Published: November 8, 2024
By Concentric Staff Writer
After over-riding its membership, on November 4, the national organization responsible for the reliability of the bulk power grid filed with federal energy regulators a suite of proposed new standards for inverter-based resources (IBRs) such as solar, batteries, and wind, to address problems with these systems in recent years.
On November 4, the North American Electric Reliability Corporation (NERC) made four separate filings to the Federal Energy Regulatory Commission (FERC) related to IBRs. NERC filed a petition for approval of two standards related to IBR ride-through performance during system disturbances (PRC-024-4, PRC 029-1); another requiring analysis and mitigation of IBR performance issues (PRC 030-1); a petition for approval of the proposed definition of the new term “Inverter-Based Resource”; and another establishing requirements of disturbance monitoring requirements for IBRs (PRC-028-1 and PRC-002-5).
“The proposed reliability standards are an integral part of NERC’s proposed framework to address IBR performance issues in a comprehensive and holistic manner,” the organization said in the filing for disturbance monitoring requirements for IBRs. “[T]he proposed reliability standards are part of a set of standards that collectively respond to the Commission’s directives for requirements addressing IBR ride-through settings, ride-through performance, data recording, and analysis and mitigation of unexpected IBR performance,” NERC said.
NERC said there has been widespread loss of generating resources—solar photovoltaic, wind, synchronous generation, and battery storage—across multiple “system events.” For example, the Blue Cut Fire in August 2016 in San Bernardino County, California, and the Canyon 2 Fire in October 2017 in Orange County, California, demonstrated a risk to grid reliability as IBRs were unable to ride-through the events. In 2022, NERC analyzed more than 10 grid disturbances involving widespread loss of IBRs, it said.
FERC in its Order No. 901 [RM22-12], approved in October 2023, had required NERC to file the IBR standards by Nov. 4 of this year. After disagreement among members, the NERC Board of Trustees in October invoked the special authority in order to allow the organization to meet the deadline, it said.
That lack of consensus led a NERC committee during an earlier August meeting to recommend that the board invoke its special authority “to ensure that systemic reliability issues associated with IBRs are addressed in a timely manner,” according to NERC documents.
In the Western Interconnection — the power grid that spans several western U.S. states, Canada, and parts of Mexico —IBRs are on the upswing, but they have introduced a number of challenges to reliability. IBRs lack the physical inertia that is inherent to traditional synchronous resources such as coal, gas, and nuclear, creating problems such as fault-induced delayed voltage recovery. IBRs also have trouble with the frequency response that traditional generation provides to the grid.
NERC’s Board of Trustees at an October 8 technical conference successfully revised the IBR standard, allowing it to be approved under a reduced voting threshold compared to its normal voting procedures. At an August meeting in Vancouver, NERC membership was unable to reach consensus on how stringent the standards should be.
FERC’s Order No. 901 required NERC to file the standards on a three-year staggered time frame. The commission required NERC to file IBR disturbance-monitoring data sharing, post-event performance validation, and ride-through performance requirements by November 4, 2024; IBR data and model validation by November 4, 2025; and planning and operational studies for IBRs by November 4, 2026. The Commission also directed NERC to develop and submit a work plan to develop new and revised reliability standards to address the IBR issues in accordance with that timeframe.
According to minutes from the October 8 NERC technical conference, Board of Trustees member Kenneth DeFontes recommended that the board use the special authority in order to file the standards in compliance with FERC’s November 4 deadline.
“[DeFontes] reported that while much of the hard work of NERC’s stakeholders is paying off, with progress made on important IBR reliability standards through the usual standard development process, NERC does not have a clear path forward on the IBR grid disturbance ride through standard,” the minutes say.
DeFontes said the board must consider its options to meet its regulatory responsibilities but noted that the board “does not consider these options lightly.” He also recommended continued participation by NERC members and industry representatives on the standard.
The board approved a package of Milestone 2 standards for IBR “ride-through,” which refers to the capability of solar, wind, and battery devices to continue operating during temporary disturbances or faults on the electrical grid. Inverters will ride-through the disturbance and remain connected to the grid instead of disconnecting immediately when voltage or frequency deviates from normal ranges.
The Milestone 2 standards were approved under NERC’s Project 2020-02, an initiative to develop and update standards for IBRs. NERC had identified that there was a gap in existing reliability standards, which were developed for traditional synchronous generation resources such as coal, gas, and nuclear.
