Search
January 27, 2025

Posted on

Generation Developers Ask for Scoring System on MISO Queue Fast Track

Groups of generation owners and developers have asked MISO to adopt a queue fast lane only as a last resort and employ a more limited process that involves scoring criteria to gain entry.

MISO intends to open an express lane in its interconnection queue beginning in June through the end of 2028 for state-designated generation projects that meet resource adequacy targets. The bypass would be meant for projects that can reach commercial operation in three to five years. (See MISO Tells Board RA Fast Lane in Interconnection Queue is a Must and MISO Outlines Plan on Fast-track Queue for Resource Adequacy.)

However, the Coalition of Midwest Power Producers (COMPP) said MISO should establish a screening process for the fast lane based on project readiness and limit the process to just two accelerated studies — one in 2025 and one in 2026. The two studies should be open to all interconnection customers, independent power producers and load-serving entities alike, COMPP said.

Speaking at a Jan. 22 Planning Advisory Committee meeting, COMPP representative Travis Stewart said MISO’s expedited process as proposed creates the possibility of discriminatory treatment in the interconnection queue. This is especially a concern, he said, because designated resource adequacy projects might get first dibs on some of the billions of dollars in freshly constructed transmission capacity MISO has approved in recent years.

Stewart suggested MISO introduce a scoring system to permit projects in the express lane to make sure it’s accepting “commercially mature” projects that meet resource adequacy needs. He said project proposals could earn points based on developers’ ability to show that projects will serve resource adequacy needs, the completeness of an engineering design and equipment procurement, and that projects have been selected through either regulators or load-serving entities’ competitive solicitation. He said the burden to show project need and readiness would be on developers, with MISO to simply “trust and then verify” information from developers and regulators.

Stewart said COMPP’s idea, which he dubbed the Alternative Resource Connection Queue, could accept 50 of the highest-scoring projects apiece in 2025 and 2026 to proceed with faster studies aimed at interconnection agreements within 90 days.

“COMPP is concerned that an unchecked, uncapped [express] queue that can continue in perpetuity will likely mimic the ‘lane expansion’ phenomena in which creating new highway lanes does not improve the flow of traffic but only creates more lanes with more traffic,” Stewart said.

Some stakeholders said that asking MISO to institute more evaluation and scoring criteria will inherently slow down and convolute a queue lane designed to be faster.

“We’d rather have some small hurdles set up at the beginning to demonstrate commercial maturity … than have MISO dedicate their engineering expertise to study a project that ultimately doesn’t get built,” Stewart said, adding that “two weeks of evaluation upfront is better than four months” of ultimately wasted analysis.

NextEra Energy’s Erin Murphy, representing a group of MISO generation developers, said MISO’s proposal raises fundamental discrimination and undue preference concerns. She agreed with Stewart that a fast lane should be open to independent power producers and load-serving entities alike.

“We are concerned that the most constructable projects and the ones most able to address RA concerns won’t get online under this process,” Murphy said.

Murphy said while a limited fast track might ultimately prove necessary, MISO should focus first on improving operations of the existing queue to reduce the backlog. She said MISO should increase staffing and allow time for its recently approved queue regulations with FERC to take hold before it establishes specialized processing.

“We’re of the firm belief that the volume currently in the queue is more than enough to meet projected resource adequacy needs,” Murphy said. She argued that MISO first should take stock of projects already in the queue to ascertain which can meet the footprint’s resource adequacy needs. She implied MISO is establishing a fast lane while disregarding viable projects in the regular queue that already have been vetted.

“There’s a heck of a lot of value in the queue that’s locked up,” Murphy argued.

Murphy said if an imminent resource adequacy gap persists after that, any express lane should come equipped with a scoring system “so the best projects come online in a timely manner.” She also said a fast lane option shouldn’t “erode” the value of the existing queue.

But WEC Energy Group’s Chris Plante said identifying resource adequacy needs is a subjective exercise today.

“It’s not as simple as meeting a reserve margin. It used to be that simple,” Plante said. He said today’s variable requirements in seasons, the sloped demand curve now in place in MISO capacity auctions and more volatile accreditation values year-over-year complicate the picture.

“There’s a tremendous amount of uncertainty in determining resource adequacy needs,” Plante said.

Murphy agreed and suggested resource adequacy needs could begin with states articulating them and then MISO validating them.

MISO’s Andy Witmeier said MISO is delaying its FERC filing into mid-March to consider stakeholders’ suggestions. He said MISO would return to the February Planning Advisory Committee to present a final proposal.

However, Witmeier said the point of the fast track is to get projects online quickly as load grows. He said MISO’s new queue regulations approved in January 2024 — which include higher fees, automatic withdrawal penalty costs and stricter evidence of land use — will take a few years to bear results.

“We’re facing a new phenomenon with spot loads,” Witmeier explained.

Witmeier confirmed that projects that elect to drop out of the regular queue to join the fast-tracked queue will face automatic withdrawal penalties.

MISO also plans to collect higher fees from fast-lane developers than in the regular queue. It will start with a $100,000 nonrefundable upfront fee and then a milestone payment of $24,000/MW. Customers in the regular queue pay $8,000/MW.

Clean Grid Alliance’s David Sapper argued that MISO’s proposal still appears to “violate” FERC’s mandate on open access and nondiscriminatory treatment.

Minnesota Public Utilities Commissioner Joe Sullivan said he heard stakeholders offer fair recommendations to MISO.

“I think we have to find a way to treat the existing queue reasonably and fairly,” Sullivan said.

