Search
January 30, 2025

Posted on

NYISO Begins Capacity Market Structure Review

NYISO on Jan. 22 laid out the timeline for its Capacity Market Structure Review project, which will take up the better part of 2025. 

Speaking to the Installed Capacity Working Group, Brendan Long, market design specialist for NYISO, said the objectives of the review include identifying current market structures “that will help facilitate New York’s evolving grid consistent with policy goals” and exploring potential alternatives. The ISO will solicit feedback from the group throughout the year with the goal of producing a final report in the fourth quarter. 

Just like the rest of the U.S., demand for electricity is growing exponentially in New York. The review was called for by stakeholders and the ISO last year to determine whether the capacity market provides adequate resources efficiently and effectively. 

According to its schedule, NYISO will propose a priority list of key areas of the market for potential enhancement by the end of the first quarter, propose an initial set of “high-level solutions” in the second quarter and “further analyze and refine” the recommendations in the third. 

In response to stakeholder questions, Long said that considering reactive power compensation was on the table and that the review would include evaluating how the market ensures transmission security. The ISO also will consider long-duration energy storage compensation structures. 

“It’s absolutely something we’ll consider, and we’ll whittle down further as the project progresses,” Long said.  

One stakeholder pointed out the project came about because market participants were frustrated with the capacity market; they asked whether identifying the sources of frustration was a priority for the review. Long said NYISO is “definitely going to keep our ears open” for stakeholder feedback and it will play a major role in the direction of the study. 

“I think that it’s important that part of this project is an articulation of why the current structure is not working,” Chris Casey, of the Natural Resources Defense Council, said in agreement with the previous stakeholder. “I think it’s important to zoom in on that to know how to fix it. It’s more than just collecting the frustrations of the stakeholders. We need to identify and articulate the reasons why this market might not be producing efficient results anymore.” 

NYISO’s structures needed to be harmonized with the state’s programs, he said. “I don’t think we should come out of this with a structure that pretends that certain revenue sources don’t exist or is otherwise blind to state programs because I think that ultimately produces results that are inefficient and costing customers more than they need to pay.” 

Doreen Saia, chair of the Energy and Natural Resources Practice at Greenberg Traurig, echoed Casey’s point, saying any capacity market changes needed to take state policy into consideration. 

Saia also asked the ISO to keep in mind the market structure has been in place for more than a quarter-century and stakeholders would require “adequate meeting time” to discuss potential changes. This comment came after a November and December in which stakeholders had grown frustrated with ISO projects they saw as rushed or incomplete. (See Large Consumers Vent Frustrations with NYISO’s Proposed SCR Changes and Winter of NYISO Stakeholders’ Discontent over ‘Complete’ Projects.) 

Several stakeholders, including Casey, urged the ISO to avoid incrementalism and seriously consider the fundamental structure of the market. They said changes, like new types of resources, might be coming in 10 to 20 years and any new market structures had to be flexible enough to accommodate them. 

“Fundamental changes to the structure, at least looking into them, are in the scope of this project,” Long said. “It might not necessarily be prioritized in our list of key areas, but I wanted to clarify that it will definitely be something we’re open to hearing feedback.” 

Posted on

6th Circuit Rules Against Michigan Local Clearing Requirement

A federal appeals court has brought Michigan’s practice of requiring some amount of locally generated electricity to a standstill, finding that the Michigan Public Service Commission violated the Commerce Clause when designing local clearing requirements.

The 6th U.S. Circuit Court of Appeals decided in a Jan. 16 order that Michigan’s local clearing requirement — which requires load-serving entities and alternative energy suppliers alike in the lower peninsula to procure an increasing percentage of their total capacity from within MISO’s Zone 7 — is discriminatory and “impermissibly interferes with interstate commerce” (23-1280). The appeals court reversed and remanded a district court’s earlier finding that the requirement does not discriminate against interstate commerce.

MISO’s Zone 7 encompasses the lower peninsula, while the upper peninsula and a portion of Wisconsin are in Zone 2. Michigan relies on MISO’s local clearing requirements to establish its own but adds the condition that some capacity comes from in-zone sources.

Energy Michigan, composed of a group of the state’s alternative energy suppliers and the Association of Businesses Advocating Tariff Equity (ABATE), an association of industrial and manufacturing entities that use the alternative suppliers, originally sued the Michigan Public Service Commission for its 2017 order establishing the local clearing requirements (U-18197).

