MISO has selected Ameren Transmission Co. of Illinois (ATXI) to build a third transmission project stemming from the RTO’s long-range transmission portfolio.
ATXI will oversee construction of the $273 million Denny-Zachary-Thomas Hill-Maywood (DZTM) 345-kV project in Missouri, part of MISO’s first, $10 billion long-range transmission plan (LRTP) portfolio. It’s the most expensive project MISO has evaluated for competitive selection.
It’s the third time MISO has opted for ATXI after LRTP project solicitations. In December, MISO decided Ameren’s transmission arm will build a $23 million, 345-kV line segment from the Iowa-Illinois border to the Ipava substation in Illinois. (See MISO Selects Ameren, Dairyland to Build 3rd and 4th LRTP Competitive Projects.)
Last year, MISO also awarded ATXI construction rights on the $84 million, 345-kV Fairport-Denny project, which extends to the Iowa-Missouri state border and links up with the DZTM project. (See MISO Selects Ameren to Build 2nd Competitive LRTP Project.)
MISO’s DZTM selection announcement marks the final time MISO will compare bids on a competitive project from the first LRTP portfolio. Only five of the 18 projects were up for competitive solicitation.
MISO said ATXI “conducted the most engineering and surveying of any developer, and its routes had the least environmental impact.”
“It also more clearly detailed its construction activities and access plans, and showed how it could modify construction activities based on the in-service date of Denny substation,” MISO wrote in the selection report.
MISO said it received six proposals from four developers, including two from ATXI and the remainder from LS Power, NextEra Energy Transmission Midwest and Transource Energy, with implementation costs ranging from $265 million to $486 million. MISO originally estimated project costs would exceed $500 million. ATXI was the only developer that offered to cap project costs, MISO said.
“The selected proposal had a substantially lower cost than that of the next-closest developer,” Jeremiah Doner, MISO’s director of cost allocation and competitive transmission, said in a press release. “ATXI’s proposal also features strong cost containment, sound design, and robust operations and maintenance plans.”
The DZTM project encompasses two new single-circuit 345-kV transmission lines at 162 miles and a new, 42-mile 345-kV conductor-only circuit that will share structures with an existing 161-kV line. The project will connect four substations.
As with its Fairport-Denny project, ATXI’s DZTM proposal includes a partnership with The Missouri Joint Municipal Electric Utility Commission. ATXI plans to sell 49% of the project to the state utility agency before the project is placed into service.
SPP’s effort to impose new capacity accreditation methodologies for thermal and renewable resources has drawn protests from public-interest and clean-energy groups at FERC.
On March 29, the Sierra Club, Natural Resources Defense Council and Sustainable FERC Project challenged SPP’s proposed performance-based accreditation (PBA) for thermal resources, arguing it would threaten reliability by ignoring fossil-fired resources’ underperformance and renewables’ overperformance when power is needed most (ER24-1317).
The groups also filed a complaint under Federal Power Act Section 206 over existing accreditation methodologies for the resources SPP is trying to replace. They said the RTO’s current and proposed capacity accreditations create a competitive disadvantage for wind and solar and will increase prices for ratepayers as utilities are “artificially incentivized to overbuild gas resources and delay coal retirements.”
“Regulators at the federal and regional level must make sure that critical resource assessments are made based on the facts and that all resources are evaluated on a level playing field,” said Natalie McIntire, senior advocate at the Sustainable FERC Project and a member of SPP’s Members Committee. “Accurate accreditation will help ensure a reliable and more affordable grid and allow renewable resources to contribute to a clean, reliable and resilient electrical system.”
The Sierra Club said clean energy advocates have been pushing SPP to fix its accreditation methodologies, which it calls discriminatory and outdated, since at least 2021. It said the parallel filings were intended to avoid a return to the status quo and SPP’s flawed stakeholder process.
Separately, the American Clean Power Association, Solar Energy Industries Association, Advanced Energy United and Advanced Power Alliance also filed a protest urging the commission to reject the proposal. They said SPP’s filing included unjust and unreasonable design features, missed crucial information in violation of FERC’s rule of reason and unduly discriminated against IBRs.
SPP filed its proposed tariff revisions at FERC in February. They included an effective load-carrying capability (ELCC) methodology for wind, solar and energy storage resources. The grid operator also laid out the calculation to determine the metrics, a variant of the equivalent forced outage rate method.
The RTO’s proposal to use a different calculation for thermal resources is an “improvement on the status quo,” the renewable interests said. “However, this change alone (and taken in concert with SPP’s ELCC proposal) cannot meet SPP’s statutory burden to ensure that its filing is just and reasonable, and not unduly discriminatory.”
SPP said that accrediting resources is “critical” to its resource adequacy program, which FERC approved in 2018.
“It is not enough to have sufficient nameplate generation installed; the region needs assurance that such capacity will deliver at an expected output when the output is needed most,” SPP said, noting that grid operators have established accreditation methods valuing the resource adequacy contributions of different resource types.
SPP asked that FERC issue an order by May 23 and set an effective date of Oct. 1, 2025, for the methodologies’ implementation.
