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December 16, 2025

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Study: Frequency Response OK in Eastern Interconnection

By Rich Heidorn Jr.

ATLANTA — Despite the ongoing shift to renewables, the Eastern Interconnection has sufficient inertia to maintain system frequency for at least the next five years, according to a study released Thursday.

The Eastern Interconnection Planning Collaborative (EIPC), a group of 20 planning coordinators, conducted the study in response to a request by NERC’s Essential Reliability Services Working Group.

The working group had cited concerns about the retirements of synchronous generators such as coal and nuclear, which respond automatically to a frequency reduction by slowing down and releasing more energy into the grid. Asynchronous wind and solar power generators do not respond in the same way unless their inverters have been programmed to provide frequency control.

The EIPC’s study was released as a NERC standards development team (SDT) reviewing other aspects of frequency response issued a request for comment on continuing to rely on FERC Form 714 for data. (See “Comments Sought” below.)

Steven Judd, lead engineer in system planning for ISO-NE and chair of the EIPC Frequency Response Task Force, said the study provided reassurance in the near term and a foundation for future projects.

“This first effort to track the interconnection’s inertial response has established a framework and baseline for system planners to improve the system network models going forward, provide sufficient notice when the changing resource mix could have an adverse effect on frequency response and develop solutions to those adverse effects,” Judd said.

This figure Illustrates a frequency deviation due to a loss of generation and the methodology for calculating frequency response. Value A is the average frequency from t-16 to t-2 seconds. Point C is the lowest frequency observed in the first 12 seconds and Value B is the average from t+20 to t+52 seconds. The black line represents the point at which underfrequency load shed (UFLS) is expected to occur. | Eastern Interconnection Planning Collaborative

In order to prepare for the expected increase in nonsynchronous generation with reduced inertia, the report said planners will need improved frequency responsive power flow simulation models.

The report was based on several analyses, including benchmarking a historical frequency event with spring light load (SLL) cases, and concluded that about 45% of governors were providing primary frequency response, substantially higher than previous NERC studies, which pegged response at about 30%. Thus, for forward-looking frequency measures, 55% of the governors were disabled in the power flow model.

“It is expected future improvements to the modeling of governors through new compliance standards and updated simulation models from the software vendors will reduce the need for artificially disabling governor models to match historical performance,” the task force said.

FERC Order 842, issued in February 2018, requires all new generators seeking interconnections be equipped to provide primary frequency response. (See FERC Finalizes Frequency Response Requirement.)

The EIPC task force tested three frequency events against the 2022 SLL Multiregional Modeling Working Group (MMWG) power flow case:

  • The loss of 4,500 MW of generation in 2007, the largest historical event seen on the EI;
  • The loss of 3,100 MW on April 27, 2011, the largest event within the past 10 years; and
  • The loss of 2,513.7 MW, the most severe single contingency for the EI as defined by NERC standard BAL-002-2(i) Requirement R2.2.

In all three events, frequency response fell no lower than 59.85 Hz, well above the 59.5-Hz initial set point that would trigger under frequency load shedding (UFLS).

Under a fourth benchmark — a 10,000-MW loss modeled to determine the margin available in the EI — the frequency dropped to a low of 59.64 Hz, still above the UFLS set point.

“In other words, the system inertia and primary frequency response will be sufficient even with expected retirements of synchronous generation and increases in nonsynchronous generation,” the report said.

The results of the analysis were submitted to NERC for inclusion in its 2018 long-term reliability assessment.

Comments Sought

David Lemmons, Ethos Energy, chairman of the standards development team for Project 2017-01 | © ERO Insider

On a related issue, the SDT for Project 2017-01(Modifications to BAL-003-1.1) on Thursday issued a request for comments following a three-day meeting last week in Atlanta.

Phase II of the project is considering potential changes to make the interconnection frequency response obligation (IFRO) calculations and associated allocations more reflective of current conditions, considering load response and the generation mix.

The standard authorization request also requires the team to ensure that overperformance by one entity does not negatively impact the evaluation of performance by another and that measurements of primary frequency response are considered in addition to secondary frequency response.

“I think we’ve got a fairly balanced industry [view]” on the standard, said SDT Chair David Lemmons, of EthosEnergy. “Some people think things need to change. Some people are happy with where it is.”

The SDT asked commenters to address the fact that load and generation data from Form 714 is two years old by the time it is applied to actual operations under the standard. In the interim, balancing authority (BA) footprints can change.

Greg Park, Northwest Power Pool | © ERO Insider

Rich Hydzik of Avista said Form 714 was adequate for use under the standard and expressed concern that more current data might be “less robust.”

“I don’t think we want perfection to be the enemy of good here,” he said. “What we’re looking for is a fair allocation on the interconnection and the BAs.”

Greg Park of Northwest Power Pool and SPP’s Daniel Baker noted Form 714 also does not include data from Mexico or Canada.

“I think [714] does an adequate job … 99% adequate,” Park said. “But that 1% is administratively burdensome.”