“Can the state of Michigan require someone selling a product in Michigan to procure that product from the state? Or, phrased in the language of the coin’s other side, can Michigan bar in-state retailers from obtaining their merchandise from outside the state? On these issues, negative Commerce Clause jurisprudence is straightforward. Whether the product at issue is milk, or coal-based electricity, the Commerce Clause prohibits such state restrictions unless they clear strict scrutiny’s high bar,” the court said, drawing on past cases.

The court said the Michigan PSC couldn’t make a law that “overtly blocks the flow of interstate commerce at a state’s borders.”

The Michigan PSC argued that it didn’t discriminate because the order’s language doesn’t mention state boundaries, only MISO’s local resource zones. The court called that “not much of a step” because Zone 7 geographically corresponds with Michigan’s lower peninsula.

Michigan regulators also argued that the clearing requirement’s purpose is to promote resource adequacy, not to protect domestic industry. Energy Michigan and ABATE took a different view of the law, arguing that it’s meant to favor utilities in the marketplace and drive out alternative energy suppliers, which are more likely to sell out-of-state electricity. Michigan allows up to 10% of retail electricity sales to be purchased from alternative electric suppliers.

However, the court said the aim of the requirement is irrelevant.

“Even the most benign purpose … cannot save a facially discriminatory law from strict scrutiny,” it said. The court added it judged the percentage requirement the same way it would a requirement dictating 100% of peak demand be procured from Michigan “or even an entire ban on electricity supply derived outside the state’s borders.”

Finally, the Michigan PSC argued that the Federal Power Act authorized it to enact the local requirement, pointing to a section that removes facilities used for electricity generation from federal jurisdiction. The court responded that “it is difficult to see how this provision authorizes, let alone unambiguously so,” Michigan to discriminate against interstate commerce.

Circuit Judge Danny Boggs dissented from the ruling, saying the case deserves some nuance and is “clearly” beyond the scope of the Commerce Clause because of the players involved. He said the district court erred in its conclusion that public utilities and alternative electric suppliers are similarly situated entities simply because they offer the same commodity.

Boggs argued that unlike the state’s utilities, unregulated alternative electric suppliers typically contract with industrial manufacturers and mid-size commercial customers and aren’t under an obligation to serve.

“At bottom, eliminating the local clearing requirement would do nothing to further the Commerce Clause’s ‘fundamental objective of preserving a national market for competition,’ and it would undermine the reliability of the state’s grid. The majority of Michigan’s retail electricity market remains in the hands of the public utilities, who have an unshakable obligation to serve that vital market,” Boggs wrote.

Boggs said MISO’s local resource zones are not only based on state boundaries but also drawn according to results of MISO’s loss of load expectation studies, “the relative strength of transmission interconnections,” the electrical boundaries of local balancing authorities and the seams between RTOs.

“Declining to give full weight to the judgment of state and local regulators on a matter of state and local concern is a fraught exercise, particularly considering the intricate area of energy regulation at play here,” Boggs wrote. “Geographic proximity to generation improves grid reliability, and without the requirement to secure in-state capacity, Michigan would be at risk of falling short of federal reliability standards.”

Posted on

Study Models West Coast OSW Transmission Options

A new report by two national laboratories finds that offshore wind could be generating as much as 33 GW of electricity for the western United States by 2050 and looks at how best to bring that power ashore. 

The “West Coast Offshore Wind Transmission Study” also points out the region will need as much as 400 GW of new capacity by 2050, and that the floating infrastructure needed for the deep water off the West Coast presents engineering challenges. 

Another, more immediate problem is not mentioned in the report: politics. The report was published Jan. 15, just five days before President Trump slapped an executive order of indefinite duration and as-yet indeterminate impact on offshore wind development in U.S. waters. (See Critics Slam Trump’s Freeze on New OSW Leases.) 

Teams of researchers at the Pacific Northwest National Laboratory and National Renewable Energy Laboratory spent two years preparing the study. 

They focused on a 9,265-square-mile region off northern California and southern Oregon where the wind is strongest (22 mph average), the water depth is tenable (4,265 feet maximum) and there is minimal overlap with protected zones, tribal communities and other potential conflicts. 

They studied two transmission models: 

A radial structure, where each wind farm is connected to one point on the coast, would be simpler to build but less versatile in operation, they found. 

