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July 8, 2024

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NERC RSTC Briefs: March 12-13, 2024

Kelly Praises Committee as ‘Kitchen’ of ERO

SAN DIEGO — In her first address to NERC’s Reliability and Security Technical Committee since being named the committee’s board liaison last month, NERC Trustee Sue Kelly asked attendees at the committee’s first meeting of 2024 in San Diego to “bear with me” as she adjusts to her new role. 

Kelly, who previously served as the Board of Trustees’ liaison to the Standards Committee, likened the RSTC to the “kitchen” and the SC to the “front of the standards development house,” meaning the work of both committees is vital to maintaining the ERO’s reputation for “technical excellence.” 

From left: RSTC vice-chair John Stephens; Mark Lauby, NERC; NERC Trustee Sue Kelly | © RTO Insider LLC

“In many respects, you are NERC’s brain trust,” Kelly said. “You do the complicated but vital work that underpins NERC’s standards, guidance, white papers [and] assessments. The reliability issues we are dealing with now are incredibly complex, and we need all the gray matter we can get to apply to these challenges. So, we on the board very much appreciate the efforts that all of you dedicate to this work.” 

The RSTC’s next meeting will take place June 11-12 at Amazon’s headquarters in Seattle, and will be a joint gathering with the SC. Committee members will participate in person, while all others attend online. Its Sept. 11-12 meeting at the headquarters of Hydro-Québec in Montreal will be hybrid as well, and the final meeting of the year, Dec. 11-12, will be fully virtual. 

IBR, DER SARs to Receive Comments

RSTC members endorsed or accepted multiple draft standard authorization requests, reliability guidelines and white papers during their two-day meeting. 

The first SAR was brought to the committee by NERC’s Inverter-based Resource Performance Subcommittee (IRPS). NERC Senior Engineer Alex Shattuck told attendees the IRPS developed the SAR in response to FERC’s Order 901, issued in October, which directed NERC to develop rules addressing IBR data-sharing, model validation, planning and operational studies, and performance standards. (See FERC Orders Reliability Rules for Inverter-Based Resources.) 

The SAR would authorize NERC to update reliability standards FAC-001-4 (Facility interconnection requirements) and FAC-002-4 (Facility interconnection studies) to ensure that transmission operators, balancing authorities and reliability coordinators that identify IBR performance issues can work on corrective actions with generator owners. Members voted to accept the draft SAR and post it for a 30-day public comment period, to begin March 18. 

NERC’s System Planning Impacts from Distributed Energy Resources Working Group (SPIDERWG) brought forward the other SAR, intended to clarify the definitions of operational planning analysis (OPA) and real-time assessment (RTA) in the ERO’s glossary of terms to “explicitly include aggregate DERs as a component of both” definitions.  

SPIDERWG Chair Shayan Rizvi explained the goal of the SAR was to bring “enhanced clarity to situational awareness and [reduce] operational risk,” noting that “DERs have contributed to grid disturbance events” and that clarifying the definition would help grid operators identify and react more efficiently in emergency situations. Members voted to approve this SAR for a public comment period, also to start March 18. 

SPIDERWG, Other Groups Submit Papers

RSTC Chair Rich Hydzik | © RTO Insider LLC

The SPIDERWG also brought forward a white paper on coordination strategies between transmission and distribution entities and a reliability guideline to assist grid planners with needed studies of DERs’ impact on reliability. RSTC members accepted the white paper and approved posting the guideline for a 45-day comment period. 

NERC’s Probabilistic Assessment Working Group also brought a paper intended to help grid planners understand the reliability risks posed by extreme weather events, while the System Protection and Control Working Group submitted its paper on transmission relay loadability. The RSTC accepted both papers and agreed to solicit reviewers for two more papers from the SPCWG: one on evaluating IBRs’ compliance with existing standards, the other on transmission system phase backup protection.

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Drop in Wash. Carbon Price Spells Uncertainty for Budget, Gas Costs

Washington’s first quarterly carbon allowance auction of 2024 has thrown two new wrinkles into the economics of the state’s fledgling — and controversial — cap-and-invest program.  

First: The auction cleared at $25.76 per allowance. That’s sharply lower than clearing prices in 2023’s four quarterly auctions, which took a lot of blame for Washington’s high gasoline prices last summer.  

Second: The March 6 auction, results for which were announced by the state’s Department of Ecology on March 13, raised $135.5 million, setting a dramatically slower pace than is needed to reach the $941 million the state predicted it would collect in the first half of 2024.  

Last year the auctions cleared at $48.50 in the first quarter of 2023, $56.01 in the second, $63.03 in the third and $51.89 in the fourth. Those prices were significantly higher than predicted, and cap-and-invest critics blamed them for adding 21 to 50 cents per gallon to Washington’s traditionally high gas prices. 