Hydzik suggested later the data source could be dictated by the “fundamental question” of whether it is generators alone that are responsible for meeting the frequency response requirement (FRR). He noted load reductions don’t provide much frequency response “unless generally you’re paying for load to drop.”

Daniel Baker (left), SPP, and Rich Hydzik, Avista | © ERO Insider

Including load strengthens the case for retaining Form 714, which includes load and generation data, he said.

“If you’re going to make the leap that energy-producing resources actually provide your FRR … then we kind of move into the situation where we look at generation-only numbers and … allocate that way. It starts to look a little bit like [Texas Reliability Entity] at that point. … They have shown us what it looks like to go with the generation approach.”

 

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UPDATED: PG&E Names New CEO, Board Members

By Hudson Sangree

Embattled PG&E Corp. named the outgoing head of the Tennessee Valley Authority as its CEO and assembled a “refreshed” board of 13 directors that includes a former FERC commissioner and a member of the Western Energy Imbalance Market’s Governing Body, the company announced Wednesday.

PG&E called the moves a response to safety concerns in the wake of catastrophic wildfires.

“We have heard the calls for change and have taken action today to ensure that PG&E has the right leadership to bring about real and dynamic change that reinforces our commitment to safety, continuous improvement and operational excellence,” PG&E said in a news release.

Critics said the changes didn’t go far enough.

“I’m not impressed,” said Assemblyman Chris Holden, chairman of the California State Assembly’s Utilities and Energy Committee. “I don’t see much in this collection that indicates that they are going to watch out for anything but their bottom line, but we’ll see. It appears the priority in this selection was protecting shareholders over ratepayers.”

PG&E was founded 114 years ago in San Francisco.

PG&E and its utility subsidiary Pacific Gas and Electric are undergoing a Chapter 11 bankruptcy reorganization after two years of massive wildfires left the companies facing billions of dollars in liability. The utility remains on criminal probation for its role in the San Bruno pipeline explosion of 2010. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)

Critics have called for major changes in the company’s safety culture, and some expressed concern Wednesday that PG&E’s new leadership might not be up to the task. The latest changes were backed by three hedge funds that hold large stakes in PG&E, The New York Times reported.

“While changes were made in the last few days to augment the safety and government expertise on the board, this proposed board still raises concerns — particularly the large representation of Wall Street interests and most board nominees’ lack of relevant California experience,” Nathan Click, a spokesman for California Gov. Gavin Newsom, said in a statement.

Bill Johnson | TVA

The changes announced Wednesday include the appointment of Bill Johnson as president and CEO. Johnson replaces former CEO Geisha Williams, who resigned before PG&E filed for bankruptcy protection in January. (See PG&E Says It Will File Bankruptcy, as CEO Steps Down.)

Johnson served for six years as head of TVA, the federally owned electricity supplier in the southeastern U.S. He was previously president of Progress Energy, which merged with Duke Energy in 2012. Johnson served as CEO of Duke for less than a day before leaving with a $44 million severance package, news outlets reported at the time.

“During Mr. Johnson’s time at TVA, the organization achieved the best safety records in its 85-year history and has been a perennial top decile safety performer in the utility industry,” PG&E said in its news release.

‘Objectively Failed’

The newly named slate of directors, which must be approved at PG&E’s next board meeting, is likely to face opposition from unhappy investors at the company’s annual shareholder meeting on May 21. BlueMountain Capital, a large PG&E shareholder, has assembled its own slate of directors led by former California State Treasurer and gubernatorial candidate Phil Angelides.

Phil Angelides | Financial Crisis Inquiry Commission

“People need to be clear about what this board is,” Angelides said. “After meetings in secret between PG&E and hedge fund investors, [PG&E announced this slate]. I don’t think anyone should be under an illusion that this represents a change from the current board or a change in the company.”

Nearly half the 13 named members are from hedge funds, Angelides said, and three are incumbents of a board that he said has “objectively failed.” PG&E “is in parole. It’s in bankruptcy. … This board does not bode well for the company or the people of California,” he said.

The utility needs directors with safety experience and green energy credentials, Angelides said. BlueMountain’s slate of candidates has such members — including Christopher Hart, a former chairman of the National Transportation Safety Board — though it will be an “an uphill battle to dislodge a company-nominated slate,” he said.

Angelides served as chairman of the federal Financial Crisis Inquiry Commission, which was charged with investigating the causes of last decade’s financial collapse.

PG&E’s newly named directors include former FERC Commissioner Nora Mead Brownell, who helped oversee the transition of NERC to FERC oversight during her term (2001-2006). Brownell, who later co-founded energy consulting firm ESPY Energy Solutions, also has served on the boards of directors of National Grid and Spectra Energy Partners and the advisory board of Morgan Stanley Infrastructure Partners.

Brownell did not respond to requests for comment Thursday.

Nora Mead Brownell | © RTO Insider

Kristine Schmidt, a member of the EIM Governing Body, was also named as a new PG&E board member. Schmidt worked as a technical adviser to Brownell at FERC. She is president of Swan Consulting Services.