Sustainable FERC Project’s Natalie McIntire said it seemed MISO wasn’t requiring enough proof that projects are ready to embark on construction. She said MISO might consider requiring engineering designs, fuel contracts if applicable and their permitting progress. McIntire said there’s “strong stakeholder support” to ensure projects will be able to meet demand in the timeframe MISO needs them.

MISO so far requires details like synchronization and commercial operation dates, interconnection facilities finish dates, generator output, manufacturer and model numbers, fuel type and facility and transformer data.

Posted on

NYISO Presents Preliminary FERC Order 1920 Plan to Stakeholders

NYISO on Jan. 21 presented stakeholders with its preliminary proposal for complying with FERC Order 1920, giving a first glimpse into how the ISO may conduct a long-term transmission planning process.

The ISO would repurpose elements of its current Economic Planning and Public Policy planning processes while retaining reliability studies like the Short-Term Assessment of Reliability and Reliability Needs Assessment as separate processes. The System & Resource Outlook would serve as the “core assessment and analysis element” of the new process.

“It’s a tough balance,” Yachi Lin, director of system planning for NYISO, told the Transmission Planning Advisory Subcommittee. “FERC does give us options on how to comply with Order 1920. We either have a multi-value [process], [with] everything going into one batch, or we decide how to repurpose our current processes, or we develop a new one.”

Lin said adding a fourth process specifically for Order 1920 would be overwhelming.

“That’s why we landed here,” Lin said. “Let’s repurpose, leverage, our existing success and experience in economic and public policy planning processes.”

NYISO would also adapt its current solution solicitation, evaluation and selection process into the new long-term process. This would incorporate the seven categories of benefits that FERC specified in the order.

Order 1920 also requires a 20-year horizon for transmission planning with cost allocation for projects that ensures that only customers who receive benefits pay for the projects. The order mandates that new grid enhancing technologies and previously passed-over projects be considered.

With Order 1920-A, FERC gave state governments more of a say in the new long-term processes, granting “relevant state agencies” the opportunity to propose alternative cost-allocation methods for long-term regional transmission facilities. (See FERC Order 1920-A Wins Approval with Accommodations to States.)

Several stakeholders asked about why NYISO had only included the Department of Public Service and Long Island Power Authority as “relevant state entities.”

“We looked at this issue in connection with a meeting around cost allocation options,” said Liz Grisaru, senior adviser for policy at the DPS. “And it appears to us anyway that a ‘relevant state entity’ is either a state permitting authority or a state entity with the authority to set rates.”

One stakeholder pointed out that New York Power Authority sets rates for its communities “all the time,” and it was not clear why it was excluded from being a relevant state entity for the purposes of Order 1920. Another stakeholder chimed in that which state entities qualified should be better clarified before “we get too far down the road.”

Challenges

The commission required that transmission providers conduct their long-term planning processes every three years. The new process requires NYISO to incorporate more factors, develop more scenarios and include more evaluation metrics than those in the Outlook and Public Policy Transmission Process combined, Lin said.

If the Public Policy and Outlook processes were simply combined without expanding the scope mandated by Order 1920, it would take about four years of NYISO-only work, she said. “We’ve got to think of ways, creative ways, to try to squeeze the time into three years,” she said.

In addition, the New York Public Service Commission will still play a role in the new process. She noted that the involvement of the PSC would add processing time, particularly with the notice and timing rules of the State Administrative Procedure Act.

Lin said that some time could be saved by soliciting data from stakeholders and relevant state entities that might affect long-term transmission needs. In effect, this would replace the biennial Public Policy Transmission Need solicitation.

Chris Casey of the Natural Resources Defense Council said that he was worried about the separation of the reliability processes and the new planning process. He said that in the past, the reliability planning assumptions had typically been conservative.

“I guess what I’m worried about is having a separate reliability process identifying a longer-term reliability need and potentially acting on it through that process without understanding if we should be expanding what the solution might be,” Casey said.

Lin replied that the objectives of the reliability planning process and the new long-term process were different. Reliability planning is about making sure that there’s enough energy and capacity. She said that short-term reliability solutions should be used as inputs into the long-term situation.

“There are opportunities to make sure that we link them up together,” Lin said. “I do not envision that we will be in a vacuum, only addressing long-term reliability needs without understanding [short-term] reliability.”

Lin asked stakeholders and state entities for feedback on the preliminary proposal. NYISO is aiming to submit its compliance filing on regional planning requirements by June 12 and another filing on interregional requirements by Aug. 12.

Posted on

MISO IMM Warns of Operational Difficulties with Growing Solar Fleet

CARMEL, Ind. — MISO’s Independent Market Monitor said ramping needs north of 10 GW are becoming increasingly common and MISO should expect challenges ahead as its solar fleet expands. 

MISO IMM Carrie Milton said in analyzing winter operations data so far, MISO’s typical wintertime dual-peaking load pattern in the morning and evening is occurring when its growing solar fleet is unavailable. She said the disparity has become more pronounced as the number of solar panels in the footprint has more than doubled.  

MISO set an all-time solar record of 8.272 GW on Jan. 13, where panels accounted for about 10% of total generation. By comparison, January 2024’s solar peak was almost 3.3 GW.    

On that day, Milton said the RTO had a top 17-GW ramping need, with a 9-GW jump occurring in just one hour as not only solar, but wind generation dropped off.  

“The good news is MISO managed it very well. You probably didn’t even notice it,” Milton said at the Jan. 16 Market Subcommittee meeting. She added that routine pricing that day belied the challenges in the operating room.  