Washington has always had some of the nation’s highest gas prices due to geographical and economic factors outside the cap-and-invest program. Average gas prices in the state are currently $4.22 per gallon compared with a national average of $3.40, according to AAA. 

High gasoline prices have led conservatives to back a November referendum seeking to repeal the cap-and-invest program. (See Wash. Cap-and-trade Opponents Advance Repeal Petition to Sec. of State.) 

Ecology Department spokesperson Caroline Halter said demand for allowances “remained strong” despite the sharp decline in settlement prices compared with the December 2023 auction. 

“As in past auctions, all available allowances were sold, and there were more bids than available allowances,” Halter told NetZero Insider in an email. An external auction monitor for the sales did not find any evidence of market manipulation and determined that the auction was conducted fairly, she added. 

Washington’s Office of Financial Management said the auction’s $135.5 million in revenue is $108-$110 million less than predicted. The state has raised $1.96 billion in cap-and-invest revenue since last year. 

The OFM noted five quarterly auctions remain in the budget biennium running from May 1, 2023, through June 30, 2025. These include two in June and September that run prior to the November referendum. Three more are scheduled for December, March 2025 and June 2025.  

With the November referendum being a factor in assembling a supplemental budget for July 2024 through June 2025, the state Legislature put language in its budget bills to keep $816 million in cap-and-invest revenue from being appropriated until Jan. 1, 2025, OFM spokesperson Hayden Mackley told NetZero Insider. Consequently, if cap-and-invest is repealed, that $816 million in appropriations would be rendered moot. 

“Regarding gas prices, OFM can’t speak to the effect of the auction on those — we don’t have any insight into or control over businesses’ pricing strategies,” Mackley wrote.  

Gov. Jay Inslee (D) spokesperson Jaime Smith added: “Even as allowance prices were relatively high throughout the fall and winter, gas prices fell to a two-year low, showing how difficult it is to infer direct impacts.” 

Washington is exploring joining the joint California-Quebec carbon market to help bring down auction prices. California-Quebec bid prices increased from $19 in 2021 to $41.76 last month, according to the California Air Resources Board. The results from last week’s auction mean that Washington’s allowance prices have now dropped below California’s for the first time. 

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Solar Growth has ERCOT Looking at Ride-through Rules

An expected tsunami of solar resources setting up shop in Texas has led to an immediate need for ERCOT to understand and set ride-through requirements for inverter-based resources (IBRs), according to a Texas energy expert. 

The Texas grid operator had more than 22 GW of solar capacity operational when 2024 began and expects that to exceed 30 GW by year-end, with more to follow. ERCOT has set numerous records for solar production this year, the most recent coming Feb. 19 at 17.2 GW. 

Two IBR-related voltage disturbances in West Texas in 2021 and 2022, dubbed the Odessa Disturbances I and II, have led to ERCOT working with stakeholders on a nodal operating guide revision request (NOGRR245) to improve the clarity and specificity of IBRs’ voltage ride-through requirements. The change would align the ISO’s rules with NERC reliability guidelines and the most relevant parts of the Institute of Electrical and Electronics Engineers standard for IBRs interconnecting with the grid. 

“One of the things that really added a sense of urgency to this issue was the fact that the projection for growth of solar in ERCOT was very significant,” Jewell and Associates principal Michael Jewell said during a Talk with Texas RE event March 12. “We’ve seen that kind of growth already happening since the Odessa events, and that growth is continuing. The need to address this issue has remained very high.” 

The guide change is tabled at the stakeholder-led Technical Advisory Committee meeting to allow for additional negotiations between ERCOT staff and clean energy developers. The NOGRR is expected to be taken up again during TAC’s March 27 meeting. (See “Stakeholders Continue Discussion of IBR Reliability Requirements,” Technical Advisory Committee Briefs: Jan. 24, 2024.) 

Under the rule’s initial requirements, all IBRs with a standard generation interconnection agreement executed on or after Jan. 1, 2023, would have to comply. All other IBRs would have to comply within 12 months of the NOGRR’s approval, with an extension of up to 12 months. 

“SCADA [supervisory control and data acquisition] data was not necessarily detailed enough to be able to catch what was going on,” Jewell said. “High-resolution data really became a focal point … and a real strong need for accurate inverter settings.” 

Stakeholders have pushed back against the timeline. They also have been concerned with issues regarding existing exemptions for ride-through requirements already in place and whether they will be repealed. 

“Stakeholders continued to point out that there have been multiple examples of grandfathering existing resources from new requirements that this was something that really should be considered,” Jewell said. 

Original equipment manufacturers (OEMs) of IBRs have said a limited pool of resources to retrofit existing IBRs could delay the time it will take to make the upgrades. Staff and stakeholders also are looking at alternative solutions for mandating testing requirements that have not yet been developed. 