Schmidt could not be reached for comment Thursday. The EIM referred an interview request to PG&E, which said “we’ll consider these sorts of requests once our new directors are onboarded.”

Cheryl Campbell, former senior vice president of Xcel Energy, was also named as a director Wednesday.

Other members of the updated 13-member board include three holdovers from the current leadership: Richard Kelly, the retired chairman and CEO of Xcel Energy and current chairman of PG&E’s board; Fred Fowler, retired chairman of Spectra; and Eric Mullins, co-CEO of Lime Rock Resources, a private equity oil and gas investment firm.

Investment and asset managers make up the remainder of the board, along with a diplomat and an attorney. PG&E said it hopes to confirm the new directors at its next in-person board meeting, “which will be held as soon as practicable,” the utility said.

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Stakeholders Tell PJM Board to Delay Capacity Auction

By Christen Smith

Stakeholders are urging PJM’s Board of Managers to reschedule the upcoming capacity auction, given the growing pile of issues on which FERC has not yet ruled.

The Joint Consumer Advocates sent a letter April 1 advocating for a temporary delay of the Base Residual Auction currently planned for August, contending it’s the best course of action to avoid possible legal and financial ramifications.

“If auctions are rerun, results refunded or other action taken, it is ultimately the end-use customers, including residential customers, who will bear those risks,” the group said. “These customers are least able to hedge against those risks.”

Likewise, a coalition of utility companies — including Exelon, American Municipal Power, Dominion Energy, EDP Renewables, Avangrid, NextEra Energy Resources, Public Service Enterprise Group and Talen Energy Marketing — said delaying the auction until April 2020 guaranteed the most time for stakeholders to adapt to any market rule changes handed down by FERC in the coming year. Seven dockets remain outstanding, the companies pointed out.

“By all public accounts, commission action does not appear imminent,” the utilities said in their March 29 letter to the board. “Given this inaction, the same concerns that led PJM to reschedule the 2022/23 BRA last August apply with equal force now. If anything, the need for clarity on auction scheduling is more severe now than it was last fall.”

| PJM

The letters come a week after PJM staff presented the Markets and Reliability Committee with four options for the August BRA, including do nothing and run the auction under current rules; file a delay waiver; file a request to confirm existing rules for the interim; or propose an interim rate. Each option came with considerable drawbacks, PJM’s Stu Bresler said during a March 21 MRC meeting. (See PJM Mulls Options for August Capacity Auction.)

It could be the second time PJM decides to delay the BRA after a June 2018 FERC ruling determined its minimum offer price rule (MOPR) was unjust and unreasonable. The RTO proposed a new rate in October and had hoped for a ruling from the commission by March 15 to no avail. (See PJM to FERC: Hurry Up with Auction Guidance.)

Although the utility companies want a delay of eight months — just six weeks before the regularly scheduled May 2020 BRA — consumer advocates want the briefest postponement possible, noting the competing interests of market participants, state utility commissions, legislatures and stakeholders.

“In that [first] waiver request, PJM stated that rescheduling the 2022/23 BRA was appropriate to allow stakeholders, PJM and FERC time to develop and establish appropriate replacement rules within a time frame that allows for the conduct of the BRA in an orderly manner,” the advocates said in their letter. “It is important that the PJM board not lose sight of these goals. PJM’s capacity market represents a large portion of the costs passed along to residential customers throughout the PJM footprint. Uncertainty in market rules and the permanence of market results can increase bids, which in turn increases costs.”

Bresler said PJM staff will reveal their decision for the auction at the April 10 meeting of the Market Implementation Committee.

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DOE Lab to Join PJM DER Integration Effort

By Christen Smith

The U.S. Department of Energy will collaborate with PJM to develop standards aimed at improving the integration of distributed energy resources onto the grid, the RTO announced Tuesday.

Under a new Cooperative Research and Development Agreement, Argonne National Laboratory will partner with PJM’s Distributed Energy Resource Ride-Through Task Force to study ride-through and trip guidelines from the Institute of Electrical and Electronics Engineers (IEEE) and adjust those rules to better serve PJM’s growing share of rooftop solar energy resources.

“Our primary mission is reliability, and we are preparing our system for the advent of more distributed energy resources so that we can seamlessly operate and understand DER behavior, both during normal operations and times of system stress,” said Chantal Hendrzak, executive director of Applied Innovation and Market Evolution for PJM.

“Our team has directly relevant experience in modeling and usage of simulation tools, and it has conducted similar analyses for the DOE and the North American Electric Reliability Corporation that can contribute to this joint effort,” said Ning Kang, an Argonne staff scientist who is leading the project with PJM.

| Cubit Power Systems

The lab also sent Rojan Bhattarai to work on site with the task force. He will analyze regional data, develop power system models with DERs and help PJM stakeholders fine-tune DER operational settings to maintain optimum system reliability.