Members Endorse Controversial IBR Rule over ERCOT’s Objections
AUSTIN, Texas — ERCOT stakeholders overrode the ISO’s objections to push through a potential rule change on inverter-based resource (IBR) ride-through requirements after months of negotiations failed to bring a compromise.
The action sets up a likely appeal from ERCOT and further discussion on the controversial measure when the ISO’s Board of Directors meets April 22-23.
The Technical Advisory Committee endorsed the Nodal Operating Guide revision request (NOGRR245) during its March 27 meeting with amended language from joint commenters.
The language was “carefully crafted” to “reach a solution that properly balances risk mitigation with economic, technological and operational realities,” the commenters said. “Requirements that are technically infeasible or impracticable to meet (particularly for existing resources) do not benefit Texas consumers or the ERCOT market and do not improve grid reliability.”
The NOGRR is intended to align the grid operator’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. Two IBR-related voltage disturbances in West Texas in 2021 and 2022, dubbed Odessa Disturbances I and II, have added urgency to the measure’s eventual passage. (See NERC Repeats IBR Warnings After Second Odessa Event.)
Stakeholders have proposed software changes to fix the issues NERC and ERCOT have identified. They have said ERCOT’s proposals, if approved, “will implement the nation’s most aggressive ride-through performance requirements to date.”
The NOGRR passed in an 18-8 vote (69%), with three members abstaining. Two previous attempts to pass motions by stakeholders and then ERCOT failed.
“Thankfully, TAC rolled its sleeves up and refused to keep going without a compromise they could actually carry a motion on,” Arushi Sharma Frank, Tesla’s U.S. energy markets counsel and policy lead, posted on X.
The breakthrough followed hours of discussion during the meeting, a sidebar between staff and stakeholders during lunch and then an additional tweak of the stakeholders’ initial proposed revision to the motion.
ERCOT’s Stephen Solis, a principal for system operations improvement, said the modification to NOGRR245 only made things worse. Solis frequently emphasized the risks to reliability during the day’s discussion. In comments filed in January, ERCOT expressed concerns about implementing “technically infeasible” requirements that could force retirement of too much IBR capacity.
“This worsens reliability from even where we’re at today, because at least today, with the current ride-through requirements, [if] you fail, you have to go to the [Public Utility Commission]. You have to mitigate it. You have to fix it,” he said. “We are putting in a construct that reduces [the requirement]. That is worsening reliability, from ERCOT’s perspective.”
Solis said ERCOT’s comments were ignored during the sidebar discussions with stakeholders.
“[NOGRR245] is moving forward with a concept that because we went into a room with them, that somehow this has ERCOT’s input. ERCOT’s input was to make other modifications, which they denied to make right now,” he said. “This has not changed anything. They have basically thrown a bone about language that is in ERCOT’s current proposed language that they already had agreed to in the [stakeholder] discussions that we had, but they didn’t include it.”
Consultant Eric Goff, representing consumers and the joint commenters, said he didn’t want to get into a “back and forth” with ERCOT. He said stakeholder comments were based on ERCOT comments filed in January but not those filed March 26, given the lack of time. However, Goff said he was open to beginning a conversation with the joint commenters to see whether they could improve their comments by working off ERCOT’s latest filing.
“The goal here is to strike some type of balance. I understand that balance isn’t completely acceptable to ERCOT, but I think it’s important for the stakeholders’ voice to be heard,” Reliant Energy Retail Services’ Bill Barnes said. “I share a lot of concerns with ERCOT on the risk to reliability, just as much as the impact to existing resources is a very heavy issue the board needs to weigh in on.”
The NOGRR was drafted by ERCOT last year and granted urgent status in September. After working its way through the stakeholder process and reaching TAC, it was tabled in January when the ISO’s staff and stakeholders failed to reach consensus. The parties have been involved in negotiations since then. (See “Stakeholders Continue Discussion of IBR Reliability Requirements,” Technical Advisory Committee Briefs: Jan. 24, 2024.)
“I do think that that is in everyone’s best interest to continue to work together with ERCOT to potentially avoid an appeal. I don’t think it’s a good look to have two appeals go to the ERCOT board,” Barnes said. “I value the stakeholders’ opinion enough to get over the hangups that [Reliant] has so we can send a version to [the board] for its consideration and ERCOT can present their appeal if they wish to do so.”
“I’m less concerned with the optics on how it looks to [the board] than getting everybody’s actual position on record,” Jupiter Power’s Caitlin Smith said, speaking for her company and not in her role as TAC’s chair. “I’d hate to say we voted X way or Y way because we didn’t like the way two appeals would look to them than not get everybody’s real point of view on paper.”
“I think that the outcome of the two appeals presents more of a divided view than I think really exists, at least from our company’s point of view,” Barnes said.
ERCOT Reviews Price Corrections
Staff told the committee they will ask the board to approve two price corrections to real-time prices during its April meeting. An analysis of the errors’ effect on the market met the criteria for review when any single counterparty’s absolute value effect is either 2% and greater than $20,000 or 20% and greater than $2,000.