“To say that there have been a lot of comments that have been filed with regard to 245 would be an understatement,” Jewell said, referring to the nearly five dozen comments submitted. “It’s a significant amount of data that’s been provided, and ERCOT has been wrestling with those and making some making some changes.” 

Jewell told his audience progress has been made to address issues at the facilities affected by the Odessa disturbances with software and firmware changes. ERCOT is expected to file another set of comments, after which the clean energy stakeholders will file their responses before the TAC meeting.

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WRI Webinar Examines How to Expand Grid-enhancing Technologies

With a major grid expansion on planning boards around the country, grid-enhancing technologies (GETs) will be key to getting the most out of current and future systems, experts said on a World Resources Institute webinar March 12. 

“We are increasingly relying on the grid to enable power-sharing between neighboring regions, to ensure good reliability, generally, but also during extreme winter events and as well as extreme heat events,” said WRI Senior Manager for Clean Energy Jennifer Chen. “We need to deliver low-cost clean energy to customers and support growing electricity demand from electrification, manufacturing, data centers, artificial intelligence, crypto-mining, indoor agriculture and the list really goes on.” 

GETs can get more power through existing transmission lines with operational tweaks or reconductor existing lines to greatly expand the number of electrons that flow through them. 

FERC must consider more than decarbonization in grid expansion; as an economic regulator, it needs to ensure the bulk power system can support the wave of demand, Commissioner Allison Clements said. 

“We need to figure out how to make easy, quick investments that can help us in the near term to modernize the grid, as well as working on medium-term and longer-term, more difficult investments, like the investment in new regional and interregional transmission,” Clements said. “I don’t think that any of the things you described are actually replacements for new transmission investment. But certainly, we have a toolbox of technologies and transmission options, cost options, market design options, and we should be trying to take advantage of all of them.” 

GETs have been shown to produce major benefits, but they face economic, operational and regulatory barriers. The utility industry does not have good incentives to make smaller investments that avoid capital spending. 

“Everyone knows that you should eat your broccoli, you don’t necessarily do it if there’s cake sitting there for you to enjoy,” Clements said. 

Many grid operators are not familiar with GETs and thus are hesitant to risk reliability on less-proven technologies, she said, adding that economic incentives and regulations need to be aligned so GETs are used more broadly than just as the subject of pilot programs. 

Another major barrier to deploying GETs is information asymmetry between regulated utilities and their regulators, said Connecticut Public Utility Regulatory Authority Chair Marissa Gillett. Like grid operators, regulators are wary of relying on new technologies. 

“State regulators, or different regions, often want to pilot something, even if it has been proven in another area of the country,” Gillett said. “And I think that can be very frustrating, particularly for proponents of new technologies.” 

Sometimes the desire to pilot makes sense, such as when a technology worked in a state with different regulations. But it also happens even when a technology has been proven to work in a state’s regulatory construct, she added. 

The Idaho National Laboratory has found that 118,000 miles of transmission lines nationwide could benefit from reconductoring, said Gilbert Bindewald of DOE’s Office of Electricity. 

“One of the aspects that I’m continually hearing is not only the economics, but given that these are multidecadal investments, how will these technologies continue to perform 20 years from now, 30 years from now?” he added. 

Multiple offices at DOE are working on research, development and deployment of GETs with the hope of showing the industry the technology’s reliability and resilience benefits, Bindewald said. That work includes testing different GETs by accelerating the aging process and using other tests to get a sense of their full lifetime of benefits, he added. 

In the Energy Policy Act of 2005, FERC got the authority to offer performance-based incentives that could be applied to GETs, but so far it hasn’t been used much, Clements said. The WATT Coalition and others have asked FERC to include GETs in its regional transmission rule and advance a notice of inquiry it launched on dynamic line ratings.  

“I think all three sitting commissioners currently have expressed a desire to revisit our transmission incentives policy,” Clements said. “I’m not sure all three of us have the same outlook for where that policy should go. From my perspective, we need to incent the hard stuff to build.” 

That would include GETs and harder-to-build transmission lines such as interregional projects, she added. 

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CAISO Wins FERC Approval for Subscriber-funded Tx Plan

FERC has approved a CAISO proposal allowing transmission lines outside California to join the ISO under a new subscriber-funded model that avoids allocating project costs to the ISO’s load-serving entities (ER23-2917). 

Under CAISO’s “subscriber participating transmission owner” (PTO) program, the developer of a transmission project not chosen in CAISO’s transmission planning process can solicit generation-owning customers to subscribe to service on a line designed to deliver energy into California. The project owner then can turn operational authority of the line over to the ISO, joining the balancing authority areas as a “subscriber PTO,” a category of owner ineligible to recover costs through the ISO’s transmission access charge (TAC) — the mechanism CAISO uses to bill load-serving entities for their transmission use.  