Before the widespread adoption of DERs, the grid was designed to handle one-way power flows, with energy moving from generating plants through the transmission system, before being stepped down to the distribution system and ultimately transmitted to end-use consumers. The growing volume generation coming off the distribution network is forcing grid operators to rethink the system to accommodate unconventional flows.

PJM said DERs — including solar, battery storage, combined heat and power plants and some wind turbines — currently function on settings designed to respond to unexpected system malfunctions that disrupt power flow. Some sources “ride-through” the event, providing much-needed reliability, while others “trip-off” to prevent system damage. Solar panels and other DERs also can’t tell the difference between a transmission fault and a distribution fault, causing inappropriate responses and overstressing the system.

“For transmission system faults, DERs should stay connected to maintain reliability, while for distribution system faults, DERs should stop producing as fast as possible to ensure safety and protection,” Bhattarai said.

But there’s a key problem: DERs can’t detect where a fault occurred.

“So the challenge for PJM and others is to find a middle ground and come up with one set of operating rules that can ensure DERs function properly for faults on both the transmission and distribution side.”

The IEEE last year updated its standard for voluntary DER interconnection (IEEE 1574-2018), which informs trip and ride-through settings, but — as PJM acknowledges — “offers a fair amount of leeway,” leading utilities to implement different required settings.

“The combined PJM-Argonne team will study the impact of DER trip and ride-through timing in the current IEEE standard to help PJM stakeholders reach a consensus on DER integration,” PJM said. “It will also inform the technical guidance that utilities and states can use to implement DERs across the region PJM serves.”

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ISO-NE Filing, Whitepaper Address Energy Security

By Michael Kuser

A new ISO-NE whitepaper attempts to chart a course for the RTO to develop new market-based solutions to overcome New England’s long-term energy security challenges.

The RTO issued the whitepaper to the New England Power Pool Markets Committee just a week after filing an interim proposal with FERC to address winter energy security for the commitment periods covered by Forward Capacity Auction 14 (2023/24) and FCA 15 (2024/25).

The nearly 400-page interim plan calls for a voluntary two-year program to “provide incremental compensation to resources that maintain inventoried energy during cold periods when winter energy security is most stressed” (ER19–1428).

The RTO made the filing despite last month’s rejection of the proposal by the NEPOOL Participants Committee. Members also rejected a proposal by energy services firm Energy New England (ENE) that would have limited compensation to oil-fired and certain natural gas-fired resources, demand response and electric storage resources. (See ISO-NE Steady on Fuel Plan Despite NEPOOL Rebuff.)

New England natural gas flows | EIA

Pulling the Trigger

The RTO’s interim program consists of five core components, including a two-settlement structure, a forward rate, a spot rate, trigger conditions and a maximum duration for compensation.

Under the proposal’s two-settlement structure, resources would be paid or charged for deviations between the forward rate of $82.49/MWh for inventoried energy purchased in a forward position for the entire winter season and the spot settlement rate — $8.25/MWh — representing energy maintained during each trigger condition.

An “inventoried energy day” under the program is triggered for any day in December, January or February when the average of the high and low temperatures on that day, as measured at Bradley International Airport in Connecticut, is less than or equal to 17 degrees Fahrenheit.

The program’s maximum duration of 72 hours of generator compensation is designed to account for the incremental reliability benefit of another megawatt-hour of inventoried energy, decreasing as a resource maintains a greater quantity of inventoried energy, according to the filed testimony of Christopher Geissler, the RTO’s market development economist.

Adding another megawatt-hour of inventoried energy to a resource able to operate for 12 hours may improve the region’s winter energy security; however, if a resource has enough inventoried energy to operate for six months, then adding another megawatt-hour of inventoried energy “is unlikely to have a material effect,” Geissler testified.

Todd Schatzki, vice president of Analysis Group, testified on behalf of the RTO and estimated the program’s costs at $148 million per year, corresponding to approximately 1.8 million MWh of inventoried energy sold forward and maintained during trigger cold days throughout the winter.

“As these assumptions reflect maximum program participation, in a sense, this estimate provides an upper bound on the program’s potential costs, assuming forward settlement of all inventoried energy and no change in the region’s infrastructure,” Schatzki said.

Program participation may differ from assumptions, he said. For example, through lower-than-expected LNG contracting, resources may not supply the maximum eligible quantity of inventoried energy into the program, or resources may supply only a fraction of their capacity through forward settlement, which could lead to higher or lower payments if the number of very cold days differs from the number assumed in setting the forward settlement rate.

Fast and Easy, or Not

FERC in December approved the RTO’s initial Tariff revisions to use an out-of-market mechanism to address concerns about fuel security, filed after the commission in July denied a Tariff waiver to allow the RTO to enter a cost-of-service agreement to keep Exelon’s 2,274-MW Mystic plant running after its capacity obligations expire in May 2022.

The commission encouraged “ISO-NE to work with all interested parties, including NEPOOL, to continue to address their areas of disagreement while developing the long-term market solution.” (See ISO-NE Fuel Security Measures Approved.)