A backbone structure, in which wind farms are connected to each other at sea as well as to points of interconnection on land, would carry a higher upfront cost but would allow cheaper energy to be moved more efficiently across regions. 

The researchers found that starting with a radial structure and expanding it into a backbone structure would present the best cost-benefit mix and result in savings that could equal $25 billion in 2024 dollars — mostly because it would allow grid regions to better share lower-cost energy such as hydropower and solar power. 

Lead author Travis Douville, PNNL’s wind systems integration portfolio manager, said such an addition of offshore wind power also would boost resilience in the coastal region, as there are not many generators along the coast. 

“With careful planning and coordination across multiple points in time, we can solve the question of how offshore wind generation and transmission could be developed on the West Coast for maximum benefit,” he said. 

Posted on

Chelan PUD Commits to SPP Markets+ Phase 2 Funding

SPP’s Markets+ notched another in a string of successes Jan. 22 when the Chelan County Public Utility District in Washington said it will pay its $1 million to $2 million share of funding for the market’s Phase 2 implementation stage.

The announcement by the Wenatchee-based publicly owned utility (POU) came just a day after the biggest Markets+ funder, Powerex, committed to joining the market and providing its funding share, estimated to be about $34.8 million. (See Powerex Commits to Funding, Joining SPP’s Markets+.)

Powerex’s move followed FERC’s Jan. 16 approval of the Markets+ tariff, which opens the door for other such moves by backers of the market. (See SPP Markets+ Tariff Wins FERC Approval.)

Chelan spokesperson Rachel Hansen said the PUD’s announcement covered only funding for Phase 2 and did not constitute a commitment to participating in the market.

“Joining the market will be a separate decision,” Hansen told RTO Insider in an email.

In a statement accompanying the announcement, Chelan General Manager Kirk Hudson echoed a point the Bonneville Power Administration has made in defending its intention to contribute its own $25 million share of Markets+ funding before a participation commitment: that the investment is necessary to ensure that Western utilities have a viable alternative to CAISO’s Extended Day-Ahead Market (EDAM).

“It’s in our customer-owners’ interest to ensure that a day-ahead and real-time market option exists that features independent governance, encourages investment in resource adequacy and appropriately values hydropower,” Hudson said.

And like BPA, Hudson referred to the fact that Northwest utilities inevitably will face a need to participate in an organized day-ahead market.

“The success of wholesale power markets is critical to keeping rates low for Chelan PUD’s customer-owners. All around us, we see changes to the region’s electric system that will affect how utilities buy and sell power, including a shift to organized electricity markets,” he said.

Chelan is not a participant in CAISO’s real-time Western Energy Imbalance Market.

According to a spreadsheet posted on SPP’s website Oct. 24, 2024, Chelan would be responsible for funding 0.7% of the estimated $150 million cost for Phase 2, based on the most likely Markets+ footprint scenario. SPP has told RTO Insider that it’s using a funding mechanism similar to that of Phase 1 to calculate each participant’s share of the Phase 2 implementation costs.

As competition between Markets+ and EDAM has ramped up over the past year and a half, Chelan has been solidly aligned with the majority of BPA’s base of POU “preference” customers who have urged the agency to join Markets+ and asked federal officials to respect its independence in making a day-ahead market decision. (See Public Utilities Urge DOE to Respect BPA’s Day-ahead Decision Process.)

And along with Powerex and a handful of other utilities in the Northwest and Southwest, Chelan has been a consistent contributor to the series of “issue alerts” published by Markets+ backers that have favorably compared features of the SPP market with those of the EDAM.

Despite its status as a BPA preference customer, Chelan manages its own balancing authority area in Central Washington, operates 300 miles of transmission and controls a combined nameplate capacity of 2,037 MW from the Rocky Reach, Rock Island and Lake Chelan hydroelectric dams.

The utility serves about 49,000 customers in a territory covering nearly 3,000 square miles.

Posted on

Cold Weather Standard Set for Posting

NERC’s Standards Committee is on track to post a revised cold weather standard for formal comment slightly ahead of schedule Jan. 27, the ERO’s director of standards development, Jamie Calderon, said during the group’s monthly conference call. 