In January, ERCOT’s energy management system (EMS) retained outdated transmission line data during the weekly model builds, affecting three operating days. Staff fixed the software to ensure correct static ratings were used in the models.
The issue resulted in $1.64 million in additional payments to market participants and a $2.84 million impact on counterparties.
During routine maintenance Feb. 28, the process that exports constraint data from the EMS to the market management system sent incorrect constraint data for generic transmission constraints to the dispatch process. The second correction will return $277,930 to ERCOT.
Ögelman Extends ERCOT Service
Kenan Ögelman, ERCOT’s vice president of commercial operations, has extended his retirement date by a month and now will step away from the ISO at the end of April. (See “Ögelman to Retire from ERCOT,” ERCOT Board of Directors Briefs: Feb. 26-27.)
“I have not seen the [reliability must-run] determination for Kenan’s retirement,” Barnes joked.
Smith teasingly suggested discussing Ögelman’s final appearance before TAC during its April 15 meeting, leading Ögelman to fire back.
“You might need a [must-run alternative] for that,” he said, referring to ERCOT nomenclature for replacing a retiring resource’s capacity.
Indeed. Ögelman has scheduled a trans-Pacific Ocean trip a couple of days after he steps away from ERCOT.
TAC Passes Rule Changes
Members endorsed a nodal protocol revision request (NPRR1197) that enables resources to separately meter and settle loads located behind the ERCOT-polled settlement meters at their points of interconnection. South Texas Electric Cooperative voting against the measure over concerns it codifies into protocols the metering situation it had attempted to prohibit in the recently rejected NPRR1194.
They also endorsed a change to the Retail Market Guide (RMGRR177) that clarifies a customer’s lease agreement option when a competitive retailer tries to remove a switch hold applied to a premise it is seeking to enroll. The Office of Public Utility Counsel (OPUC) and residential customers abstained from the vote.
The consent agenda included goals for the Reliability and Operations and Wholesale Market subcommittees and NPRR1205 that, if approved by the board and the PUC, would “strengthen ERCOT’s market entry eligibility and continued participation requirements counterparties by clarifying minimum credit quality qualifications for banks that issue letters of credit on behalf of market participants and insurance companies that issue surety bonds on behalf of market participants.”
Last year’s GridEx VII security exercise demonstrated the importance of communications in maintaining grid reliability along with the need for continued discussions between industry and government on prioritization of loads during system restoration, NERC said in its report on the exercise released this week.
The Electricity Information Sharing and Analysis Center (E-ISAC) conducted GridEx VII from Nov. 14 to 16, 2023. The exercise comprised a distributed play portion, held during the first two days and involving more than 15,000 individuals from 252 participating organizations. Additionally, an executive tabletop was held on the third day with about 230 attendees from 75 organizations, including electric utilities; U.S. and Canadian government agencies and law enforcement; and representatives from the oil and natural gas, telecommunications, finance and nuclear industries.
GridEx VII marked the second exercise in a row to see a decline in organizations participating in the distributed play from the previous event: 293 organizations took part in the distributed play in 2021, and 526 in 2019. (See NERC ‘Very Happy’ With GridEx VII Participation.)
Of the organizations in the distributed play, 174 represented electricity asset owners or operators; 55 were government or “other”; 17 were reliability coordinators; and six represented the regional entities. All categories of participants were up or steady from last year except for government/other; 105 groups from this category took part in GridEx VI in 2021
NERC acknowledged the change in participation in its report while observing that the number of individuals taking part seemed to have increased significantly from the 3,000 estimated for GridEx VI. As in previous years, the number of individuals taking part was estimated based on responses in the after-action report.
The ERO attributed the participant decrease to the continuing impacts of the COVID-19 pandemic, as well as the requirement — implemented for GridEx VI — that participating entities must be E-ISAC members. NERC also noted that participating organizations may have coordinated their exercise play with unregistered entities, whose participation the E-ISAC could not track.
Organizations participating in the executive tabletop also fell from 88 participants in GridEx VI; however, the 230 individuals attending represented an increase from nearly 200 in the last exercise.
Cyber, Physical Attacks Hit Hard
The distributed play scenario was developed by the E-ISAC and customized by participants, so details of the exercise varied between entities. However, the outlines were shared by all.
The game consisted of five “moves.” It actually began over the week prior to the exercise, with Move 0 consisting of threats injected according to the “organizational objectives” of participants. Moves 1 to 4 comprised the core exercise over Nov. 14-15:
1: Cyberattacks and ransomware hit utilities’ communication software, internal information technology networks and third-party systems that operate the electricity markets. Additionally, disruptions to natural gas supply reduce generation capacity.
2: Attackers launch a coordinated physical assault against multiple substations, with gunfire targeting critical transformer components. A social media misinformation campaign and further cyberattacks hamper utilities’ responses.
3: As recovery gets underway, further attacks occur at telecommunications facilities. Protesters, frustrated by the ongoing power outages, begin to harass utility personnel. Attackers detonate explosives at equipment storage and staging areas, damaging equipment needed to restore service.