Ahead of NEPOOL discussions over the next six months on a long-term solution, the interim program first had to be simple enough to be designed and filed quickly, and not overly complex to implement, the RTO said.

Second, to be effective, the program should compensate resources that provide winter energy security. And third, “it should be designed consistent[ly] with sound market design principles, most notably providing similar compensation for similar service,” Geissler said.

Looking Ahead

The RTO’s whitepaper now looks at the region’s needs beyond FCA 15. To accommodate the complexity needed in a long-term solution, the document broadly recommends “expanding the existing suite of energy and ancillary service products” in the markets to address “the uncertainties and supply limitations inherent to a power system evermore reliant on just-in-time energy technologies.”

Three core components intended to spur discussion are a multi-day ahead market, new ancillary services in the day-ahead market and a seasonal forward market.

Many New England gas pipelines are subject to high capacity utilization rates, prompting ISO-NE to seek ways to ensure future fuel security for a grid increasingly dependent on just-in-time deliveries to gas-fired power plants. | EIA

The first would optimize energy, including stored fuel energy, over a multi-day timeframe and produce multi-day clearing prices for market participants’ energy obligations.

The second component would create several new, voluntary ancillary services in the day-ahead market to provide, and compensate for, the flexibility of on-demand energy.

The seasonal forward market would see the RTO conduct a voluntary, competitive forward auction to incent and compensate asset owners to invest in supplemental supply arrangements for the coming winter, the whitepaper said.

Referring to the paper, Marcia Blomberg, ISO-NE’s senior media relations specialist, said: “The ISO committed to posting this by April 1 to give stakeholders a basis for discussion as we work with them to refine the proposal to be filed at FERC by Oct. 15.”

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SMUD Goes Live in Western EIM

By Hudson Sangree

The Western Energy Imbalance Market continued expanding Wednesday as the Sacramento Municipal Utility District (SMUD) became the first publicly owned utility to begin participating in CAISO’s real-time electricity market for the West.

“The Western EIM demonstrates the economic and environmental savings achieved when participants work collaboratively across the region,” CAISO CEO Steve Berberich said in a news release. “As one of the premiere community-owned utilities in the country, SMUD’s participation will only strengthen the market and add to its efficiency and diversity.”

SMUD first announced its intent to join the EIM in October 2016. The nation’s sixth-largest community-owned utility, SMUD also is the largest member of the Balancing Authority of Northern California (BANC). Other BANC members — all publicly owned — may eventually join the EIM. (See SMUD Balancing Area Inks Agreement for EIM Membership.)

“BANC is excited to be the first publicly owned agency to become an EIM entity in the Western EIM,” BANC General Manager Jim Shetler said in the joint statement by CAISO, SMUD and BANC. “We found the CAISO staff to be extremely helpful in assisting us in what was a very smooth transition effort. BANC is currently evaluating future participation by its other members.”

BANC, which began operations in 2011, is the third largest balancing area in California and the 16th largest of the 38 balancing areas in the Western Electricity Coordinating Council. Created as an alternative to CAISO, BANC is responsible for balancing load among its members, as well as coordinating system operations with neighboring balancing areas. BANC contracts with SMUD to perform day-to-day balancing functions.

BANC also serves the Modesto Irrigation District, Redding Electric Utility, Roseville Electric Utility, the city of Shasta Lake and the Trinity Public Utilities District. The BA includes a portion of the Western Area Power Administration’s transmission grid and the U.S. Bureau of Reclamation’s hydroelectric resources in California. The agency’s members control capacity on the California-Oregon Intertie, one of two high-voltage transmission lines linking California with the Pacific Northwest.

In its latest statement of benefits, the EIM said its participants have saved nearly $565 million in the five years since the market started. Shifting electricity from where it’s overabundant to areas that need it has increased efficiency and allowed the growth of renewable resources, proponents contend. (See Sacramento Utility to Join EIM; Other BANC Members May Follow and SMUD to Join EIM in Spring 2019 at the Earliest.)

CAISO says the EIM has cut carbon emissions by more than 324,000 metric tons since its 2014 launch by replacing electricity generated from fossil fuels with energy from wind, solar and hydropower resources.

In addition to CAISO, the EIM’s other members are PacifiCorp, NV Energy, Arizona Public Service, Puget Sound Energy, Portland General Electric, Idaho Power and Powerex. Entities scheduled to begin participation next year include Seattle City Light, the Los Angeles Department of Water and Power and Arizona’s Salt River Project.

Montana’s NorthWestern Energy is planning to join the EIM in 2021. Public Service Company of New Mexico was hoping to join by 2021, but recent regulatory delays have cast doubt on that timing. (See PNM’s Bid to Join Western EIM Gets Approved in Part.)

The EIM serves areas in Washington, Oregon, California, Nevada, Idaho, Wyoming, Utah and Arizona.