The Board of Trustees directed the committee to develop a revision to EOP-012-2 (Extreme cold weather preparedness and operations) at a special meeting Jan. 10, invoking Section 321 of NERC’s Rules of Procedure to bypass the ERO’s normal stakeholder approval process for the second time. The revised standard must be submitted to FERC by March 27, according to a deadline set by the commission last year. (See NERC Board Invokes Section 321 Authority for Cold Weather Standard.) 

Committee Chair Todd Bennett, of Associated Electric Cooperative Inc., told attendees that a small group of volunteers from the SC, industry and NERC staff has been working on the new standard since the board’s decision. Under the rules invoked by the board, the SC itself must work with stakeholders and NERC staff to prepare a standard that satisfies FERC’s order and post it for a 45-day public comment period no later than Jan. 29. 

Calderon said the drafting team is finished with its revisions; at this point, the standard is undergoing a final legal and administrative review. She emphasized that NERC is “committed to reviewing all comments” received during the comment period, which will end around March 13. After the comments have been reviewed, the board plans to hold a special call to review the standard and any comments that the team considers relevant before FERC’s deadline. 

In response to a question from Sean Bodkin of Dominion Energy, Calderon confirmed NERC will not hold another formal ballot for the standard. The ERO already has held two formal ballot rounds for EOP-012-3, but each time the standard failed to receive more than a 45% segment-weighted favorable vote — far below the two-thirds majority needed for approval. 

Trustee Sue Kelly, the board’s liaison to the SC, praised the team for taking their time to work on the standard. 

“I was reminded of Shakespeare’s [quote] … ‘We few, we happy few, we band of brothers’ — and sisters — who spent all the time working on this together,” Kelly said. “And we on the board just wanted to say thank you very much for all your efforts.” 

GO/GOP Definitions Project Approved

The only standards action taken by the committee on the conference call, other than the update on the cold weather standard, was to approve a proposal to authorize drafting new definitions for generator owners and operators. 

The proposal was in a standard authorization request (SAR) submitted by the team for Project 2024-01 (Rules of Procedure Definitions Alignment — Generator owner and generator operator). NERC Manager of Standards Development Alison Oswald explained the projected is intended “to align the NERC Glossary of Terms’ definitions for [GO] and [GOP] with those that are contained in the Rules of Procedure registry criteria.”  

Oswald explained the SAR already has been posted for a 45-day formal comment period and received “supportive” comments from industry stakeholders. SC members unanimously approved the SAR, which now will be assigned to the Project 2024-01 team. 

Posted on

FERC Approves CAISO’s SWIP-North Development Agreement

FERC on Jan. 21 approved an agreement between CAISO and LS Power to develop a transmission line that would deliver Idaho wind power into California and could help secure Idaho Power’s participation in the ISO’s Extended Day-Ahead-Market.

The commission’s order covers the Southwest Intertie Project-North (SWIP-North), a 285-mile, 500-kV line being developed by LS Power subsidiary Great Basin Transmission at an estimated cost of $1 billion (ER25-543).

The project, which will be jointly funded by CAISO and Idaho Power, will span northern Nevada and southern Idaho and link up with NV Energy’s One Nevada (ON) line to the south, providing 2,070 MW of transfer capacity southbound and 1,920 MW northbound.

The development agreement memorializes CAISO’s previous agreement to fund about 77% of the project, equal to Great Basin’s ownership share, in exchange for operational control of the company’s entitlements on the line, which will equate to 1,117.5 MW of southbound capacity and 1,072.5 MW of northbound capacity, with the balance in both directions being allocated to NV Energy.

In addition to facilitating transfers into California, the line offers Idaho wind power resources access to wholesale electricity markets in the Desert Southwest through the Desert Link line connected to the southern end of the ON line.

CAISO’s Board of Governors approved the development agreement during an October 2024 meeting despite opposition from some Idaho residents concerned about the path of the line. (See CAISO Board Approves Moving Forward with SWIP-N Transmission Line.)

In its filing with FERC, CAISO said it needed to pursue SWIP-North to support the California Public Utilities Commission’s resource planning portfolio calling for California load-serving entities to procure 1,000 MW of wind generation from Idaho. The ISO noted the proposed line is the only active project that would help fulfill that objective, making it the most timely and cost effective option. The project is expected to commence operation in 2028.

CAISO also said SWIP-North would provide additional economic benefits, such as improving California’s resource diversity and increasing the ability to reduce congestion costs on the parallel California-Oregon Intertie. The line also will assist California in reducing renewable energy curtailments and exporting its solar surpluses.