The plan, which CAISO’s Board of Governors approved in July 2023, is designed to help California draw on clean energy resources outside the state to meet its ambitious greenhouse gas reduction goals while alleviating financial risks associated with building new merchant transmission. (See CAISO Board OKs Plan to Admit Subscriber-funded Transmission Lines.) 

“The commission has long required a merchant transmission facility’s owner and its willing customers to assume the full market risk for the cost of constructing the facility and ensure that no captive customers are required to pay for the cost of the facility,” FERC wrote in the March 12 order. “Here, subscribers of the capacity on the subscriber PTO’s transmission facilities will be responsible for paying the entire cost of constructing those transmission facilities, and no transmission revenue requirement for the subscriber PTO transmission facilities will be included in the TAC.  

“Therefore, we find CAISO’s proposal to be consistent with the commission’s policy regarding cost recovery for merchant transmission facilities.”

The subscriber PTO program will require applicants to obtain approval from CAISO’s board to join the balancing area, execute a transmission control agreement, place transmissions assets and associated entitlements under the ISO’s operational control, and satisfy the requirements applicable to other PTOs.  

In exchange for funding the project, subscribers will receive scheduling priority on the associated transmission paths. Initial subscriber-owned generation interconnecting with CAISO through the subscriber PTO’s transmission will be studied through the PTO’s transmission interconnection process, rather than the ISO’s generator interconnection process. 

The program is open to existing transmission lines and those being planned or developed. 

Nonsubscriber Charges Prompt Protest

Protests filed with FERC against the subscriber PTO model focused on how those PTOs will be compensated when nonsubscribers use their lines.  

The proposal calls for CAISO to assess the TAC rate for nonsubscriber imports using the scheduling points associated with a subscriber PTO’s transmission facilities, while assessing the ISO’s wheeling access charge (WAC) rate for nonsubscriber exports and “wheeling-through” transactions at those points.  

At the same time, each subscriber PTO can develop a nonsubscriber $/MWh usage charge that cannot exceed the application TAC rate at the time the PTO files its charge for FERC approval.  

“Thus, while nonsubscribers will pay CAISO the current TAC or WAC, the subscriber PTO would receive an amount no greater than the TAC rate via the nonsubscriber usage rate accepted by the commission,” FERC noted in the order. “CAISO explains that, if the total TAC and WAC revenue contributed by transactions on the subscriber PTO’s facilities exceeds the total calculated nonsubscriber usage payment then the excess amount will be added back to the regional access charge for allocation to the other participating TOs besides the subscriber PTO.” 

When WAC revenue is insufficient to cover nonsubscriber charges, CAISO will draw on nonsubscriber TAC revenues to cover the balance before distributing those revenues to other CAISO PTOs. 

In a jointly filed protest, Pacific Gas and Electric and Southern California Edison complained that subscriber PTOs should not be compensated for nonsubscriber use of their transmission lines because those lines will be fully paid for by the subscribers. 

“As an initial matter, and contrary to protestors’ arguments, the commission has not held that a facility’s costs can be allocated to customers only following a determination that the facility is necessary for reliability, economic, policy or other reasons through the CAISO transmission planning process,” the commission wrote. “In any case, we disagree with protestors that compensation for nonsubscriber use of a subscriber PTO’s transmission facilities conflicts with the commission’s longstanding policy that a merchant transmission facility’s owner and its willing customers must assume the full market risk for the cost of constructing the merchant transmission facility, and that no captive customers are required to pay for the cost of the facility.”  

The commission declined to address the protestors’ concerns about how the nonsubscriber usage rate will be formulated, saying the issue was outside the scope of the current proceeding and best addressed in future proceedings dealing with rates proposed by subscriber PTOs. FERC also dismissed a request to sever the nonsubscriber rate provisions from the proposal and reject them. 

“Regarding protestors’ concerns that the TAC could increase as a result of the nonsubscriber usage rate, we find, based on the record before us, that the subscriber PTO model is unlikely to result in an increase in the TAC, and, should an increase occur, any such increase would not be due to the subscriber PTO recovering any of the costs for constructing the subscriber PTO’s initial transmission facilities through the TAC,” the commission found. It also noted that CAISO’s response to a FERC deficiency letter in January clarified that the nonsubscriber usage rate would be required to decline in line with any future reduction of the TAC. 

TransWest Request Denied

FERC rejected a request by TransWest Express for guidance on “a potential framework to determine the nonsubscriber usage rate,” saying the subject was outside the scope of the proceeding and reiterating that the issue would be addressed in future rate filings. 

The proposed TransWest Express project, a 700-mile line designed to carry 3,000 MW of wind energy from Wyoming to a CAISO interconnection point in Nevada, likely will become the first transmission facility to join the ISO under the subscriber PTO program. 