Milton said such challenges will become a more common feature for MISO control room operators. RTO leadership has said its solar capacity will grow to 12 GW before March. (See MISO Estimates Solar Fleet will be 12 GW by Winter’s End.)  

“We continue to set new records with solar,” MISO’s John Harmon acknowledged at the Jan. 23 Reliability Subcommittee.  

Load Shed Drills Announced

MISO signaled it expects a more fraught operating environment by announcing it will conduct tabletop load shed exercises over 2025, hoping to bring in not only load-serving entities, but also regulators and other stakeholders.  

Speaking at a Jan. 23 Reliability Subcommittee meeting, MISO South Manager of Reliability Coordination Jeff Sundvick said MISO’s “ever-evolving energy landscape” and “ever-changing weather” is “putting unprecedented stress on our grid.” He said MISO would mimic seasonal load shed and extended system loss scenarios in the exercises.  

During MISO’s Board Week in December, executives confirmed they would pursue large-scale load shedding drills among its membership.  

Sundvick said MISO doesn’t know some of its members’ “specific capabilities for demand reduction.” He said MISO hopes to standardize some communication through the drills and “simulate high-pressure scenarios.” When it issues load shed instructions, it’s up to the RTO’s local balancing authorities and transmission operators to identify specific loads to shed while prioritizing critical infrastructure. 

“We don’t want to learn of bottlenecks in the heat of battle. We want to learn about them beforehand,” Sundvick said.  

MISO Eludes Max Gen Event Thus Far

Recent months have proven little challenge for MISO, which recorded 75-GW average demand and a 95-GW peak in December, a few gigawatts higher than December 2023’s totals. Peak demand wasn’t anywhere near the almost 107 GW peak set in December 2022.  

Prices rose year over year to an average of $31/MWh, up from $25/MWh in December 2023. Natural gas prices inched upward from their stable $2/MMBtu over most of 2024 to $3/MMBtu. 

MISO also weathered a hard freeze stretching into coastal MISO South using just cold weather alerts and conservative operation instructions Jan. 20 through Jan. 22. The storm dumped a record 10 inches of snow in some parts of New Orleans. The RTO also employed a cold weather alert and conservative operations for the South region only to manage a cold front Jan. 6-9. The cold snaps likely produced a winter peak.  

Harmon said despite back-to-back winter storms in January, “everything performed as expected from the MISO perspective.”  

Ahead of the arctic bouts, MISO asked all members to evaluate equipment outage schedules, fuel availability and staffing levels. 

MISO operations went off without a hitch in November, bringing lower prices and a lower peak than last year.  

The footprint averaged a 70-GW average load in November, in line with the previous three years. The month’s 81-GW peak load Nov. 21 was smaller than November 2023’s 89-GW peak.  

Though coal and gas prices were unchanged year-over-year at $2/MMBtu, the month’s average locational marginal price slid to $23/MWh, lower than November 2023’s $28/MWh.  

MISO experienced the lowest generation outages in November in four years, averaging 47 GW daily, a 2-GW reduction over 2023. 

Posted on

NextEra, GE Vernova Move Toward Gas Generation Development

NextEra Energy is collaborating with GE Vernova on development of natural gas-fired power generation and is taking further steps toward restarting an idled nuclear plant. 

NextEra CEO John Ketchum announced the moves Jan. 24 with release of the company’s fourth-quarter and full-year financial results. Both are in response to the anticipated growth in U.S. power demand. 

The Duane Arnold Energy Center in Iowa was shut down after it suffered damage in an August 2020 derecho. After 45 years in operation, it was put in line for decommissioning rather than repairs. 

Nuclear fission has rapidly gained interest for its near-constant output of zero-emissions power, and NextEra has shown rapidly growing interest in restarting Duane Arnold. 

During the second-quarter earnings call in July 2024, Ketchum said the prospect of a restart under the right conditions had been given some thought. During the third-quarter call in October 2024, he said the company was “very interested” in a restart. 

During the fourth-quarter call, he said the company recently asked the Nuclear Regulatory Commission for a licensing change, an important first step on the regulatory path to restore Duane Arnold’s operating license and restart operations as early as the end of 2028. 

But a restart would meet only a fraction of the gigawatts of new generation the nation needs, and new-build nuclear is unlikely to fill that deficit in the next decade, he said. 

“That means we need renewables and storage to meet demand that is here today and, as we move towards the next decade, we can supplement renewables and storage with natural gas-fired generation,” Ketchum said. 

The framework agreement he announced with GE Vernova would create a partnership between a leading developer of power generation and a leading manufacturer of power generation equipment who already have a decadeslong relationship. 

“This agreement has the potential to support multiple gigawatts for data centers, the reshoring of manufacturing and the electrification of industry, as well as serve investor-owned utilities, municipalities, cooperatives and commercial and industrial customers,” Ketchum said. 

And it offers the potential to boost renewables development by pairing them with natural gas generation, he said. 

“Over the next four years, the companies plan to collaborate to identify key locations on the energy grid that would benefit from new generation,” Ketchum said. 

During the call, an analyst asked for the specifics of the partnership.  

Ketchum said NextEra and GE Vernova would target large load customers with an integrated solution of gas-fired generation, renewables and storage that would be co-owned equally by the partners and contracted on a long term to the customer. 

“We could contemplate in the right situation with the right customer potentially a build-own-transfer on gas-fired generation as well, if it was part of a larger transaction that included renewables and other growth opportunities,” he added. 