4: The game jumps forward a week after the attacks, and players consider long-term recovery challenges. Issues such as fuel and equipment shortages were highlighted, with entities having “to rely on their current inventories.”
NERC developed a set of recommendations from after-action surveys, feedback during exercise design and other engagement data.
First, NERC suggested that electric utilities continue to engage proactively with nonfederal government partners on emergency response plans. The report authors mentioned feedback from one planner who normally coordinates with county emergency managers but “realized [during GridEx VII that] it was not feasible to communicate individually with each county … in an incident that spanned many counties.”
NERC also noted the trend of declining participation by government entities. Observing that incident response “will likely require involvement from government partners at all levels,” the ERO urged municipal and state governments to step up participation.
The report also called on utilities to improve their communication and response measures in light of changes to work habits caused by the COVID-19 pandemic. Because gathering all responders together into a single room is not as feasible as it once was, it is important that utilities update their plans to account for a more distributed workforce.
NERC highlighted a comment from one planner that the simulated public unrest rendered the location intended for an in-person response inaccessible. The planners’ organization decided that a secondary location must be identified and added to emergency response plans in the future.
Additional recommendations related to communication of technical information across critical stakeholders, along with the E-ISAC’s support for organizations of varying sizes and levels of experience. Participants provided positive feedback on the inclusion of Move 4 and its focus on long-term consequences of the previous days’ events.
The distributed play portion of the exercise took place across Nov. 14 and 15 and consisted of four moves, plus a preliminary move the previous week. | NERC
Communications Struggle in Executive Tabletop
The executive tabletop also comprised four “acts,” with facilitators leading participants “through discussions designed to simulate the communication and coordination during a real event.”
1: A cyberattack compromises utilities’ inter-control center communications protocol (ICCP) software, through which grid operators receive data from transmission and generation facilities. Operators had to use alternate and manual methods and “suspend the electricity market systems that automatically dispatch and price generation.” Voice and data communications networks fail across a large swath of the country as well.
2: Coordinated cyber and physical attacks damage transformers and other equipment at substations in Louisiana and Texas. This leads to power outages at natural gas hubs.
3: Cyberattackers compromise and deface MISO’s website, demanding ransom. Backup systems are corrupted, and critical IT staff members cannot be reached.
4: One month later, ICCP telemetry is mostly restored, but MISO’s electricity market systems still are suspended, damaged substation equipment is not yet fixed and power has not been restored to natural gas facilities.
Recommendations from the tabletop included evaluating technology and processes to increase ICCP communication resilience. NERC emphasized that ICCP systems already are “highly reliable, supported by layers of redundant infrastructure and cybersecurity protections.” But the ERO said the exercise prompted participants to ask if the systems are adequately protected against certain vulnerabilities and if alternative measures would help secure the system.
NERC also suggested the industry study communication alternatives between grid operators, which could be needed if automated telemetry becomes unavailable or compromised. In addition, the ERO said industry and government should discuss whether utilities’ established restoration procedures conflict with government priorities during sustained, complex outages. Finally, NERC urged the industry to evaluate how to manage the reliability impacts of extended market system or data unavailability.
“Today’s threat landscape is dynamic, presenting challenges that are increasingly difficult to detect and protect against,” Manny Cancel, senior vice president of NERC and CEO of the E-ISAC, said in a statement. “The scenario created for GridEx VII reflected this by testing the collective ability of industry, government and cross-sector partners to restore the grid under the most extreme circumstances. … I am encouraged that several participants have already begun to implement some of the recommendations in their organizations.”
Many recent projections for energy use have fossil fuel use plateauing after 2030, when it needs to rapidly decline to meet midcentury carbon targets, Resources for the Future said April 2 in a new report.
The study — “Global Energy Outlook 2024: Peaks or Plateaus?” — reviews projections on the future of energy use and production from entities such as the U.S. Energy Information Administration, the International Energy Agency, the Organization of the Petroleum Exporting Countries and oil firms. They all use different scenarios, but RFF applied a detailed harmonization process comparing 16 scenarios across eight outlooks published last year, as well as two historical sources.
Even the scenarios that limit temperature change to 1.5 degrees Celsius by 2100 have substantial fossil fuel consumption through 2050, which suggests that a phaseout by then is not a prerequisite to achieving international climate goals.
“World primary energy demand has experienced a series of energy additions, not energy transitions, with newer technologies such as nuclear, wind and solar building on top of incumbent sources such as biomass, coal, oil and natural gas,” the report says. “To achieve international climate goals and limit warming to 1.5 C or 2 C by 2100, a true energy transition is needed.”
The scenarios in the report suggest that although a transition is needed, fossil fuels will not have to be eliminated. If fossil fuels are not phased out, the world will need to scale up carbon-removal technologies such as direct air capture; carbon capture, utilization and storage (CCUS); and nature-based solutions, all of which require robust monitoring and verification.
As of 2022, 42 million metric tons of CO2 were captured internationally — just 0.1% of annual global emissions, but a tripling of the technology since 2010, a compound annual growth rate of 8.7%. That growth is already on pace for some of the scenarios, but with more ambitious climate policies, the technology would need to grow by nearly 20% a year.