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NEPOOL Markets Committee Briefs: March 13, 2024

ISO-NE on March 13 presented the NEPOOL Markets Committee with additional results of the impact analysis for the RTO’s resource capacity accreditation (RCA) project, which looked at how changes to the resource mix would affect the seasonal distribution of shortfall risks. 

The RCA project is being developing in conjunction with structural changes to the timescale of the Forward Capacity Auction (FCA). The RTO has proposed a three-year delay of FCA 19 to develop and implement the changes. (See related story, NEPOOL MC Backs Further Forward Capacity Auction Delay.) 

In the initial impact analysis “base case,” ISO-NE estimated that loss-of-load risk is distributed 80% in the winter and 20% in the summer. (See NEPOOL Markets Committee Briefs: Feb. 6, 2024.) 

The sensitivity analyses presented to the MC included three scenarios: 

      • the addition of wind, solar and battery resources without corresponding resource retirements; 
      • the addition of the renewable resources accompanied by the retirement of oil-only capacity; and 
      • the addition of renewables accompanied by the retirement of coal capacity. 

The addition of renewables without retirements would be more likely to reduce the number of days with loss-of-load events in the winter than in the summer but would provide greater reductions in the duration of the events in the summer than in the winter, ISO-NE found. 

When coal capacity was retired, ISO-NE found increased risk of multiday loss-of-load events in the winter, shifting the region’s risk profile towards the winter, said Dane Schiro, the RTO’s principal analyst. 

Compared to the retirement of coal, retiring oil capacity “can be thought of as retiring proportionally more summer capacity than winter capacity” because of the model’s winter fuel constraints for oil resources, Schiro said. Therefore, the retirement of oil capacity shifted the overall risk profile toward the summer relative to the coal-retirement scenario. 

“The seasonal output characteristics of retiring and new resources are important to the seasonal risk split,” Schiro said, adding that the findings were in line with expectations. 

ISO-NE will present additional sensitivity results to the MC in April. 

Regional Differences in Gas Accreditation

Ben Griffiths, vice president of wholesale market policy at LS Power, made the case for the RCA updates to incorporate regional differences in pipeline gas availability in the winter. 

ISO-NE is planning to treat access to nonfirm gas as the same across the region, despite LS Power data showing that gas access varies significantly based on where generators are located on the pipeline system, Griffiths said. 

“Observational data, economic modeling and physical analysis all indicate that gas availability is location and fact specific,” Griffiths said. “A failure to reflect locational attributes will lead to inaccurate pricing for gas generators, worse reliability [and] potential premature retirement.” 

Gas units in Connecticut run “at a higher level than we would expect across a range of temperatures, and there is no appreciable temperature-dependent output deviation,” Griffiths said. “This suggests that the gas system is not constrained in Connecticut at any observed temperature.” 

In contrast, generation for some units in Maine and Massachusetts historically has been highly temperature dependent, although this temperature correlation can vary significantly unit to unit, Griffiths added.  

The accreditation of gas resources has been a major topic of the RCA project. ISO-NE has advocated for a “market constraint approach,” in which the RTO would limit the amount of nonfirm gas capacity it procures based on the region’s gas constraints while having gas-fired resources compete for capacity obligations. 

ISO-NE initially indicated it would not be able to design and implement this approach for FCA 19, but it said March 13 that if the proposal for an additional two-year delay of the auction is approved by FERC, it will prioritize implementing a market constraint approach in time for it. (See NEPOOL Markets Committee Briefs: Jan. 11, 2024.) 

Regardless of the approach ISO-NE takes, it must account for local differences, Griffiths said. 

Under the market-constraint approach, ISO-NE could create “a nested zone for Connecticut which has higher levels of fuel availability and is, in effect, unconstrained,” Griffiths said. LS Power’s proposal would not affect the total amount of accredited gas capacity and simply would change how the overall capacity of the fleet is distributed, he added.  

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NY State Reliability Council Executive Committee Briefs: March 8, 2024

Proposed Transmission Criteria for Gas Contingencies

ALBANY, N.Y. — The New York State Reliability Council Executive Committee on March 8 approved for industry review two new proposed reliability rules, 153a and 154a, aimed at revising NYISO’s transmission planning requirements to account for a loss of the gas delivery system and fuel shortages at power plants, respectively. 

Roger Clayton, chair of the council’s Reliability Rules Subcommittee, said the group’s goal is to “basically convert what are currently considered extreme contingencies and extreme system conditions into design conditions.” 

While the failure of the gas delivery system to multiple plants is already included as an extreme contingency in the council’s design criteria, PRR-153a would add the loss of fuel to a single plant as another contingency. Both would be clarified to apply specifically to fossil-based plants. 

“This recognizes the increasing importance of gas going forward amid the increasing development of renewable resources, and the need to have reliable backup base reserves by incorporating a design contingency for the sudden loss of gas fuel,” Clayton said. 