“SMUD sees significant financial, operational and resource value in participating in the Western EIM due to its broader regional scope and dispatch,” SMUD CEO Arlen Orchard said in Wednesday’s statement. “The EIM’s geographic diversity allows easier and more economical balancing and integration of intermittent renewable energy resources, helping SMUD meet its and California’s aggressive renewable and carbon-reduction goals.

“SMUD is pleased to have forged this important partnership with the CAISO and the other EIM participants to further these goals.”

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FERC Rejects CAISO RA Incentive Change

By Hudson Sangree

FERC on Monday rejected a plan by CAISO to modify an exemption to its Resource Adequacy Availability Incentive Mechanism (RAAIM) that it grants to variable energy resources such as wind and solar (ER19-951).

“CAISO proposed RAAIM as a way to provide incentives to resources to meet their resource adequacy must-offer obligations through a series of incentive payments and charges,” FERC explained. “CAISO also proposed to exempt certain resources from RAAIM, including variable energy resources,” so that they wouldn’t be unfairly penalized for weather and other natural circumstances beyond their control.

FERC accepted CAISO’s exemption for variable energy resources in October 2015 (ER15-1825).

On Jan. 31, CAISO asked to alter the exemption by referencing “participating intermittent resources” and “eligible intermittent resources” instead of “variable resources.” The ISO said the change would clarify the exemption because only solar and wind currently can qualify as participating intermittent resources. The proposed change was a product of CAISO’s Commitment Cost Enhancements Phase 3 (CCE3) initiative.

CAISO is headquartered in Folsom, Calif. | CAISO

“CAISO explains that it has no approved forecasting methodology for other resource types besides wind and solar, and thus it has not offered RAAIM exemptions for them,” the commission said.

Pacific Gas and Electric protested, saying CAISO’s proposed changes would unfairly exclude certain variable energy resources from the RAAIM exemption, including run-of-river hydroelectric plants that don’t have dams and reservoirs.

“PG&E asserts that this proposal would discriminate unjustly and unreasonably against certain types of variable energy resources without adequate justification,” FERC wrote. “PG&E explains that certain hydro resources, such as run-of-river hydro, operate similarly to wind and solar in that there is no storage capability, and, thus, no ability to optimally choose when to generate.”

In response, “CAISO asserts that these terminology revisions maintain existing application of the bidding and RAAIM exemptions for wind and solar resources … [and] that forecasting run-of-river hydro resources is outside the scope of this proceeding.

“Further, CAISO argues that because its revision maintains the status quo … [it] will have no practical impact because the terms ‘variable energy resource’ and ‘eligible intermittent resource’ are interchangeable.” The changes would substitute more concrete terms for a generic one, CAISO said.

FERC decided it wouldn’t accept the wording change because the ISO had failed to show it wasn’t preferential or discriminatory.

When it previously accepted the ISO’s proposed RAAIM exemptions, it was so variable resources wouldn’t be unfairly penalized, FERC wrote.

“In this filing, though, CAISO proposed to limit eligibility for the RAAIM exemption based on whether CAISO has developed a forecast methodology for that resource,” the commission said. “This approach to determining eligibility for the RAAIM exemption is not consistent with the reasoning CAISO originally offered in support of its proposal, and with which the commission agreed.”

The commission did accept a handful of other Tariff revisions related to the ISO’s CCE3 and Reliability Services initiatives, including the following:

  • a provision stating resource-specific information that resource owners provide for inclusion in CAISO’s master file of resources must accurately reflect the design capabilities of a resource when operating at maximum sustainable performance over minimum run time, recognizing that performance may degrade over time;
  • revisions clarifying the integration dates for opportunity cost adders stemming from the CCE3 proposal; and
  • provisions clarifying the bidding obligations of resources with limited availability.
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MISO Closer to Clearing Up Queue Extension

By Amanda Durish Cook

FERC on Monday conditionally accepted MISO’s second attempt to address an inherent conflict within its Tariff related to the termination of generator interconnection agreements (GIAs) (ER18-2054).

The conflict stemmed from a discrepancy between what was laid out in MISO’s generator interconnection procedures (GIP) and its pro forma GIA.

In an October 2017 order, FERC found that a provision in the GIA allowing interconnection customers to extend the commercial operation date (COD) of a project by up to three years without facing termination conflicted with a GIP provision stating a COD extension required a material modification of the interconnection request — or the project risked removal from the queue. The discrepancy was discovered when the Merricourt wind project in North Dakota sought to extend its COD under a GIA with Montana-Dakota Utilities and MISO.

In mid-2018, FERC directed MISO to make a second Tariff filing clarifying an interconnection customer can extend its COD by up to three consecutive years before risking withdrawal from the queue. (See FERC OKs MISO Revision of Queue Termination Rules.) At the time, FERC directed MISO to “provide clarity as to the three-year period that must lapse before MISO must seek to terminate a GIA for failure of a generating facility to achieve commercial operation by the [COD].”

MISO’s updated Tariff language clarifies that an interconnection customer’s project has up to three years beyond its original COD to begin generating or risk removal from the interconnection queue.