Another analyst asked about the costs involved in a Duane Arnold restart. 

Ketchum did not want to tip his hand prior to any cost negotiations, but said the storm damage is not severe or complicated — the cooling tower needs to be replaced, and NextEra has experience building cooling towers at its gas-fired plants. 

One of the first questions was about the “elephant in the room” — the Trump administration’s antipathy to renewables.  

Subsidiary NextEra Energy Resources is a leading developer of solar and wind power generation and energy storage. What impact does Ketchum expect from Trump’s executive orders targeting renewable energy and the IRA funding that has spurred growth in the renewable energy sector? 

Ketchum did not offer an exact answer. Instead, he offered reasons why that impact would not be great, and why he thought Trump would temper his initial stance. 

First off, he said, NextEra has only one onshore wind project on federal land and zero offshore wind, so it avoids the worst of the president’s wrath. 

Second, the country needs a lot more electricity quickly, and NextEra can deliver it quickly with wind, solar and storage. 

Finally, NextEra is one of the largest infrastructure developers in the nation; it plans to invest $120 billion over the next four years. 

“And again, 80% of those dollars is going into Republican states. That’s a lot of manufacturing, a lot of job creation, a lot of property taxes, a lot of economic benefits. So those are the messages that we’re trying to make sure we get we get across in Washington around the IRA discussion,” Ketchum said. 

“I remain very optimistic that we’re going to be able to work through any issues that that may come up along the way.” 

Preliminary full-year financials show NextEra Energy had 2024 net income of $6.94 billion on operating revenues of $24.75 billion, or $3.37 per share. 

That compares with $7.31 billion, $28.11 billion and $3.60 for all of 2023. 

NextEra Energy stock closed 5.2% higher in heavy trading Jan. 24, making it the highest-performing component in the S&P 500 on a day when the index closed 0.3% lower. 

Posted on

WRAP Members Align on Key Issues to Prioritize

Members of a key Western Resource Adequacy Program (WRAP) stakeholder group voted Jan. 23 to prioritize three topics of concern as the group continues developing the program aimed at addressing resource adequacy and reliability in the West. 

WRAP’s Program Review Committee (PRC) is “charged with receiving, considering and proposing design changes” to the RA program operated by the Western Power Pool (WPP). The PRC is developing a draft work plan to identify which changes it can develop into concrete proposals. 

During the meeting Jan. 23, the committee decided on three topics to prioritize for development this year, including load forecasting, adding language to clarify what qualifies as firm transmission under WRAP and enhancing the WRAP operations program to make it compatible with both SPP’s Markets+ and CAISO’s Extended Day-Ahead Market (EDAM). 

The prioritized topics have been on most members’ minds, and there appeared to be consensus on their importance, Rebecca Sexton, director of reliability programs at WPP, told RTO Insider. 

“There’s a lot still to do to come up with the final work plan,” Sexton said. “There’s a lot more opportunity for stakeholders to weigh in. But for now, seems like a lot of consensus on the order that they determined today.” 

Rebecca Sexton, director of reliability programs at WPP | © RTO Insider LLC

The PRC hopes to have the work plan endorsed by the WPP Board of Directors by June, but there will be a “rigorous process of review” between now and then, Sexton said. 

“So there’s a lot of opportunity for the … approach to change,” Sexton added. “But I think having not done this before and getting lots of very engaged input, this seems like we’re on a path to create something that people will endorse in a couple of months.” 

The PRC meeting followed WPP board’s approval of revisions to WRAP’s transition plan in September, including by postponing the program’s “binding” phase by one year and reducing penalties for participants who come up short on RA obligations. (See WPP Board Approves WRAP Transition Plan Changes.) 

The changes were made after WRAP participants urged the board to postpone the start of the program’s penalty phase by one year, from summer 2026 to summer 2027, citing “significant headwinds” in securing energy resources in light of supply chain issues, forecasts for faster-than-expected load growth and increasing extreme weather events.  

Though the revisions to the transition plan are part of a separate process from those discussed by the PRC, Sexton said much of the work within WRAP task forces tends to overlap. 

“It’s the way in which we’ll hopefully continue to be responsive to stakeholder needs, whether participant or non-participant, and evolve the program with best practices as resource adequacy practices change,” Sexton said. 

Posted on

PJM in Discussions with Gov. Shapiro on Capacity Price Cap

VALLEY FORGE, Pa. — PJM is in discussions with Pennsylvania Gov. Josh Shapiro to work toward a resolution on his complaint to FERC asking it to lower the price cap of the RTO’s capacity market, the Members Committee heard Jan. 23 (EL25-46). 

The discussions also follow a letter Shapiro wrote to the PJM Board of Members requesting that it intervene to avoid an “unacceptable” $20.4 billion increase in capacity market prices or the commonwealth may “re-evaluate” its relationship with the RTO. (See Shapiro Warns of ‘Reevaluation’ of PJM if Capacity Prices not Addressed.) 

PJM General Counsel Chris O’Hara told the committee that the discussions have included the design of a price cap, as well as the concept of a price floor. He said PJM also has emphasized to the governor that any market changes must consider the need to attract investment in the RTO while also balancing consumer rates. 

“We want to make sure you are all aware of these discussions,” he told stakeholders. 

Responding to questions on whether there is a timeline for PJM to reach a settlement or how the discussions interact with the schedule of the 2026/27 Base Residual Auction, O’Hara said the RTO is moving expeditiously. The auction is scheduled to be conducted in July and in several filings seeking to revise elements of the capacity market, PJM has requested orders by Feb. 21 to ensure it has time to implement the changes. 