PRR-154a aims to better align the council’s requirements with expected gas plant availability under winter peak conditions. It would add the unavailability of nonfirm gas service during the winter peak to the “credible combinations” of conditions under which the grid would be strained, and it would clarify that extreme conditions include the loss of all gas generation, regardless of supply firmness. 

“As New York becomes a winter-peaking system, the gas supply to electric generation plants is expected to be strained,” the proposal says. “To maintain reliability in the future, New York’s grid should be designed to withstand gas shortages during forecasted winter peak conditions.” 

Zach Smith, vice president of system and resource planning at NYISO, commended the committee for developing proposed rules that respond to evolving market conditions. 

Smith said the ISO’s only concern with the proposals was related to timing, as it would like to incorporate them into its annual Reliability Needs Assessment because it might “identify reliability needs in the wintertime” that it might have previously overlooked. Smith added that, if the timing aligns as intended, the rules would also be integrated into NYISO’s first newly revamped interconnection cluster study, but not its transitional cluster study. 

The proposed rules will be posted online for a 45-day review period. 

NYISO Updates

Aaron Markham, NYISO vice president of operations, briefed the committee on how the ISO is preparing for the April 8 solar eclipse, predicting it could reduce the afternoon’s solar production by “upwards of 3,400 MW if it is a clear sky day.”  

Markham added that if the eclipse occurs on a cloudy day, NYISO would not conduct a post-event review of its impact on solar production, as the previous cloudy day eclipse event had only minor impacts on solar production. (See “October Operations,” NYISO Braces for the Coming Winter.) 

NYISO staff also addressed Advanced Energy United’s recently released scorecard on ISO/RTO generator interconnection processes. The ISO received a C-, better than only PJM and ISO-NE, though no grid operator scored higher than a B. (See AEU Grades ISO/RTO Queues as Order 2023 is Implemented.) 

COO Emilie Nelson said the study relied on a small sample of interconnection queue datapoints for each ISO/RTO. “Nevertheless, we’re working really hard with our stakeholders to improve the interconnection process, and we take that objective very seriously, so I think that the results of that effort will come to bear in the next few years.” 

Smith followed up, saying, “We’ve reached out to the authors to try to understand what went into their [methodology]. … But what they were intending was to create a reference point, because all of [the ISO/RTOs] are entirely changing their interconnection processes, and we are completely overhauling our current processes. 

“So, in talking to them, and trying to understand their objective, their objective is to put out another report in the future to demonstrate that ‘this is where we were, and where are we in the future?’” 

Gioia, Burman Honored

The committee opened its meeting by dedicating a plaque in honor of former New York Public Service Commission Chair Paul L. Gioia, who helped establish NYISO.  

Gioia, 81, died last month. He was appointed chair by Gov. Hugh Carey in 1981 and served for five years until he was fired by Gov. Mario Cuomo. He then joined law firm Dewey & LeBoeuf, where he became lead counsel for the New York Power Pool and helped oversee its transition into the ISO in the late ’90s. 

The council “recognizes Paul’s outstanding public service and contributions to the health and safety of New Yorkers today, and in the future, by assuring the reliability of the electric power system in New York state,” Clayton said. 

NYSRC commemorative plaque for Paul L. Gioia | © RTO Insider LLC

PSC Commissioner Diane Burman also paid tribute, highlighting Gioia’s impact as a mentor and how much his “personal and professional friendship” meant to her. She shared a personal tribute on LinkedIn. 

The committee recognized Burman for her service at the meeting’s conclusion. She announced last month that she would not seek reappointment after a decade on the commission. Her term ended Feb. 1. 

“I’ve been a public servant over for 20 years; five of that was as a staffer for the commission, and over 10 years has been as a commissioner,” she said. “Leaving is really bittersweet to me, but it is time for me to pass the baton. 

“I really wanted to come here today to thank the Reliability Council as a whole, but more importantly, each of you individually for your continued service. Thank you for making me a better, more well-rounded regulator, and I am truly going to greatly miss being a part of all this with all of you.” 

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House Oversight Examines Grid Reliability and Resource Adequacy

Former FERC Commissioner James Danly told a House Oversight subcommittee March 12 that resource adequacy was being threatened by rapid generation retirements and demand growth. 

The message, given to the House Oversight and Accountability Subcommittee on Economic Growth, Energy Policy and Regulatory Affairs, was not much different from what Danly, now a partner at law firm Skadden, told Congress last year when he was on the commission. (See FERC’s Danly, Christie Again Warn Congress of Looming Reliability Crisis.) 

“Every market is different, the tariffs are different region to region, but there have been problems in properly incentivizing the arrival of new generation to meet load growth,” Danly said. “This problem becomes all the more difficult when the markets have to operate and create those price signals upon which we rely to ensure resource adequacy, when they’re operating in the context of widespread and lucrative subsidies, which have the inevitable effect of warping price signals.” 