“Are these growth rates achievable? Technically speaking, the answer is ‘yes,’” the report says. “CCUS infrastructure and underground storage reservoirs are more than adequate to handle these volumes of CO2,” the report says. “However, the future costs of deploying these technologies, including to relatively novel sectors such as electric power generation (Most CCUS today is used in the industrial sector.), are not well understood.”
The scenarios all have the global economy becoming more efficient, so energy demand grows slowly or declines under almost every scenario. In the ambitious climate scenarios, demand can drop as much as a third by midcentury.
While overall energy demand drops, the scenarios all show significant growth in the global demand for power. At the end of 2019, electricity was roughly 20% of final energy consumption, but it grows up to 50% by midcentury in aggressive scenarios.
“This growth enables electricity to become a larger provider of energy services across the economy, particularly in the buildings and transportation sectors,” the report said.
Coal declines in all scenarios, while natural gas demand is mixed, with half the scenarios showing growth and the other half showing declines.
“Wind and solar grow faster than any other sources in percentage terms under all scenarios, but with a wide range,” the report said.
Wind and solar have represented about 75% of global capacity additions in the past decade, with solar growing at 10% a year from 2020 to 2022 — 320 GW per year. To reach 11,000 GW by 2030, as some scenarios call for, solar deployment would need to ramp up to 800 GW annually.
The nations of the world have committed to tripling nuclear energy by 2050, but that would require a fundamental change in the trajectory of the technology in developed countries, of which 12 out of 22 have seen declines over the last decade. Most scenarios have the technology growing modestly, with only two having it triple.
The Bureau of Ocean Energy Management (BOEM) issued its final Record of Decision (ROD) approving Avangrid Renewables’ New England Wind project on April 2, marking a major milestone for the proposed offshore wind project.
The New England Wind project is separated into two phases, which could total up to 2,600 MW of nameplate capacity. Neither phase of the project is under contract to be built, but Avangrid recently bid the project into Connecticut, Massachusetts and Rhode Island’s coordinated offshore wind solicitation. (See New England States’ OSW Procurement Receives 5,454 MW in Bids.)
The project is essentially a rebranding of the recently cancelled Commonwealth Wind and Park City Wind projects. (See Park City Wind to Cancel PPAs, Exit OSW Pipeline and Commonwealth Wind PPA Cancellations OK’d.) It would be located adjacent to the under-construction Vineyard Wind 1 project, on a lease area about 23 miles south of Martha’s Vineyard.
The ROD marks the Biden administration’s eighth offshore wind project approval, totaling more than 10 GW of approved capacity.
“Today, we celebrate the incredible progress being made toward achieving our goal of 30 gigawatts of offshore wind energy capacity by 2030,” said Secretary of the Interior Deb Haaland in a press release. “The New England Wind project will help lower consumer costs, combat climate change, create jobs to support families and ensure economic opportunities are accessible to all communities.”
Liz Burdock, CEO of the Oceantic Network (formerly the Business Network for Offshore Wind), celebrated the decision and praised the recent offshore wind permitting steps taken by the Biden administration.
“BOEM is crushing it,” Burdock said. “With the first projects nearing completion, two set to begin major construction this summer and more following in quick succession, a consistent construction pipeline is fostering the industry’s growth, creating opportunities for U.S. businesses to thrive and workers to develop critical skills.”
Representatives of environmental organizations including the Environmental League of Massachusetts, the Sierra Club and the Nature Conservancy also praised the decision.
“It is now well documented that Cape Cod and its adjacent ocean waters are among the very fastest-warming locations in the world, adding further urgency for Cape Cod’s transition to a sustainable energy future,” said Dorothy Savarese of the Cape Cod Climate Change Collaborative. “Offshore wind is an absolutely essential component of that vision.”
According to the federal permitting dashboard, the project is on track to complete the federal permitting and environmental review process by the beginning of July.
Avangrid CEO Pedro Azagra applauded the Biden administration for issuing the ROD and called the project “the most advanced and shovel-ready offshore wind opportunity in the Northeast region.”
While Avangrid backed out of power purchase agreements for earlier iterations of the project due to growing economic pressures, the states hope bid indexing will help account for future inflationary pressures and push the next cohort of offshore wind projects across the finish line.
The company has indicated New England Wind could reach commercial operation by 2030 if it is selected in the New England states’ coordinated solicitation. The states’ decisions on bids are due by Aug. 7.
NYISO on April 1 informed the Transmission Planning Advisory Subcommittee (TPAS) and Electric System Planning Working Group (ESPWG) it intends to seek a May 2 effective date for Order 2023.
The ISO plans to submit its full compliance filing May 1, about a month after FERC’s original April 3 deadline. The commission last month issued Order 2023-A, with minor modifications and clarifications of the new generator interconnection rules, and rejected multiple requests for rehearing. (See FERC Upholds, Clarifies Generator Interconnection Rule.)
