contractually able to charge from the grid, it must be offered as open loop, but there may be circumstances in which the resource owner may wish to operationally limit it to closed-loop usage. 

The revisions would allow generation owners to change loop classification according to the existing technology change rules. A capacity resource is permitted to change its ELCC class once every five years with a request submitted by Aug. 1 of the year prior to the relevant BRA. Energy-only resources can make such a change every year with a request made by May 30 of the previous calendar year. 

Other MRC Business

PJM’s Michele Greening presented a first read on tariff and Reliability Assurance Agreement revisions drafted by the Governing Document Enhancement and Clarification Subcommittee. The changes include removing sunset terms and obsolete references, correcting drafting errors and clarifying instructions. 

PJM presented revisions to manuals 3 and 10 drafted through the documents’ periodic review. The changes to Manual 3: Transmission Operations would update links and references, clarify the process for revising timely transmission outages, and reflect existing practices on facility ratings. The Manual 10: Prescheduling Operations revisions would clarify how outages for inverter-based resources are reported in eDART, specify that work on forced outages must be completed before planned outages can start and correct an exhibit showing the time the day-ahead market closes. 

PJM’s Suzanne Coyne gave a first read on revisions to Manual 28: Operating Agreement Accounting to expand the lost opportunity cost (LOC) formula to hybrid, storage and solar resources. The formula currently only applies to wind resources. 

The committee endorsed tariff revisions to make PJM’s creditworthiness review of bilateral capacity transactions more proactive. The revisions would require that auction-specific and locational unforced capacity transactions be submitted to PJM in advance for credit review and advance approval. PJM would be expected to approve transactions submitted prior by 1 p.m. by the end of the next business day; submissions made after 1 p.m. would be complete within two days. The credit risk of all parties to the transaction and its potential market impact would be considered in the review. The proposal was added to the Members Committee’s consent agenda by acclamation following the MRC meeting.

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NCUC Approves Latest Duke ‘Carbon Plan’ to Expand Renewable, Nuclear and Gas Generation

The North Carolina Utilities Commission issued an order Nov. 1 approving Duke Energy’s consolidated Carbon Plan and Integrated Resource Plan (CPIRP), which is meant to meet state-mandated carbon emission cuts and improve system reliability.

The plan was the first biennial CPIRP since NCUC approved the initial one at the end of 2022. Determining the least-cost path to cutting carbon emissions while maintaining system reliability is a complex and iterative process, the regulator said.

NCUC has directed Duke to pursue every opportunity, including tax incentives and federal funding, to cut costs for consumers. Duke has delivered electricity at rates below the national average for decades, and the regulator said it would work to ensure that record is maintained.

The order waived the requirement to model a 70% carbon cut by 2030, agreeing to extend that to 2032 and telling Duke to pursue 70% carbon cuts by the earliest date possible.

The order approves a settlement between Duke and the commission’s Public Staff, which is the state’s consumer advocate. The settlement also was agreed to by Walmart and the Carolinas Clean Energy Business Association.

“We believe this is a constructive outcome that allows us to deploy increasingly clean energy resources at a pace that protects affordability and reliability for our customers,” Duke said in a statement on the CPIRP. “The order confirms the importance of a diverse, ‘all of the above’ approach that is essential for long-term resource planning and helps us meet the energy needs of our region’s growing economy.”

The CPIRP requires Duke to retire its remaining coal plants, which total more than 8,000 MW, by 2036.

Duke will conduct two competitive solar procurements in the next two years, targeting 3,460 MW of new solar generation that can be placed into service by 2031. It also will procure 1,100 MW of battery storage, which includes 475 MW of standalone storage and 625 MW paired with solar, to come online by 2031.

The order calls for Duke to procure 1,200 MW of onshore wind to come online by 2033, including at least 300 MW targeted for commercial operation by 2031.

NCUC approved new natural gas capacity as well, with 900 MW of combustion turbines to be developed by 2030 and 2,720 MW of combined cycle capacity coming online by 2031.

Duke will try to build 1,834 MW of pumped storage hydropower at the Bad Creek Hydroelectric station in South Carolina, which would be placed into service by 2034.

The order authorized early development of 300 MW of advanced nuclear generation to go into service by 2034 and an additional 300 MW for the next year. Duke also was authorized to work on extending its operating licenses for its existing nuclear plants.

For offshore wind, the CPIRP authorizes Duke to start gathering information regarding the development of up to 2,400 MW off the North Carolina coast to be in commercial operation by 2035.

The order also requires Duke to continue planning for a 1% load reduction through demand-side management and energy efficiency. It calls on Duke to work with large customers to manage load for the benefit of all customers.

Commissioner Jeffrey Hughes filed a concurrence saying that while the order will lead to benefits, the NCUC could have spent more time analyzing the potential costs associated with climate change.

“I would have liked to see more acknowledgement that producing carbon emissions, whether directly through the combustion of gas or coal or indirectly through the production and delivery of those fuels, carries a significant economic cost in terms of climate change,” Hughes said.

The order was criticized by those who want the state and Duke to move faster to cut emissions. The nonprofit Ceres, which encourages investors to address climate change, welcomed the required clean energy procurements but objected to the timeframe.

“Leading businesses across North Carolina have supported the state’s plan to reduce power sector emissions by 70% by 2030, both to reduce their own exposure to climate risk and to experience the economic benefits of clean energy investment,” said Ceres Director of State Policy Mel Mackin. “This decision not only delays that goal, but it also sets a worrying precedent.”