Federal subsidies overvalue some resources, while undervaluing others, and because those others are getting less money overall, that means there are fewer of them, he added. 

Subcommittee Chair Pat Fallon (R-Texas) asked Danly whether EPA’s latest proposal on greenhouse gas emissions from power plants would impact reliability. As commissioner, Danly had sent a letter to EPA because he was worried they were not taking its potential impact on reliability seriously enough. 

The rule is going to increase the capital investments of some of the covered power plants, which will have to be reflected when they bid into markets, and that ultimately should lead to higher prices, Danly said. 

“I think that the Clean Power Plan could potentially create extraordinarily expensive prices in the markets,” Danly said. “And what I’m really concerned about is not that, because that’s a public policy decision. What I’m concerned about is that it seems to be undertaken without full knowledge of the consequence.” 

Another issue with cleaning up the grid is that the buildout of renewables favored by many will require a massive expansion of transmission. 

“I’m skeptical that that buildout of transmission is even feasible, given the cost. It’s an extremely capital-intensive proposition to build out that amount of transmission,” Danly said. “And given the regulatory risks that attend any large infrastructure project in the United States, it is very hard to site and construct long, linear infrastructure projects.” 

The committee also heard from the libertarian Cato Institute through Director of Energy and Environmental Policy Studies Travis Fisher, who said the grid is becoming a liability due to multiple subsidies, mandates and regulations. The Inflation Reduction Act extended the production tax credit for renewables, and Fisher said they could cost taxpayers $3 trillion through 2050. 

“These tax credits reward electricity production from unreliable sources and distort the market signals that keep reliable power plants running,” Fisher said. “The result will be a weaker grid over time, not to mention a deepening fiscal crisis in the country.” 

While Fisher and Danly blamed policy for the grid’s performance, the Democrats’ witness — Converge Strategies’ Jonathon Monken, who previously worked for PJM — blamed increasing bouts of extreme weather caused by climate change. The grid is transitioning as clean energy becomes cheaper than traditional power plants like those that burn coal, Monken said. 

“This transition is occurring at a time when the grid is under threat from climate-driven changes in severe weather patterns, as well as targeted attacks on grid infrastructure from homegrown violent extremists conducting physical attacks, and foreign adversaries utilizing cyber capabilities,” Monken said. 

Recent winter reliability events have shown it’s risky to run the grid with a single fuel type and with limited geographies. Most outages in Winter Storms Elliot and Uri were because of issues around natural gas. 

“More comprehensive evaluations of fuel security are needed to identify the optimal mixture generation types to reduce the risk of disruptions caused by fuel availability,” Monken said. “This should include transmission planning to prioritize connecting regions with a greater diversity of resources to those regions with a high dependency on single fuels that could suffer from these common mode failures.”

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FERC Releases Fiscal Year 2025 Budget Justification

FERC has released its fiscal year 2025 congressional justification, which would have the agency fund itself with $532 million from fees and annual charges assessed to its regulated entities. 

The request is up from $508.4 million last year but is short of its requirement of $565.4 million, though FERC can defer some of that with $33.4 million that it brought in earlier and did not spend. The funding would support 1,576 full-time equivalent employees, 68 more than in 2023. 

“The commission allocates 62% of its budget to directly cover personnel compensation costs of its employees on an annual basis,” said the request, released March 11. “The commission’s request reflects a personnel compensation increase of $39.6 million, or 12.8%, above the FY 2023 enacted level to support an increase of 68 FTEs and accounts for an estimated 2% pay raise in January 2025.” 

FERC is using money from the Inflation Reduction Act to speed its permitting efforts’ timelines and to increase its public outreach in communities with environmental justice concerns. 

The request includes $152.5 million to support information technology investments, an increase of $36.9 million or 31.9% over 2023. The increase would fund improvements including a series of proofs of concept to harness the generative power of artificial intelligence. 

“The utilization of AI promises to enhance efficiencies across various FERC program offices, ultimately leading to substantial benefits in the execution of the commission’s mission,” the request said. 

The funding request includes an $8.9 million cut in rental costs as FERC has consolidated its employees in the D.C. area into its headquarters and has lowered the amount of space its operations require. 

The electric industry is responsible for most of the funding, with FERC expecting to collect $319 million across hydropower ($124.8 million), natural gas ($106.9 million) and the oil industry ($13.8 million). 

The document also includes brief descriptions of what FERC has been up to and its plans to move specific policies along. The paper discussed its transmission NOPR, which has produced Order 2023 mandating changes to the commission’s pro forma interconnection rules. 

“The commission will also consider requests for rehearing of Order No. 2023 and evaluate Order No. 2023 compliance filings with respect to changes to transmission providers’ generator interconnection procedures and agreements,” the document said. 

The industry expects another final rule on transmission planning and cost allocation, and FERC said it would “continue to evaluate feedback from the public” on its NOPR to “help inform whether further commission action is appropriate.”  

