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.