“We are aware of the auction schedule, and we are moving with haste, but there is no date certain,” he said. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, questioned if it was appropriate for PJM to be discussing market rules with a nonmember, particularly when the changes could affect all market participants. O’Hara responded that PJM will continue to have discussions with membership as well. 

Shapiro requested the auction’s price cap be reset to 1.5 times the net cost of new entry (CONE); the status quo is the greater of gross CONE or 1.75 times net CONE. On Jan. 21, FERC granted a joint motion that Shapiro and PJM filed asking for a one-week extension on the RTO’s deadline to respond. 

“The requested extension will allow the joint parties to engage in discussions concerning the complaint before any answers are filed,” they said in their motion. 

PJM responded to Shapiro’s letter on Jan. 16, saying it has yet to take a position on the substance of his complaint. 

“We share your concern for consumer cost increases resulting from the region’s supply/demand challenge,” PJM wrote. “We are simultaneously concerned about market changes that could serve to thwart new generation entry. This new entry is needed to preserve system reliability and ultimately reduce costs for consumers. PJM is very willing to have discussions about how these two concerns can simultaneously be addressed.” 

Since Shapiro’s complaint was filed, the governors of Maryland, Delaware, Illinois and New Jersey also have sent letters to PJM and FERC urging action. 

“As one of the original members of PJM, New Jersey has long worked in partnership with PJM to pioneer new and innovative approaches to provide our residents with reliable and affordable power, most recently exemplified with our work together on the State Agreement Approach,” Gov. Phil Murphy said in a Jan. 21 letter to the RTO. “That long partnership has become frayed in recent years as PJM continues to take actions that are incongruent with our energy policy and the best interests of our residents. I am calling on you to help repair that partnership and work with New Jersey and other interested states to resolve this matter.” 

In his own letter, Maryland Gov. Wes Moore argued that a lower price cap is needed to prevent a growing affordability problem from worsening in the next capacity auction. 

“I strongly urge you to make the requested adjustments to help contain costs to Maryland households, as well as households throughout PJM, particularly in light of the fact that the previous suite of changes to risk modeling and capacity accreditation developed under PJM’s Critical Issue Fast Path contributed to the results of the last auction,” he wrote. 

On Jan. 17, Illinois Gov. JB Pritzker and former Delaware Gov. Bethany Hall-Long (whose term ended Jan. 21) joined Murphy and Moore in a letter to FERC arguing that the temporary change would contain auction prices, as barriers to new entry prevent resources from responding to high prices and a large number of rule changes are being considered by the commission. 

“The proposed temporary modification to the price cap ensures that prices do not reach unjust and unreasonable levels despite the structural limitations in today’s marketplace preventing a pronounced market response to elevated prices,” they wrote. “This measure is also warranted given the unusually large number of emergency reforms PJM has proposed for the upcoming 2026/2027 auction, as well as the significant changes implemented in the 2025/2026 auction.” 

Posted on

Weather, Supply Chain Top SERC Risk Rankings

Extreme weather, supply chain constraints and resource uncertainty top the risks facing the SERC Reliability footprint in the next two years, presenters said at a Jan. 23 webinar detailing the regional entity’s latest Regional Risk Report.

SERC publishes the regional risk report every two years to supplement NERC’s Reliability Risk Priorities Report; the ERO’s report is published in odd-numbered years, while SERC’s is released in even-numbered years.

“I can’t really think of anything better for our industry and our [power] grid than this report,” Tim Ponseti, SERC’s vice president of operations, said at the webinar examining the report. “It’s foundational for everything we do here at SERC. It feeds into the NERC risk report, it feeds into our outreach, our priorities, our state programs, our assistance programs — so many things.”

The report identified 10 key risks facing entities in SERC’s footprint. Each risk was nominated by stakeholders via a form on SERC’s website and reviewed by the RE’s Reliability Risk Working Group and Technical Committee to determine whether or not to add it to SERC’s risk registry. Their ranking was determined by subject matter experts evaluating each risk across 15 impact areas.

First on the list were supply chain constraints, which include both the risk of vendors introducing vulnerabilities to products used by grid operators — whether intentionally or not — and of delays to projects from shortages of needed materials.

These conditions can arise from a number of factors, the report found, including overreliance on a limited number of suppliers that can be disrupted by cyberattacks, natural disasters and geopolitical tensions. The report said SERC’s Engineering Committee “has identified significant supply chain risks that threaten the stability of the energy sector” and recommended several mitigation strategies, such as diversification of suppliers, enhanced cybersecurity measures and stronger regulatory compliance programs.

Extreme weather came next, which several presenters considered especially appropriate in light of the extreme cold temperatures and record snowfalls that affected much of the Southeastern U.S. the same week as the webinar. Nancy DeLeon, SERC’s senior reliability engineer for situation awareness, noted that while the cold snap was unusual, extreme weather has long been a known risk for the RE.

“We’re located in a place where we do get a lot of extreme weather — extreme colds, extreme heats, hurricanes tornadoes, a lot of thunderstorms, things like that,” DeLeon said.

The report said extreme weather can “pose significant risks to [grid] reliability” by disrupting fuel supplies and telecommunications, limiting situational awareness and causing forced outages of generation and transmission facilities. Additionally, with the grid increasingly reliant on wind and solar generation and severe weather becoming more frequent, renewable resources are uniquely vulnerable to interruption during major events.