CAISO’s pursuit of the line likely has played a key role in Idaho Power’s leaning in favor of joining CAISO’s Extended Day-Ahead Market (EDAM) rather than SPP’s Markets+. (See CAISO’s EDAM Scores Key Wins in Contested Northwest.)

And last year, Ryan Atkins, NV Energy’s vice president of resource optimization and resource planning, pointed to SWIP-North and the EDAM’s growing transmission footprint when explaining the utility’s reason for choosing the CAISO market in comments to the Public Utility Commission of Nevada. (See Market Footprint Critical for EDAM Decision, NV Energy Says.)

Posted on

Santee Cooper Seeks Buyer for Unfinished Nuclear Project

Spurred by the recent wave of interest in new nuclear generation, Santee Cooper is seeking a buyer to take over an expansion project halted in 2017 amid extensive cost overruns and delays. 

The South Carolina public power and water utility on Jan. 22 announced the request for proposals for the two unfinished generating units at the V.C. Summer Nuclear Station. A buyer could propose to complete one or both units or propose alternatives. 

New nuclear generating facilities are a tantalizing prospect in an era in which demand for electricity — and for zero-emissions electricity — is expected to soar. But U.S. projects using traditional nuclear technology have been slow and expensive to complete, and the first advanced-technology projects still are a few years in the future, at best. 

Santee Cooper is pitching V.C. Summer Unit 2 and to a lesser extent Unit 3 as an outlier, with some of the time-consuming work already complete. 

Santee Cooper CEO Jimmy Staton said in a news release: “Considering the long timelines required to bring new nuclear units online, Santee Cooper has a unique opportunity to explore options for Summer Units 2 and 3 and their related assets that could allow someone to generate reliable, carbon emissions-free electricity on a meaningfully shortened timeline.” 

Staton alluded to state officials’ interest in moving the halted project into its next chapter and said: “Although Santee Cooper has no plans to own or operate those units, this process could help identify another entity with a viable alternative that would produce benefits for our customers, support economic development and provide value to the state of South Carolina.” 

It is the only site in the United States that could deliver 2.2 GW of nuclear capacity on an accelerated timeline, Santee Cooper said. It sits within the security envelope of the V.C. Summer site, where Dominion Energy South Carolina operates Unit 1, and there are sufficient land, water and transmission assets on site to accommodate Units 2 and 3. 

Santee Cooper also noted that Units 2 and 3 would use the same AP1000 reactor technology used by Southern Co. at its Plant Vogtle expansion project, about 85 miles away in Georgia. 

Plant Vogtle Units 3 and 4 have become a frequent talking point for nuclear opponents, far behind schedule and stunningly over budget. 

They came online in 2023 and 2024 with a final price tag north of $30 billion, making their combined 2.43 GW of nameplate capacity some of the most expensive power generation ever built. 

V.C. Summer Units 2 and 3 were heading down the same path — South Carolina Electric & Gas (SCE&G) spent more than $9 billion on the project before formally ending construction Aug. 17, 2017. 

The fallout continued long after cancellation. Four years later, The Associated Press reported on the third guilty plea to federal criminal charges by executives connected to the project, and on the multiple civil lawsuits filed by ratepayers and others left to foot the bill. 

Like the Vogtle expansion, the V.C. Summer expansion suffered extensive and costly delays and the bankruptcy of lead contractor Westinghouse Electric Co. 

In 2018, SCE&G transferred its majority interest in Units 2 and 3 to minority owner Santee Cooper and Dominion Energy acquired SCE&G parent company SCANA. (See Dominion to Buy Distressed SCANA for $8B.) 

The Nuclear Regulatory Commission first licensed V.C. Summer’s 977-MW Unit 1 to operate in 1982, and in 2004 relicensed it to operate into 2042. 

Posted on

SPP Markets+ Tariff a ‘Home Run’, Staff Says

FERC approved SPP’s tariff for Markets+ with minor modifications in what the RTO’s staff described as a “home run” during the Markets+ Participant Executive Committee’s meeting Jan. 21.  

The commission’s approval Jan. 16 marked a significant milestone likely to ramp up competition with CAISO’s Extended Day-Ahead Market. The order came with two conditions, including a requirement that SPP make a compliance filing within 30 days. (See SPP Markets+ Tariff Wins FERC Approval.)