The GIP now explains that once a GIA is executed or filed unexecuted, “if the generating facility fails to reach commercial operation by the [COD], such [COD] may be extended by [the] interconnection customer for a period up to three consecutive years, after which [the] transmission provider shall terminate the GIA if the generating facility has still failed to reach commercial operation.”

In its filing, MISO relayed concerns that the new GIP language could inadvertently allow a maximum six-year extension to a generating facility’s COD by creating a three-year maximum extension that is “distinct” from the same three years allotted in the GIA. That could occur when a project’s timeline is jeopardized by a change in milestone fees by another party to the GIA, a change in a higher-queued interconnection request and delays in MISO studies; and when an interconnection customer can show that engineering, permitting and construction will take longer than the definitive planning phase allows. None of the four exceptions amounts to a material modification under MISO Tariff.

FERC agreed with MISO that the language could be construed as creating an “additive” three-year extension that is “distinct from, and in addition to, the three-year extension that an interconnection customer may receive if it qualifies for any of the four exceptions.”

To avoid that reading, the commission Monday directed MISO to make a further compliance filing to reference that the new GIP language is consistent with the provision in its pro forma GIA that limits the COD extension to three years.

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More Info Needed on MISO Storage Participation Plan

By Amanda Durish Cook

MISO must flesh out more details around its already lengthy proposal for allowing energy storage resources to participate in its markets, FERC said Monday.

In an April 1 letter requesting more information on the plan, FERC said it could not process MISO’s Order 841 compliance filing until it clarifies several points regarding its phased participation approach, proposed commitment statuses, complexities for storage resources on the distribution system, conflicting offers and bids and make-whole payments (ER19-465). MISO has 30 days to respond.

FERC Order 841 requires RTOs and ISOs to revise their market participation models to allow storage resources 100 kW and larger to provide the capacity, energy and ancillary services they are technically capable of providing. MISO and its stakeholders spent the better part of last year negotiating rules that culminated in a 1,300-page filing. (See MISO Offers Storage Proposal, Promises to Exceed Order 841.)

In its compliance filing, MISO said it “anticipates significant uncertainty and risks related to the ability of MISO’s system and software to handle the participation of large numbers of very small” energy storage resources. The RTO asked for a “phased approach in the accommodation of very small” storage resources that would limit participation of small storage resources to 50 in the first year of compliance and 150 in the second year.

MISO said that approach would give it time to “further develop and fine-tune its system and software to be able to handle potentially increasing numbers of very small” storage resources.

But FERC directed MISO to specify what year it expects to provide market access to all storage resources that meet the 100-kW minimum threshold.

MISO must also explain how its must-offer requirement is affected when storage resources elect to use the RTO’s proposed dispatch status of “not participating” or other commitment statuses, the agency said. MISO’s filing proposed owners of storage resources could choose between several commitment modes, including charge, discharge, continuous, available, not participating, emergency charge, emergency discharge and outage. MISO has said its discharging, charging and continuous modes will carry must-run designations.

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FERC said MISO must clarify whether it proposes to levy transmission charges on storage resources when they are charging to resell energy later. MISO must also explain how it will help storage on the distribution system from making double payments — at both retail and wholesale — for charging energy.

FERC also asked if MISO would propose metering practices to manage the “complexities” of selling energy to a storage resource that will then resell the energy at the wholesale LMP.

MISO’s proposal requires storage owners to secure agreements with distribution companies that can deliver stored energy to the transmission system. However, FERC asked if MISO would require the same agreements when energy is moved from the transmission system to distribution-level storage, and it asked the RTO to explain a provision that prohibits distribution-level storage resources from pseudo-tying into a different balancing authority.

The agency also told MISO to cite Tariff provisions that will allow owners of storage resources to self-manage their state of charge.

FERC additionally said if MISO were to rely on existing Tariff provisions for a storage participation model, it should provide the commission with citations to the applicable market rules and pseudo-tie requirements for transmission-level resources. MISO must also describe how its filing will give storage resources access to all capacity, energy and ancillary service markets, as well as non-market services such as black start, primary frequency response and reactive power.

FERC told MISO to explain how its filing will prevent the same resource from submitting conflicting supply offers and demand bids for the same market interval. It also seeks to know if the participation model allows for make-whole payments when a resource is dispatched as load and the wholesale price is higher than the bid price and when a resource is dispatched as supply and the wholesale price is lower than the offer price. The commission also asked if resources available for manual dispatch will be eligible for make-whole payments.

Finally, FERC asked MISO to cite how its compliance filing will allow storage dispatched as supply and demand to set the wholesale market clearing price as both a wholesale seller and buyer, as Order 841 dictates. The agency also asked for citations to support that storage resources can set the price in the MISO capacity market, that MISO will accept wholesale bids from storage owners and that self-scheduled storage resources can participate in the market as price-takers.

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FERC OKs MISO Outage Scheduling Rules, DR Testing

By Amanda Durish Cook

CARMEL, Ind. — FERC on Friday granted MISO permission to implement the remaining two proposals in its three-part short-term resource availability and need project.