Both top risks were labeled as “monitor” in the report, meaning that mitigation plans and guidance already exist. The third highest risk, resource uncertainty, was marked as “manage,” which means that a mitigation plan needs to be developed and implemented.

The resource uncertainty risk also stems from the accelerating shift from traditional thermal generation to renewable resources and the accompanying rise of natural gas as a supplier of reliability services such as system inertia and ramping. SERC said the change to renewables will require “continued improvements in planning approaches” to understand how the behavior of solar and wind facilities contrasts with traditional generators and account for the difference in system planning.

“Through proactive and strategic planning, and continued collaboration, the sector can sustain the reliability and resilience of the [grid] in the SERC footprint,” the report said. “SERC remains committed to driving innovation and preparedness to meet the future demands of a secure and reliable electric grid.”

Posted on

Data Centers to Drive Calif. Power Demand, Sales

CAISO peak demand will grow from 48.3 GW in 2024 to about 68 GW in 2040, according to a new forecast that attributes much of the increase to data center load.

The figure is part of the California Energy Commission’s annual update to the California Energy Demand forecast. The forecast, which is part of the Integrated Energy Policy Report (IEPR), is considered a cornerstone of the state’s energy planning process.

The commission approved the 2024 update Jan. 21.

At the same meeting, the commission welcomed its newest member: Nancy Skinner, who served in the state Senate from 2016 to 2024. Skinner replaces Commissioner Patty Monahan.

The CEC’s peak demand projections for 2040 are 66.8 GW in what’s known as the planning forecast and 68.5 GW in the local reliability forecast.

That compares to a peak demand recorded in 2023 of 44.53 GW, followed by 48.32 GW in 2024. CAISO’s all-time peak demand was 52,061 MW on Sept. 6, 2022, amid a record-breaking heat wave.

The new projections are substantially higher than those made in 2023, when estimated peak demand in 2040 was around 60 GW.

One difference is that the 2024 forecast “improved [the] characterization of the expected growth of data centers,” the CEC said in its draft IEPR update released in November.

“A significant amount of the peak growth is coming from the additional data center load that we have added this cycle,” Nick Fugate, lead forecaster in the CEC’s Energy Assessments Division, told commissioners.

Data centers typically run around the clock, including during peak hours, and therefore contribute to peak demand, Fugate said.

The CEC updated its forecasts in December after receiving new information from Pacific Gas and Electric about data center trends. The PG&E update indicated substantially more requested data center capacity compared to figures the utility submitted in September. (See CEC Ups Data Center Demand Forecast After PG&E Revisions.)

Sales Forecast

The annual peak demand growth rate in the CEC forecast through 2040 is 2.3% and 2.4% in the planning and local reliability forecasts, respectively.

The growth is even steeper for statewide electricity sales, which see a 3.2% and a 3.3% annual increase through 2040 in the planning and local reliability forecasts, respectively.

Fugate noted that peak load doesn’t grow as quickly as electricity sales in the forecast because much of the EV charging that contributes to electricity sales is expected to take place in off-peak hours.

Electricity sales will increase from about 245 TWh in 2024 to 420 TWh in 2040, under the local reliability forecast. In comparison, the CEC’s 2023 forecast predicted only about 350 TWh of electricity sales in 2040.

The CEC’s planning forecast makes “mid-range” assumptions and is used for system-level planning, such as resource adequacy.

The local reliability forecast may be used for utility distribution system planning or local area reliability studies in CAISO’s transmission planning.

Compared with the planning forecast, it assumes less behind-the-meter solar and storage, less energy efficiency and more electrification, resulting in higher predicted demand. That makes up for some of the uncertainty in forecasting for smaller areas, the CEC said.

Behind-the-meter Solar

Another change to the 2024 energy demand forecast was improved projections of behind-the-meter solar and storage. Historical data was updated based on better interconnection data from several utilities.

The CEC estimated there was 17.2 GW of behind-the-meter solar capacity in California at the end of 2023, including a record-setting 2.5 GW that was interconnected that year.

And behind-the-meter solar capacity factors were updated based on “a large real-world sample,” the CEC report said. Capacity factors are the ratio of electricity actually generated by a system to the system’s maximum capacity.

The new, lower capacity factors used in the 2024 forecast translated to lower estimates of electricity generation compared to the 2023 forecast.

On the energy storage side, the CEC found roughly 1.5 GW of behind-the-meter storage in the state through 2023, and about 84% of that was interconnected in the last five years.

In other changes made in the 2024 forecast, the CEC used the latest information about zero-emission appliance regulations to update building electrification projections. The forecast also accounted for growth in transportation electrification.

Posted on

ERCOT Technical Advisory Committee Briefs: Jan. 22, 2025

Stakeholders Sound off on Market Design Framework 

ERCOT’s Technical Advisory Committee held its first meeting of 2025 on Jan. 22, with the biggest chunk of the meeting devoted to discussing the grid operator’s proposed market design framework. 

The framework dates back to August of 2024, when ERCOT CEO Pablo Vegas presented it to the Board of Directors. It is made up of very broad guidelines to use as the grid operator develops rules and regulations, said Vice President of Commercial Operations Keith Collins. 

“What we see is that while reliability is the organization’s primary objective, cost should always be considered,” Collins said. “So, I think that hopefully will set us up for some of the discussion debate that will happen about what the meaning of this balance is.” 

ERCOT already had gotten comments from six sets of stakeholders on the document, and Collins invited them to reiterate what they wrote at the TAC meeting. 