The goals of Project 2020-02 are to update existing standards such as protection and controls, modeling, data, and analysis to make them more suitable for IBRs. These include requirements for more accurate modeling, performance verification, and coordination of protection systems. The initiative also has the goal of defining and enhancing ride-through requirements to establish clear and consistent requirements for IBRs to ride through system disturbances without tripping off.
NERC also has the goal of ensuring an accurate representation of IBRs in grid models, seen as critical for planning and analysis of operational reliability. This includes requirements for verifying that IBR models reflect their performance in the real world.
NERC’s Project 2020-02 included modifications to the PRC-024-4 standard and the development of the PRC-029-1 standard to initiate its development (frequency and voltage ride-through requirements for inverter-based resources), but the latter standard failed to achieve consensus through the usual standard-development process, NERC said.
The NERC board discussed issues surrounding the FERC Order No. 901 directives, including whether or not the proposed reliability standard PRC-029-1 is “just, reasonable, not unduly discriminatory or preferential, in the public interest, helpful to reliability, practical, technically sound, technically feasible, and cost-justified,” according to a NERC memorandum.
On Jan. 17, NERC also submitted its Order No. 901 work plan, which consists of key milestones to meet the FERC directives by the filing deadlines. The Milestone 2 standards, in progress, focus on the development of reliability standards to address disturbance monitoring, performance-based ride-through requirements, and post-event performance validation for registered IBRs by the Nov. 4 deadline.
While Project 2020-02, which addressed generator ride-through directives from FERC Order No. 901 had created controversy, Projects 2021-04 and 2023-02 are on track for timely completion through the usual NERC standard development process, the memorandum says.
FERC’s Order No. 901 cited multiple reports of events with IBRs as the reason NERC should have reliability standards for ride-through frequency and voltage system disturbances. The standards should permit tripping of IBRs only to protect the IBR equipment in scenarios similar to when synchronous generation resources use tripping as protection from internal faults, FERC said. Exceptions should be applied to certain IBRs, and finding consensus around those directives was a part of the main issues addressed during the technical conference, according to NERC.
FERC said NERC must require registered IBRs to continue to perform frequency support during any bulk-power system disturbance and that any new or modified reliability standard must also require registered IBR generator owners and operators to prohibit momentary cessation in the no-trip zone during disturbances.
Under FERC’s order, NERC was required to submit new or modified reliability standards that establish IBR performance requirements, including requirements addressing frequency and voltage ride-through, post-disturbance ramp rates, phase lock loop synchronization, and other known causes of IBR tripping or momentary cessation.
“Therefore, we direct NERC through its standard development process to determine whether the new or modified reliability standards should provide for a limited and documented exemption for certain registered IBRs from voltage ride-through performance requirements. Any such exemption should be only for voltage ride-through performance for those existing IBRs that are unable to modify their coordinated protection and control settings to meet the requirements without physical modification of the IBRs’ equipment,” FERC said in the order.
During deliberations among NERC members, many argued that the proposed PRC-029-1 definition was too broad and ambiguous, particularly the inclusion of phrases like “entire” and “in its entirety,” when referring to a generating plant or facility. Those parties recommended revisions to clarify the definition and ensure it aligns better with Institute of Electrical and Electronics Engineers Standard 2800, which covers interconnection and interoperability of IBRs, and interconnection with associated transmission systems.
Project 2020-02 will enhance reliability by requiring entities to perform energy reliability assessments to evaluate energy assurance and develop corrective action plans to address identified risks, NERC said. These energy reliability assessments should evaluate energy assurance across operations planning, near-term transmission planning, and long-term transmission planning or equivalent time horizons by analyzing the expected resource mix availability and flexibility and the expected availability of fuel during the study period.
According to NERC, IBRs are still being designed and installed without setting their protection and controls in accordance with their physical capabilities.
NERC had solicited comments from the industry as well as original equipment manufacturers on any information on hardware-based limitations that would prevent IBRs from meeting the proposed frequency criteria within PRC-029-1. The organization said 21 individual comments were received, including six from different original equipment manufacturers of IBRs. There were concerns that a draft of PRC 029-1 proposed frequency criteria that went beyond those established in IEEE 2800-2022 and there was a concern that IBR operators would not be able to meet those proposed frequency criteria, as IBR capability limits were hardware-based and inherent to manufacturer design.