The commission extended the compliance deadline 30 days after Order 2023-A’s publication in the Federal Register; as of press time, the revised order has not been published.
Due to the filing delay, NYISO rescheduled the start of the pre-application process to May 2 and shifted the opening of the transition cluster application window to Aug. 1, shortening the window from 105 calendar days to 75. Additionally, NYISO’s proposed pause on accepting new interconnection requests will now commence June 15. (See NYISO to Pause New Interconnection Requests for 3 Months in Order 2023 Transition.)
Although NYISO’s timeline for the transition cluster and subsequent interconnection processes remains largely unchanged, potential adjustments may occur if FERC does not approve the requested effective date or if stakeholder motions prompt the commission to delay its ruling on the compliance filing, the ISO said.
FERC recently approved NYISO’s proposed tariff adjustments designed to improve the coordination between its interconnection and transmission planning processes. The revisions, formulated prior Order 2023’s issuance, were recognized by the commission as part of the permissible independent entity variations transmission providers can incorporate into their compliance. (See FERC Accepts NYISO Proposal to Coordinate Queue, Transmission Processes.)
Dave Andrus, an executive consultant with Power Consulting Services, asked if NYISO has a better sense of whether FERC was more amenable to such variations after issuing the revised order.
Sara Keegan, NYISO’s assistant general counsel, said FERC’s stance on variations is unchanged and firmly established, but she added that “when you read this order, compared to the original order, it does provide additional areas in which the commission opens the door for independent entity variations, such as study timelines.”
Glenn Haake, vice president of regulatory affairs at Invenergy, asked about the perceived discrepancy between FERC’s and NYISO’s treatments of inverter-based resources (IBRs), suggesting that the commission’s approach is more lenient than the ISO’s, which based its approach to IBRs on rules recently approved by the New York State Reliability Council (NYSRC). (See New York Approves Final Rule on Inverter-based Resources.)
“As is often the case with the NYSRC, their rules tend to be more stringent than say NERC or even the NPCC [Northeast Power Coordinating Council], and that is the justification for our own compliance filing being more stringent than what was in the commission’s order,” Keegan responded.
NYISO said it will present a detailed overview of its Order 2023 compliance filing updates at the next Interconnection Issues Task Force meeting April 15.
NYISO senior manager of interconnection projects Thinh Nguyen requested stakeholders direct any feedback regarding NYISO’s Order 2023 compliance filing to stakeholder_services@nyiso.com.
Class Year, Expedited Deliverability Study Updates
NYISO also told the ESPWG and TPAS it initiated the 2024 Expedited Deliverability Study (EDS 2024-01) on March 28, with a total of 20 projects requesting participation.
ISO staff are evaluating each project’s eligibility for EDS 2024-01 inclusion and plans to issue agreements to eligible project developers. The goal is for developers to finalize their EDS agreements in time for NYISO to present a finalized list of EDS 2024-01 projects to stakeholders in May, though this list may not include all 20 projects. The EDS process is designed to streamline integration of projects seeking capacity resource interconnection service (CRIS) rights by determining if a project can be delivered as proposed without requiring system deliverability upgrades. In February, NYISO’s Operating Committee approved the results from the previous EDS study, EDS 2023-01, which evaluated 16 projects, of which 14 were deemed deliverable. (See NYISO Operating Committee Briefs: Feb. 15, 2024.)
NYISO also informed stakeholders of the completion of validations for all 83 projects in Class Year 2023, down one from the previous total after a CRIS-only project in Zone C, Q1059 Jaton Solar, withdrew from the study queue. A list of CY23 participants is available online.
The CY23 draft report is expected to be finished and submitted to the OC for approval by September.
The Massachusetts Commission on Energy Infrastructure Siting and Permitting on March 29 issued detailed recommendations to state lawmakers as they consider significant revisions to state processes for developing energy projects.
The recommendations focus on consolidating and expediting state and local permitting processes for clean energy infrastructure, while creating standardized requirements for early community engagement.
“Massachusetts’ current siting and permitting processes are causing significant delays in the clean energy transition,” Energy and Environmental Affairs Secretary Rebecca Tepper said in a statement. “By cutting red tape and building in better opportunities for meaningful stakeholder engagement, Massachusetts can ensure needed clean energy infrastructure is built more quickly and responsibly.”
The commission called on the legislature to establish a new consolidated permitting process for clean energy infrastructure at the state’s Energy Facilities Siting Board (EFSB), which would issue permits that “encompass all state, regional and local permits that a clean energy infrastructure project would otherwise be required to obtain to commence construction and operation.”
The EFSB also should be required to decide on permits within six to 15 months of its verification that an application is complete, the report said.
While larger clean energy, storage, and transmission and distribution projects would be under the jurisdiction of the EFSB, the commission also recommended the legislature establish a consolidated permitting process for smaller projects that fall outside the EFSB’s jurisdiction.
“Legislation should be enacted to establish a process by which a single consolidated permit is issued by a municipality to an applicant for non-EFSB jurisdictional clean energy infrastructure,” the recommendations said, noting that this permit would cover all local permits required of a project, but not state, regional or federal permits.