“Our comments are meant to be very generally supportive of the framework and the intent behind the framework, because it can be helpful to have this sort of tool to help socialize and coordinate thinking about market design changes,” said Ned Bonskowski of Vistra. 

However, Vistra wanted to make sure the policy framework is not resetting all of the work the Texas legislature and Public Utility Commission have put into the markets since the February 2021 winter storm, or even further back, he added. 

The PUC shelved the performance credit mechanism in December, and ERCOT is working on implementing the real-time co-optimization (RTC) of energy and ancillary services, which means stakeholders have to look for some new policies to improve the system. 

“We want to choose among the best tools that we have available to us and use those tools efficiently,” Bonskowski said. “But we also don’t want to, for instance, give up on trying to just because we may not have the exact perfect tool that we would like to have for a situation. We should not let the perfect be the enemy of the good.” 

The Lower Colorado River Authority’s Blake Holt saw the document as providing some clarity to those who are not in the “stakeholder trenches” regularly, but he had questions on how the document would influence policy implementation at ERCOT. 

“How does ERCOT intend to resolve conflicts between competing attributes and timelines?” Holt said. “For example, [the reliability unit commitment] enhances reliability for the hours utilized. However, excessive use of the tool can lead to wear and tear on a unit and worsen reliability in the future, not to mention the out-of-market action leads to flawed and inefficient price formation.” 

One basic issue the document brought up for many is the tension between affordability and reliability, which is a universal concern in the power industry. 

“We recognize there are tradeoffs between the two, and we currently support the stance of conservative operations and understand that operating more reliability or more reliably comes with increased cost,” Holt said. “We believe the best way to support this increased cost is through markets in which these operational reserves are currently valued and reflected in as procurement.” 

Collins agreed the framework could be useful for people who are not always in stakeholder meetings to use as a way to help wade through the information that is produced at them. 

The city of Eastland’s Mark Dreyfus questioned the purpose of the document, noting that the stakeholder process implements the nitty gritty details of policy. While they are complicated, many people are involved, and ERCOT’s board has the grid operator’s entire staff to explain things to them. 

“Consumers, as a market segment, have always supported competitive markets, because we know that the competitive market — as reflected in the law, interpreted through the commission rules and into the protocols — is the best way to provide reliability at lowest cost to consumers,” Dreyfus said. 

The Texas Advanced Energy Business Alliance’s Doug Pietrucha said his group agrees that markets are the best way to ensure the right balance between reliability and affordability, but it wants to make sure that technology neutrality is a key part of market design. 

“The participation in various services should be based on the attributes that different technologies can provide, and the goal of the service shouldn’t be to be designed around the attributes of any one particular technology,” Pietrucha said. 

Mark Bruce, principal at Cratylus Advisors, questioned the value of the document, noting that policy is determined elsewhere. 

“ERCOT doesn’t get to make high-level, aspirational policy determinations and documents like this,” Bruce said. “All this talk about competitiveness, that issue has been settled since Sept. 1, 1999,” referring to the law that restructured Texas’ utility industry. 

Collins disagreed with that assessment, noting that he has worked around the country in other markets where they do not necessarily wait for FERC for directions. 

“You can blaze a path that that can help the commission determine … a reasonable approach to implementing reliability,” Collins said. “It’s one thing to say you want a reliable market. Well, how do you want a reliable market? How do you want competitive markets? And what we’re seeing here are things that help emphasize how you can achieve that.” 

Large Load Interconnection Report

In other business, TAC got an update on the number of large loads lined up to connect to the ERCOT grid. 

A combination of new standalone projects and those co-located with generation, net of a few cancellations, has ramped up the queue by 17,481 MW since TAC’s last meeting in November. With some anticipated rule changes anticipated, interconnect requests for loads energizing more than two years in the future have gone up significantly in the past two months, according to an ERCOT report. 

ERCOT has added 5,229 MW of large loads from 2022 through 2024, and that could grow to more than 80,500 MW by 2030, the report says. Projects representing more than 14,000 MW are interested in connecting to the grid this year, though most of that — and most of the 80 GW for 2030 — is under ERCOT review or has yet to submit enough information for the grid operator to even start a review. 

Votes on Leadership, Transmission, Rule Changes

The meeting opened up with TAC members voting to give Caitlin Smith of Jupiter Power another year as its chair. 

The committee elected a new vice chair, with Martha Henson of Oncor taking that role over after Collin Martin, also of Oncor, stepped down at its last meeting. (See ERCOT Technical Advisory Committee Briefs: Nov. 20, 2024.) 

TAC voted to recommend three transmission projects from Oncor that are big enough to require approval from the board: 

    • The Forney 345/138-kV Switch Rebuild Project, which costs $103.5 million, to address reliability issues in Kaufman County and will not require a certificate of convenience and necessity (CCN).
    • The Wilmer 345/138-kV Switch Project, which costs $158.2 million, to address reliability issues in Dallas, Kaufman and Ellis counties, which will require a CCN.
    • The Venus Switch to Sam Switch 345-kV Line Project, which costs $118.9 million, to address reliability issues in Ellis and Hill counties and will not require a CCN. 

In addition to the three transmission projects, TAC also voted on many rule changes, but the only one that generated debate was NPRR 1250, which is needed for ERCOT to end its renewable portfolio standard implementation practices. Others were put on a combination ballot and were approved unanimously. 