Though the organization had failed to reach consensus among its members on some of the standards, the filing of NERC’s new standards will hopefully address the issues with IBRs that have raised their head in the Western Interconnection in recent years.
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All views expressed by the contributors are solely the contributors’ current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The contributors’ views are based upon information the contributors consider reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
Published: October 3, 2024
By: Concentric Staff Writer
Interconnection queue backlogs around the country are making it much more challenging to develop new generation projects, such as zero-emission resources needed to meet national decarbonization goals.
However, Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs) that manage massive electrical grids around the country are responding, as is the federal government, to address the problem and make reforms. A key element of this response is Federal Energy Regulatory Commission (FERC) Order 2023, issued in July 2023, which aims to address interconnection queue backlogs, improve certainty for developers and others, and prevent undue discrimination towards new technologies.
Danielle Powers, Chief Executive Officer at Concentric Energy Advisors, is working on the front lines of the issue. Part of the solution, according to Powers, is to implement stricter requirements for demonstrating project “readiness” in order to decrease the number of speculative projects entering the interconnection queues.
“The independent system operators are taking steps to make the commitment to entering the queue more real, in terms of physical control and deposits, penalties or withdrawal fees,” Powers said.
A major concern that remains is the inability of many projects in interconnection queues to get built due to siting difficulties. This remains a challenge in ensuring that the resources needed to meet reliability and public policy goals actually get built.
Other than new zero-emission projects such as solar, solar/battery, and wind, other infrastructure such as data centers and electric vehicle charging stations are increasing demand at a time when an increasing amount of variable-output energy resources are being added.
In interconnection queue processes performed by ISOs, RTOs, and individual utilities, projects seeking interconnection must undergo a series of studies before they can be built. The studies determine which network upgrades are needed to interconnect, and the associated costs. Projects must also meet certain milestones and make payments to stay in the queue—the list of projects waiting to interconnect.
With the massive build-out of renewable generation happening on the U.S. grid, there were about 12,000 projects representing 1,570 GW of generator capacity and 1,030 GW of storage seeking interconnection at the end of 2023, according to Lawrence Berkeley National Laboratory (LBNL). Solar, storage, and wind projects make up about 95 percent of capacity in queues around the country.
Among a subset of queues for which data are available, about 19 percent of projects, or 14 percent of the capacity requesting to interconnect between 2000 and 2018, reached commercial operation by the end of 2023, LBNL said in its “Queued Up: 2024 Edition” report. Solar projects had a 14 percent completion rate, and storage projects had an 11 percent completion rate.
The average time projects spent in queues before being built has increased sharply, with the typical project built in 2023 taking about five years from the interconnection request to commercial operation, compared to three years in 2015 and two years in 2008, LBNL said.
FERC’s Order 2023 is meant to develop a new approach to interconnection as massive amounts of new resources come online.
“The growth of new resources seeking to interconnect to the transmission system and the differing characteristics of those resources have created new challenges for the generator interconnection process,” FERC said in the Order. “These new challenges are creating large interconnection queue backlogs and uncertainty regarding the cost and timing of interconnecting to the transmission system, increasing costs for consumers.”
Backlogs in interconnection queues also create reliability concerns, FERC said, as new generating facilities are unable to come online in an efficient and timely manner. More reforms are needed even after the issuance of FERC Order No. 845 , the agency said. FERC Order No. 845 adopted “reforms that are designed to improve certainty for interconnection customers, promote more informed interconnection decisions, and enhance the interconnection process.” FERC said.
Order No. 2023 implemented a “first-ready, first-served” cluster study process, which FERC said increases access to information prior to entering the queue; creates a mechanism to study interconnection requests in groups where all interconnection requests in the groups are equally queued and of equal study priority; and increases financial commitments and readiness requirements to enter and proceed through the queue.
The rule requires transmission providers to publicly post available information pertaining to generator interconnection and developers to use cluster studies as the interconnection study method.
The rule also requires transmission providers to allocate cluster study costs on a pro rata and per capita basis and to allocate network upgrade costs based on a proportional impact method. Interconnection customers must pay study and commercial readiness deposits as part of the cluster study process, as well as demonstrate site control at the time of submission of the interconnection request.
Transmission providers must also impose withdrawal penalties to interconnection customers for withdrawing from the interconnection queue, with certain exceptions. FERC also required transmission providers to adopt a transition process to move from the existing serial interconnection process to the new cluster study process.