The report also called for the creation of a Division of Energy Siting and Permitting within the Department of Energy Resources, which would be aimed at helping municipalities with clean energy permitting.
Community Engagement
Along with proposals to speed up and increase the efficiency of permitting and siting, the commission also made a series of recommendations intended to strengthen community engagement for energy infrastructure projects.
The commission called for standardized pre-filing community engagement requirements for project developers, including community notifications, public meetings, comment opportunities and efforts to engage local organizations. It also recommended the EFSB create a new “Office of Community Engagement” to help applicants and communities in the engagement and permitting processes.
The report also recommended creating pre-filing community engagement requirements for non-EFSB jurisdictional projects, along with “a uniform set of baseline health, safety and environmental standards to guide municipalities in the issuance of permits for clean energy infrastructure.”
Like legislation that has been backed by environmental organizations, the report also recommended updating the EFSB’s statutory mandate to include consideration of the state’s climate targets and laws relating to environmental justice, labor standards and public health. It also recommended adding Indigenous and environmental justice representation to the EFSB. (See Mass. EJ Groups Rally Behind Permitting, Siting Reforms.)
Environmental organizations also have advocated for the addition of cumulative impact assessments to the permitting process to protect environmental justice communities, but the commission noted it “could not come to agreement on whether to include such language.”
The report did recommend that fossil fuel infrastructure – which would not be included in the expedited process – should be subject to a cumulative impact assessment, along with “the same community engagement and benefit requirements as clean energy infrastructure.”
Next Steps
While some of the recommendations could be implemented without legislation, many of the recommendations would need to be achieved through legislation.
Massachusetts legislators have indicated permitting and siting reforms are among their top priorities for this year’s session, and lawmakers have introduced multiple reform proposals. (See Mass. Lawmakers Aiming for an Omnibus Climate Bill in 2024.)
The House side of the legislature’s Joint Committee on Telecommunications, Utilities and Energy (TUE) favorably reported a bill this year that would create a consolidated permitting process while establishing early community engagement requirements. TUE Co-Chairs Rep. Jeff Roy and Sen. Mike Barrett were nonvoting members of the commission.
“I think everyone was resolved that we need to do something to speed up the permitting and siting process in order to achieve our goals,” Roy told NetZero Insider. “But just how best we can achieve that was difficult.”
Roy said he will work in the coming weeks to reconcile the commission’s recommendations with his initial proposal “to see if I can come up with a solution that will pass muster in the House.”
He added that some of the key points of contention at the commission included how much local control should be maintained, the definition of clean energy projects and which state entity should oversee the consolidated process.
The Healey administration has not yet indicated whether it plans to submit a new bill or work with legislators to incorporate the recommendations into existing proposals. The 2024 legislative session ends at the end of July, putting a deadline on the negotiations.
CAISO released a draft transmission plan April 1 identifying 26 new transmission projects aimed at accelerating California’s ability to meet its ambitious clean energy goals and costing an estimated $6.1 billion.
The 2023-2024 Draft Transmission Plan is based on projections the state needs to add more than 85 GW of capacity by 2035, a “significant increase” from the base portfolio amounts used in last year’s plan, reflecting the rapidly escalating need for new generation.
“The ISO’s 2023-2024 draft Transmission Plan identifies the next installment of critical infrastructure development that will be needed to bring historic amounts of new clean energy onto the grid, including the first projects to deliver offshore wind from California’s North Coast,” CAISO spokesperson Anne Gonzales told RTO Insider in an email.
As with last year’s plan, the ISO coordinated with the California Public Utilities Commission and the California Energy Commission to implement the blueprint outlined in the joint memorandum of understanding signed by the three agencies in December 2022.
The MOU “tightens the linkages” between resource and transmission planning, interconnection processes, and resource procurement to meet reliability needs and clean energy policy objectives set in Senate Bill 100, which requires the state’s electricity system be emissions-free by 2045.
“To help ensure we have the transmission in place to achieve this transition reliably and cost-effectively, the ISO’s 2023-2024 Transmission Plan builds on the much more strategic and proactive approach adopted in last year’s 2022-2023 Transmission Plan to better synchronize power and transmission planning, interconnection queuing and resource procurement,” the plan reads.
Emphasis on Renewables
The plan outlines the resource development needed to meet emissions reductions targets, including:
More than 38 GW of solar generation in regions that include the Westlands area in the Central Valley, Tehachapi, the Kramer area in San Bernardino County, Riverside County, southern Nevada and western Arizona.
More than 3 GW of in-state wind generation in existing wind development regions, including Tehachapi.
More than 21 GW of geothermal development, mainly in the Imperial Valley and southern Nevada.
Access for battery storage projects co-located across the state with renewable generation project and standalone storage located closer to major load centers in the Los Angeles Basin, greater Bay Area and San Diego.
The import of more than 5.6 GW of out-of-state wind generation from Idaho, Wyoming and New Mexico.
More than 4.7 GW of offshore wind, with 3.1 GW in the Central Coast (Morro Bay call area) and 1.6 GW in the North Coast area (Humboldt call area).