The legislature passed HB 1500 to end the renewable portfolio standard (RPS), which effectively has been moot for more than a decade, as the Texas grid has long had more renewables than was ever required by the standard. ERCOT still will run a voluntary renewable energy credit (REC) trading program but will end the mandatory REC program for RPS compliance. 

Vistra’s Bonskowski abstained from voting for NPRR 1250 because it did not eliminate several compliance provisions, but he noted they’re going to be dealt with in a future rule change. 

Posted on

ISO-NE Details Evaluation Models for Transmission Solicitation

ISO-NE has outlined the transmission and economic models it plans to use to evaluate proposals submitted for the longer-term transmission planning (LTTP) process.

The RTO is developing the first request for proposals (RFP) for the LTTP process, which is intended to address transmission needs identified in long-term planning studies. FERC approved the new process in July. (See FERC Approves New Pathway for New England Transmission Projects.)

At the direction of the New England States Committee on Electricity (NESCOE), the first LTTP solicitation focuses on increasing the transfer capability at two interfaces in Maine and facilitating the interconnection of at least 1,200 MW of onshore wind in the state. (See ISO-NE to Work on State-backed RFP for Northern Maine Transmission.)

To help qualified transmission project sponsors (QTPS) develop their proposals, ISO-NE will publish transmission and economic models, said Dan Schwarting, manager of transmission planning at ISO-NE. The models will use the same basic structure as those used by ISO-NE to evaluate projects but will use generic information for generator performance to protect confidentiality.

The economic models outlined at the Planning Advisory Committee (PAC) meeting Jan. 23 will include a capacity expansion model and a production cost model. The capacity expansion model will determine “the amounts and types of generation needed to adequately serve load over multiple years, given emissions constraints and load growth,” Schwarting said. The production cost model will calculate hourly data on generation dispatch, power flow and production cost.

ISO-NE plans to use its version of the models to calculate benefit-to-cost ratios (BCRs) for proposals. These financial benefit calculations will account for production cost and congestion savings, avoided capital costs, avoided transmission investment, reductions of line losses and reductions of unserved energy.

For a project to be selected in the LTTP, the BCR calculation must show that its benefits outweigh its costs. If multiple projects pass this threshold, ISO-NE is not required to select the proposal with the highest BCR and also will consider factors including project scope, permitting challenges and “constructability,” Schwarting said.

If no projects pass the threshold, FERC has approved a “supplemental process” in which one or more states could opt to cover the costs that exceed the threshold.

In February, ISO-NE plans to provide additional modeling details to the PAC, including an outline of its modeling of “representative onshore wind projects in northern Maine,” and the composite load model the RTO will use for stability simulations.

Schwarting said ISO-NE plans to release a draft RFP to NESCOE and the QTPS to solicit feedback prior to publishing the official RFP in March. He said this limited review process would “strike a balance between feedback and timeliness in issuing the RFP.”

Several people asked ISO-NE to expand the opportunity to provide feedback to all stakeholders. Sheila Keane, director of analysis at NESCOE, also expressed an interest in expanding the draft RFP review process.

“As we think about this being the first time through for everyone … it seems like adding in some transparency on the draft RFP might add some value to the process without adding too much time,” Keane said.

After issuing the RFP, ISO-NE plans to give transmission developers six months to submit proposals, followed by a yearlong period for ISO-NE to evaluate and select a proposal. Under this timeline, ISO-NE would likely select a solution by September 2026.

“If it is possible to accelerate this timeline we certainly will,” Schwarting said.

2024 Economic Study

Also at the PAC meeting, ISO-NE presented the final policy scenario results of its 2024 Economic Study, which is intended to evaluate “economic and environmental impacts of New England regional policies, federal policies and various resource technologies on satisfying future resource needs in the region.”

The preliminary results of the policy scenario, presented in November, found the need to add 58 GW of capacity from a range of zero carbon resources including renewables, energy storage and small modular reactors (SMRs).

The study found that carbon constraints will drive capacity expansion from 2033 to 2039, after which both carbon constraints and load growth will drive resource additions.

Overall, the final results indicate New England will need to add a cumulative capacity of 77,176 MW by 2050. Compared to the preliminary results, the increased need for new capacity reflects a reduced SMR buildout, which increases the amount of capacity required from other resources.

As the region decarbonizes, SMRs could help fill an essential firm power role and limit the need to overbuild intermittent renewables. ISO-NE has deemed hydrogen generation, carbon capture and storage, and geothermal generation — other potential low-carbon dispatchable resources — to be infeasible solutions for the region due to geological constraints.

The model found that, in 2050, “without additional revenue incentives, SMRs only operate at a 21% capacity factor, but they successfully provide emission free dispatchable generation in the winter to reduce overall system emissions,” said Elinor Ross of ISO-NE.

The results also indicate that the cost of additional carbon reductions will increase exponentially as the power system nears full decarbonization in the leadup to 2050.

“Hours of high solar and wind generation are easy to decarbonize at a low cost,” said Ross. “The remaining hours left to be decarbonized require energy storage and SMRs, which are more expensive than wind and solar.”

Sensitivity analyses also highlighted the significant cost benefits of land-based wind, which was “consistently the most cost effective resource in a levelized cost analysis,” Ross said.

Reducing the limitations on onshore wind decreased the overall build costs in the model. In the most extreme sensitivity considered by ISO-NE — which allowed the model to build unlimited land-based wind — the model added more than 44 GW of onshore wind, cutting the overall build costs nearly in half relative to the reference case.

ISO-NE is taking feedback on the policy scenario results and requests for additional sensitivity scenarios through the end of February.