Order no. 2023 will “increase the speed of interconnection queue processing and incorporate technological advancements into the interconnection process,” FERC said.
In the Pacific Northwest, the Bonneville Power Administration (BPA) switched to a “first-ready, first-served” interconnection queue process, a change from the “first-come, first-served” approach it previously used. Developers now must show they have site control and meet commercial-readiness requirements that include a cash deposit, an irrevocable letter of credit, or a deposit into an escrow account. BPA had 376 projects in its queue as of June, according to BPA materials.
In California, where a substantial amount of new zero-emission resources are coming online, queue reforms are underway to address the fact that only about 10 percent of projects in the queue come to fruition. Developers are faced with extremely long timelines for project development and a “stop-start” situation that makes it difficult in terms of site security, financing, and other areas.
CAISO’s normal level of about 113 interconnection requests per year grew to 373 in 2021, with more than 150 GW of projects sitting in its Cluster 14. CAISO went as far as requesting that FERC pause new interconnection requests, which FERC approved in March.
CAISO launched a series of reforms known as its Interconnection Process Enhancements, which it said were needed to avoid CAISO becoming out of compliance with Order. No. 2023 or being forced to file for a waiver. CAISO filed the tariff changes for the enhancements with FERC on Aug. 1.
“The CAISO interconnection queue now contains more than three times the capacity expected to achieve California public policy objectives for the next two decades and far exceeds the ability of available and planned transmission to deliver power from all of these projects to customers,” CAISO said in the filing.
CAISO said its reforms maintain open access in the region and that the ISO will now identify the most viable and needed projects and allow them to advance through the queue. This will be done in zones with sufficient transmission capacity, providing resource diversity and availability in the queue.
CAISO noted that clogged queues create “unsustainable strain” on planning and engineering resources and that interconnection study results lose accuracy, meaning, and utility when the level of interconnection requests far exceeds the existing or planned transmission capacity in a given area. It is impossible to allocate deliverability, or the transmission capacity needed to deliver a generator’s energy to load during various system conditions, to all of the interconnection requests currently in the CAISO queue, the grid operator said.
FERC, in November 2022, also approved an interconnection process reform filing by the PJM Interconnection, which covers 13 mid-Atlantic states and Washington D.C. The filing transitions PJM’s queue from a serial “first-come, first-served” approach to a “first-ready, first-served” approach.
PJM has expressed concern about having enough generation to meet demand. The interconnection queue reform process will help clear the backlog of requests and get generation online more quickly, PJM officials said. The effort includes a “Queue Scope tool” that allows resource developers to more effectively assess the engineering and financial impacts of a project at various locations on their own before they formally enter the interconnection queue.
PJM had about 62 GW of projects that completed its study process by the end of 2023 and expects that number to be about 100 GW by the end of 2025. However, in 2022, only about 2 GW of new projects came online, with only about 700 MW of that being renewables. The grid operator had about 265 GW of projects seeking to interconnect in 2023, about 95 percent of which were renewables.
Reforms are also underway in the Midcontinent Independent System Operator (MISO), which covers 15 states. FERC in February approved MISO’s filing to re-work its queue process, which includes increasing milestone payments, adopting an automatic withdrawal penalty, revising withdrawal penalty provisions, and expanding site control requirements. Historically, about 70 percent of projects in MISO’s queue have never come to fruition, resulting in the need to restudy projects with lower queue positions.
MISO increased its Milestone 2 (M2) payment from $4,000 per MW to $8,000 per MW; its Milestone 3 (M3) from the greater of 20 percent of network upgrade costs minus the M2 payment or $1,000 per MW; and its Milestone 4 payment to 30 percent of network upgrade costs minus M2 and M3 payments.
MISO increased Point of Interconnection (POI) site control requirements to 50 percent site control from generator site to POI upon application, or $80,000 per mile for the entire line mileage to POI. It also required 50 percent site control from generator site to POI and 50 percent of interconnection switchyard, if necessary, prior to Phase 2. 100 percent site control is required from generator to POI, including interconnection switchyard, if necessary, prior to the execution of a generator interconnection agreement or within 180 days of execution with an approved exception.
It also imposed a new escalating automatic penalty upon withdrawal and an adjustment to the calculation for harm imposed by a withdrawal. These range from 10 percent of the Milestone 1 payment at decision point 1 of the process to 100 percent of Milestone 2 during generator interconnection agreement negotiations.