This year’s plan places a greater emphasis on the development of floating offshore wind off California’s North Coast. Major projects include a new Humboldt 500-kV substation, a 260-mile HVDC line interconnecting the Humboldt substation to the Collinsville substation, a 140-mile 500-kV AC line connecting Humboldt to the Fern Road substation and a 115-kV line from the new Humboldt station to the existing Humboldt station.
“The infrastructure investments also have tremendous reliability and economic benefits for California and its dynamic economy and in this year’s plan, significant amounts of new offshore wind generating capacity and the associated transmission upgrades are required to cost-effectively bring reliable decarbonized power to California consumers and industry across all seasons of the year,” the plan says.
Out of the 26 newly identified projects, 19 are reliability-driven, representing $1.54 billion of the total cost. Examples of reliability-driven projects that CAISO recommended for approval include PG&E’s Martin-Millbrae 60-kV area reinforcement in the greater Bay Area, the Eldorado 230-kV short circuit duty mitigation project led by Southern California Edison, and San Diego Gas & Electric’s Valley Center System Improvements.
CAISO also identified seven policy-driven projects, those needed to meet renewable generation requirements established by the CPUC, representing $4.59 billion. Projects include PG&E’s new Humboldt substation and the new line connecting to Fern Road.
The ISO also conducted studies aimed at identifying economics-driven projects, those that could reduce ratepayer costs, but no such projects were recommended.
CAISO scheduled a stakeholder meeting April 9 to discuss the plan and expects to seek approval from its Board of Governors on May 23.
FERC ordered Tri-State Generation and Transmission Association to rework two filings involving departing members in orders issued March 29.
One order was a specific agreement on United Power’s departure from the wholesale member-owned cooperative (ER24-1145), while the other regarded what costs future departing members would have to cover (ER21-2818).
Tri-State provides wholesale power and transmission service to 42 members in Colorado, Nebraska, New Mexico and Wyoming. United is a Colorado co-op that has taken service from Tri-State under a wholesale electric service contract (WESC), but it gave official notice it wanted to leave in April 2022, to be effective May 1, 2024.
The broader departure fee case dates back to September 2021, when Tri-State first filed revisions, which were set for hearings and led to another order in December 2023. (See FERC Picks ‘Balance Sheet Approach’ Exit Fee for Tri-State Members.) The order issued last week directs another compliance filing to fix some aspects of the proposed exit fee.
United told FERC that the latest withdrawal proposal from Tri-State would charge it $627.7 million, while it calculated a fee of $464.5 million. The largest reason for the $163 million gap is the $148 million United said Tri-State failed to account for in the co-op purchase of non-networked transmission and distribution facilities.
FERC found the arguments in the case from both United and Tri-State would be better addressed in the broader compliance case but accepted the withdrawal agreement subject to some additional issues being resolved.
The $627.7 million fee is based on a contract termination penalty of $709.5 million, minus $81.9 million in patronage capital that United had put up but no longer will be used now that it is leaving. Tri-State will have to file an updated amount with the right patronage capital amount and regulatory liabilities credit, which are being developed in the ongoing ER21-2818 docket.
The commission accepted the withdrawal agreement, subject to a compliance filing due in 14 days, which will allow United to leave Tri-State’s service.
Tri-State also will have to make a compliance filing on the broader contract termination payment (CTP) rules within 14 days, but those rules will apply only in total to firms that leave the co-op’s service after 2025. FERC also set up hearing and settlement procedures for some aspects of the rule.
FERC accepted Tri-State’s proposal to provide each member with a potential CTP every year that reflects their pro rata allocation of power purchase agreements in addition to their pro rata share of its debt. Tri-State also won approval for its proposal to enter into withdrawal negotiations within 180 days of getting a request, but the association will have to make clear that none of those procedures are required by entities leaving this year or next, which already have started to withdraw.
The commission found that Tri-State partly complied with its requirements to pay back departing members’ patronage capital, either as a discounted lump sum or over time as it is retired in the normal course of business. But its proposal failed to account for any accrual or retirement of patronage capital that occurs between when a member signals a notice to leave and actually leaves service.
Tri-State has members in both the Eastern and Western interconnections, and while those out West likely face higher CTPs than patronage capital amounts, that is not the case in the East. Tri-State proposed never having to pay a departing member if its patronage capital were higher than its CTP, but FERC ordered it on compliance to pay out a lump sum should such firms request it.
Tri-State also was required to change its transmission crediting mechanism for departing members, basing it on their pro rata share of the full amount of its transmission debt and paying them back with full interest.
The compliance filing also will have to change how PPAs are treated, as Tri-State will have to show departing members their pro rata share of system capacity and associated energy when it proposes their buyout amount. That will be earlier than Tri-State initially proposed, which FERC said would help departing members make their decision.
Tri-State also will have to update its proposed CTP to properly reflect costs of serving customers in the Western Interconnection to reflect the impact of any members departing before another, so that a departing member does not have to pay for debt Tri-State collected in an earlier CTP.