Facing baseload generation retirements, more frequent emergencies and diminishing capacity margins, MISO had proposed stricter outage scheduling rules and annual real power testing for demand response. FERC said MISO could implement both provisions, though it wants the RTO’s Maintenance Margin tool chronicled in its Tariff.

In February, FERC approved a MISO proposal requiring owners of load-modifying resources to provide firmer and more clearly documented commitments regarding their availability. (See MISO LMR Capacity Rules Get FERC Approval.)

Taken together, the three filings are geared toward freeing up an additional 10 GW of supply as MISO navigates its spring maintenance outage season and the arrival of warm weather.

Stricter Outage Planning

MISO can now impose new generator accreditation penalties for planned outages taken during what it deems “low margin, high risk periods” (ER19-915). RTO staff have said the rules will incent the forward scheduling of planned generation outages.

FERC approved the proposal effective Monday and said it expected the rules will promote advanced scheduling, improve outage coordination and help MISO address its recent spate of shoulder period emergencies.

“MISO’s proposed Tariff revisions add specificity and incentives to the Tariff’s existing provisions governing the scheduling of generator planned outages,” FERC said.

MISO generation resources now must provide 120 days’ notice for planned outages. However, outages scheduled between 14 and 119 days in advance will be exempt from the RTO’s accreditation penalties, provided the outages are scheduled during predefined periods with adequate margins. Generator planned outages and derates scheduled fewer than 14 days in advance and occurring during a declared maximum generation emergency would be subject to accreditation penalties. The proposal also provides safe harbor provisions for resources that adjust a planned outage at MISO’s request.

The RTO also has instituted a transition period to the new set of outage rules. Outages scheduled prior to April 1 will not be subject to the accreditation penalty, while requests and revisions submitted April 1 and beyond for outages starting April 15 through July 29 would be exempt from the penalty if the request is submitted no later than 14 days in advance and MISO foresees “adequate projected margin at the time of the request.” The full set of outage requirements will go into effect for outages scheduled to start July 30 or later.

MISO said that although it has so far managed generation outages through voluntary rescheduling, “there has been a significant increase in the number of maximum generation emergencies that are at least in part driven by highly correlated generator planned outages.” The RTO said only 30% of planned outages are scheduled 120 days or more in advance, with most being scheduled just weeks in advance.

A group of state regulators and Prairie Power argued that MISO wasn’t providing enough detail into what load forecasts it uses in its Maintenance Margin tool, the nonpublic webpage the RTO maintains to help members schedule outages during adequate supply conditions.

The two also contended that MISO mischaracterized the accreditation penalty as an “incentive”; violated its stakeholder process by allowing just 11 days for stakeholders to review the final proposal; and that the proposal “ignores the real world of utility operations” in which previously unknown problems can be uncovered as equipment is disassembled. Indiana Municipal Power Agency and Southern Minnesota Municipal Power Agency also derided the 14-day deadline as “arbitrary.”

But FERC said the tiered approach “provides MISO with the forward transparency it seeks, reduces the risks associated with correlated [outages] and maintains sufficient flexibility for generator owners to schedule their [outages] without risk of an accreditation penalty.” FERC also pointed out that outages scheduled fewer than two weeks in advance aren’t automatically subject to an accreditation penalty unless the outage occurs during an emergency.

However, FERC agreed with WEC Utilities and American Municipal Power that MISO needs to define the Maintenance Margin in its Tariff. The tool “is the sole factor in determining whether there is an ‘adequate projected margin’ under the proposed Tariff revisions,” FERC said, and as such, should be recorded in the MISO Tariff.

“We find that the Maintenance Margin can have a significant impact on rates, terms and conditions of service,” the commission said, directing MISO to make a compliance filing by the end of April.

Real Power Testing for DR

FERC on Friday also approved MISO’s proposal to require annual actual power tests from its DR resources (ER19-651).

The RTO had asked for permission to conduct the tests to get more certainty about resources’ ability to perform when needed during tight operating conditions.

At MISO’s recent Board of Directors week in New Orleans, RTO executives said the move will put DR on a more level playing field with other resources, which are already beholden to the annual power tests.

DR resources that complete the annual testing will receive credit for one of the five deployments required of them in a planning year. MISO has said that resources that are deployed and follow all scheduling instructions in a planning year will not be subject to the testing in the following year.

MISO has also said it will waive the testing requirements for DR resources “that are subject to regulatory restrictions that preclude testing.” Additionally, a DR resource that simply wants to opt out of testing can do so, provided it agrees to pay MISO three times the cost of demand reduction for non- or underperformance.

Some MISO member companies protested the filing, arguing that the RTO failed to justify the need for annual testing; the testing would cause DR to exit the market; the proposed penalty cost was arbitrarily punitive; and an annual testing requirement would result in increased production costs and risk to equipment.

But FERC disagreed on all fronts.

“To the extent that MISO’s proposal increases costs on demand resource owners, they can reflect those costs in their submitted offers into the auction,” FERC said.