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NEPOOL MC Backs Further Forward Capacity Auction Delay

The NEPOOL Markets Committee (MC) voted March 12 to approve an additional two-year delay of ISO-NE’s Forward Capacity Auction (FCA) 19 to develop and implement a new prompt and seasonal capacity auction. FCA 19 applies to the 2028/29 capacity commitment period (CCP).  

ISO-NE has proposed to shift its forward capacity market, which is held about three-and-a-half years prior to the CCP, to a “prompt/seasonal” market held several months before the CCP, while procuring capacity separately for different seasonal periods. (See ISO-NE Moving Forward with Prompt, Seasonal Capacity Market Design.) 

The specifics of an eventual prompt and seasonal market have yet to be determined. The approved proposal would establish a backstop interim schedule that “shifts all FCA 19 activities back by another two years (three years total),” while implementing “a 10-month schedule over many auction cycles to return to three-year forward schedule,” said Chris Geissler of ISO-NE.  

ISO-NE intends for the backstop provisions to be ultimately overwritten by the final market design, which will be developed during the delay.  

Also during the delay, ISO-NE will prioritize developing a “market constraint approach” to accrediting gas resources once the two-year delay is approved by FERC, Geissler said. The RTO previously indicated this is its preferred gas accreditation approach but said it would not have time to develop this approach for FCA 19 with just a one-year delay. (See NEPOOL Markets Committee Briefs: Feb. 6, 2024.) 

If FERC accepts the additional delay, ISO-NE is planning to pause stakeholder discussions on its ongoing Resource Capacity Accreditation (RCA) project “and develop a work plan for a combined accreditation design with a prompt/seasonal capacity market to implement for CCP 19.” 

If the proposal is rejected by FERC, ISO-NE will proceed with the RCA project and target a filing in the fourth quarter of 2024. ISO-NE has not decided whether to pursue expedited treatment from FERC on the filing.  

Internal, External Monitors Offer Support

David Naughton, executive director of the RTO’s Internal Market Monitor (IMM), expressed support for the proposal, calling it a “a more cost-effective and efficient means of procuring capacity compared to the current forward market framework.” 

Naughton said a prompt and seasonal market would help reduce uncertainty related to projecting supply and demand about four years into the future, especially amid significant changes associated with the clean energy transition. 

Stakeholders have expressed concerns that the changes could reduce the forward notice of resource retirements, which are currently tied to the FCA process. ISO-NE has said the retirement process could be separated from the capacity auction to preserve this advanced retirement signal in a prompt format.  

“Under a prompt procurement time frame, the solution space for addressing reliability issues becomes constrained; there may be limited time and scope for transmission solutions or a market response to capacity exits,” Naughton wrote in a memo. 

“Therefore, it is likely beneficial for the retirement process to commence well in advance of the prompt time frame, with details to be developed regarding notification timing, irrevocability of the notification, market power assessments and auction treatment,” Naughton said.  

Potomac Economics, ISO-NE’s External Market Monitor, also expressed support for the move to a prompt and seasonal capacity market, as well as the additional two-year delay to achieve this design.  

Pallas LeeVanSchaick of Potomac Economics noted that the current FCM was initially designed to provide enough advance warning to enable investments in new gas capacity if the projected power supply did not match demand.  

However, the FCA has failed to incentivize these new investments “because developers receive only one year of guaranteed revenue for resources with much longer economic lives and it can create inefficient risk for developers related to the required in-service date,” LeeVanSchaick said. 

LeeVanSchaick added that recent out-of-market reliability mechanisms like the Mystic Cost-of-Service Agreement and the Inventoried Energy Program indicate that the current FCM is not adequately ensuring winter reliability.  

“The most common reason resources are retained out-of-market is that the market does not fully reflect the reliability need the resource is satisfying,” LeeVanSchaick said. He downplayed concerns raised by some stakeholders that a prompt market would increase risk of out-of-market retentions by reducing the advanced notice of resource retirements.  

“When a capacity market (regardless of whether it is a prompt or forward market) is designed to set prices efficiently at each location and all reliability needs are reflected in its requirements and resource accreditation, the need to retain resources out-of-market will be very limited,” LeeVanSchaick said.  

“If the capacity market compensates resources efficiently, retirement-driven reliability needs are usually so localized that a transmission solution can be completed in time to allow the generator to retire rather than be retained out-of-market or to be retained for a relatively short duration,” he added. 

LeeVanSchaick also disagreed with some concerns raised by stakeholders that a prompt market could increase capacity market volatility, arguing that a prompt market would instead lead to more stable prices by providing more flexibility to suppliers and eliminating the “phantom new entry” of delayed generation projects with capacity commitments, “which has led to significant price suppression in some FCAs.” 

The proposal now heads to a Participants Committee vote in early April.