Paul Suskie, SPP’s executive vice president of regulatory policy and general counsel, noted during the executive committee’s meeting that the compliance filing requires SPP to add six sentences to the tariff and delete one. 

“I’m going to repeat that: addition of six sentences and the deletion of one, out of a 650-page tariff,” Suskie said. “Pretty significant accomplishment.” 

Specifically, FERC asked for modifications to sections in the tariff dealing with transmission availability and transmission opt-out mechanism, duration and communication of opt-outs, Markets+ transmission contributor and mitigation methodology for resource aggregation, according to Suskie. 

“Then last was a deletion of a duplicate that we acknowledged was an unintended duplicate in the filing,” Suskie said. 

SPP and the SPP Market Monitor also must file informational progress reports to FERC every six months to provide updates on market developments. 

This map shows the balancing authority areas that participated in Phase 1 of developing SPP’s Markets+. NV Energy in Nevada has committed to joining CAISO’s EDAM and will not be participating in Phase 2. | SPP

Suskie said after reading and rereading the order, “I give it a home run with 10 feet to spare. So, a great success.” 

SPP Director Steve Wright said the FERC approval is “a really big moment” and that consumers will be better off as a result. 

“Because what has happened here is choice has been created, and when there is choice, there is competition,” Wright said. “And we’ve already seen the impacts of the competitive element that Markets+ has offered in the West just over the course of the last 18 months.” 

The commission said it expects Markets+ will provide its participants with “important economic and reliability benefits” and help them manage the impact of “increasing levels of variable energy resources, load growth and extreme weather events in the region.” 

The order comes nearly six months after the commission issued the RTO a deficiency letter outlining 16 problems it needed to address in the tariff, which it filed last March after an intensive stakeholder process. 

The decision indicates that SPP sufficiently addressed most of those deficiencies, with FERC asking the RTO to provide clarity where the tariff “lacks specificity on key points,” as Commissioner Judy Chang noted in a concurrence, such as in protocols covering “market and resource dispatch mechanics to account for state greenhouse gas programs and the ability for resources to be aggregated when participating” in the market. 

SPP anticipates executing Phase 2 funding agreements soon. FERC must approve the agreements, after which SPP can go to the bank and obtain the financing necessary to fund Phase 2. The process may take up to two months, SPP staff said. 

Posted on

NEPOOL Reliability Committee Briefs: Jan. 22, 2025

The NEPOOL Reliability Committee (RC) voted to support changes in ISO-NE Planning Procedure 7 (PP7) to comply with FERC Order 881. That order is intended to improve transmission line ratings by requiring ambient adjusted ratings for near-term transmission service requests and seasonal ratings for longer-term transmission requests. (See FERC Orders End to Static Transmission Line Ratings and FERC Denies Rehearing, Clarifies Order 881 on Line Ratings.)

PP7 details ISO-NE’s procedures for determining and implementing transmission line ratings.

“The proposed PP7 revisions focus primarily on increasing the number of seasonal ratings from 2 to 12 and providing general guiding principles and requirements in calculating ratings for transmission lines, while allowing each Market Participant to establish their own rating methodology,” wrote Michael Drzewianowski, principal engineer of transmission planning for ISO-NE, in a memo before the meeting.

He added that the proposal “is designed to advance the order’s objective to account for the natural cooling and heating effects of weather when determining available transmission capacity and to promote and enhance sharing of rating methodologies and ratings data.”

New England Clean Energy Connect

The RC voted to support two operating agreements related to the New England Clean Energy Connect (NECEC) transmission project:

    • A transmission operating agreement between ISO-NE and NECEC Transmission giving ISO-NE authority for operational control over the NECEC line
    • An interconnection operating agreement between ISO-NE and Hydro-Québec enabling “the coordinated operation of the Québec-to-New England interconnection”

Data and Information Publication

ISO-NE also outlined a series of updates to its reporting of operational data and information on capacity scarcity conditions, responding to a series of stakeholder requests.

The RTO implemented several changes in late 2024, including “enhanced notifications of real-time contract curtailments” and a new Next Day Operational Capacity Report.

ISO-NE also is working to create a new “public prospective monthly report” containing total capacity supply obligation data and intends to expand its capacity reporting to include hourly data on capacity surplus. It’s considering informational enhancements related to aggregate storage capabilities and real-time tracking of reserves and outages.