“These reforms are needed to reduce the number of queue requests withdrawing from the process,” MISO said on its web site. “The fewer projects in studies, the quicker it takes to complete; the fewer projects that withdraw, the more certain phase 1 and 2 study results are.”
In Texas, the growth of interconnection requests was noted by Oncor CEO Allen Nye in a recent second-quarter earnings call, during which he noted that interconnection requests in Oncor territory increased by about 100, or 13 percent from the second quarter of last year. The Electric Reliability Council of Texas projects that its peak load in 2030 will nearly double to 152 GW, compared to the current record of 85.5 GW, which was set in August 2023.
As Concentric’s Chief Executive Officer, Danielle Powers, noted, it’s a bit soon to see how much of a difference the ongoing efforts at the federal level and by RTOs and ISOs to reduce interconnection queue levels will make, but it’s clear that much work is underway.
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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, related companies, or clients. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.
Published: July 20, 2023
By: Concentric Staff Writer
Officials of the Canadian province of Ontario said they are launching a new energy initiative to address growing electricity demand due to electrification using a variety of resources, reflecting electrification trends also occurring across the United States.
Energy Minister Todd Smith announced the plan on July 10, saying strong economic growth and trends such as electric vehicles create a need for new zero-emissions electricity generation, long-duration energy storage and new transmission infrastructure.
“Our government’s open for business approach has resulted in unprecedented investments and job creation, from electric vehicles and battery manufacturing to critical minerals to green steel,” Smith said in written statement. “Powering Ontario’s Growth lays out the province’s plan to build the clean electricity generation, storage, and transmission we need to power the next major international investment, the new homes we are building, and industries as they grow and electrify.”
New EV and battery manufacturing facilities from companies such as Stellantis, Volkswagen and Umicore are contributing to a rise in electricity demand in Ontario for the first time since 2005. Smith said the province is working with the steel industry to end usage of coal and to electrify operations to produce “green steel” in the cities of Hamilton and Sault Ste. Marie. The investments alone will increase electricity demand by eight terawatt hours, doubling the annual average energy use of the Ottawa region.
The province’s Independent Electricity System Operator (IESO) has recommended an early start to meet energy demands through 2030 while keeping costs low. The IESO’s Pathways to Decarbonization Report issued in December 2022 included one scenario for demand growth that could rise from 42,000 MW today to 88,000 MW by 2050.
Powering Ontario’s Growth includes a nuclear energy component, such as a plan to site 4,800 megawatts (MW) of new nuclear on the current site of the Bruce Power Nuclear Generating Station, already the largest operating nuclear plant in the world with 6,550 MW of capacity. Nuclear power currently provides about 50 percent of the province’s energy supply, and it is one of the cleanest grids in the world, officials said.
A second aspect of the new plan is competitive procurements of new clean-energy resources such as wind, solar, hydroelectric, batteries and biogas, while a third component calls for designating and prioritizing three new electric transmission lines: one to power Algoma Steel and other companies in Northeastern Ontario, one line in the Ottawa region and one across Eastern Ontario. The Energy Minister’s office said it would direct the IESO to conduct a report on transmission options to address system bottlenecks between Toronto, Northern Ontario, and into downtown Toronto, where growth is expected.
The province will also request Ontario Power Generation to optimize hydroelectric generation sites and assess proposed pumped storage projects in Marmora and Meaford to “improve grid efficiency.”
The new plan also aims to keep costs low by starting to plan for the future of energy efficiency programming to reduce demand and support the deployment of distributed energy resources such as rooftop solar and EV batteries.
“As our province moves toward an electric future with a strong end-to-end EV supply chain, there has never been a greater need for clean, affordable energy that companies can rely on. This plan brings us one step closer to being a world-leading energy powerhouse,” Ontario Minister of Economic Development Vic Fedeli said in a written statement, adding that the province has attracted billions of dollars in investment from domestic and international companies over the past 2 ½ years.
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All views expressed by the author are solely the author’s current views and do not reflect the views of Concentric Energy Advisors, Inc., its affiliates, subsidiaries, or related companies. The author’s views are based upon information the author considers reliable at the time of publication. However, neither Concentric Energy Advisors, Inc., nor its affiliates, subsidiaries, and related companies warrant the information’s completeness or accuracy, and it should not be relied upon as such.