Generator Availability Data Collection

The RC also supported a proposal for a new planning procedure to govern data collection for the RTO’s Generating Availability Data System.

“This procedure will describe the data submission timelines, reporting requirements and validation processes for the required data,” said Steven Judd, manager of resource adequacy and accreditation for ISO-NE. He noted that ISO-NE relies on the data to calculate each resource’s outage rate and the region’s installed capacity requirement.

He clarified methodology used to calculate when wind and solar generators must report events, which differs from the methodology used for conventional generators and is “based on the difference of the plant’s [Network Resource] Capability and their Real Time High Operating Limit.”

Operating Procedures

Jaren Lutenegger, director of operational performance, training and integration at ISO-NE, detailed some minor proposed updates to ISO-NE Operating Procedure (OP) 14, which contains technical requirements for generators.

ISO-NE proposes to clarify its language regarding do-not-exceed dispatch limits for solar and wind generators, and to add fuel types to enable reporting to meet U.S. Energy Information Administration requirements.

Mike Knowland, manager of operations forecast and scheduling for ISO-NE, presented proposed changes to OP-21, which governs operational surveys, energy forecasting and energy emergency actions. The proposal is intended to “streamline the surveys and associated processes,” and includes updated survey questions and clarifying language regarding energy alerts and emergencies.

The RC voted to support both proposals, along with clarifying changes to an OP-23 appendix concerning audits of reactive resources.

Posted on

PJM Sets Record Winter Peak Load

PJM set a record winter peak load of 145 GW around 8:15 a.m. Jan. 22, surpassing its previous seasonal peak of 143.7 GW, set in February 2015. 

In an announcement of the record peak, Senior Vice President of Operations Mike Bryson said actions the RTO and its members took ahead of the cold snap got the system through strained conditions the night of Jan. 21 and the following morning. That includes maximum generation and low voltage alerts, a load management alert, a maintenance outage recall, conservative operations and a cold weather alert. 

“We also worked closely with member companies to help resolve any cold-weather issues before the deep freeze set in,” Bryson said. “All of those steps served to help PJM and our members get ready for the cold weather. They have performed remarkably thus far, and I am grateful for their efforts.” 

Exports added an additional 8 GW on top of the Jan. 22 peak and were as high as 9 GW during other times. The maximum generation alert put neighboring regions on alert that exports may need to be curtailed, PJM said. Bryson added that interchange is bidirectional, and PJM has relied on its neighbors in the past. 

The preliminary load data PJM shared should be considered approximate figures calculated from raw telemetry data, PJM cautioned in the release.  

“Verified metered loads are provided by electric distribution companies and represent the best-quality level of load within their zones, with adjustments to data occurring up to 90 days after the actual date,” it said. 

High demand is expected to continue as long as temperatures remain unusually cold.  

In an announcement of the alerts Jan. 21, PJM noted that the conservative operations declaration had been established in the wake of the December 2022 Winter Storm Elliott to provide operators with more flexibility in committing reserves or reducing power flows on certain facilities. It said PJM was working with gas generators to ensure their resources were dispatchable ahead of the onset of cold weather and the MLK Jr. Day holiday weekend. 

The RTO also lauded the performance of its generation fleet during a cold weather alert issued between Jan. 8 and 10. PJM’s Kevin Hatch told the Operating Committee that generation owners started their units early to ensure they could be dispatched if needed and maintenance was rescheduled to ensure availability. Forced outages increased by 2 GW as the temperatures fell, which Hatch said was an improvement over the 7 GW increase in outages seen during the January 2024 Winter Storm Gerri. (See “System Performing Well During Cold Weather Advisory,” PJM OC Briefs: Jan. 9, 2025.) 

Winter storms have become an increasing focus in PJM’s risk modeling, with the season holding 87.8% of the expected unserved energy (EUE) risk according to figures the RTO will present to the Markets and Reliability Committee on Jan. 23. Accelerating demand is noted in the preliminary 2025 Load Forecast, which estimates winter peaks will increase by 2.4% annually, up from 1.8% the year prior. Most of that increase is associated with large load additions (LLAs), such as data centers and chip manufacturing facilities, which make up 11.8% of the increase in winter loads between the 2024 and preliminary 2025 forecasts for the 2030/31 delivery year.