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.
FERC on March 29 approved CAISO’s request to forgo this year’s process for taking interconnection applications, giving the ISO more time to study last year’s record-breaking number of requests (ER24-1213).
FERC’s order became effective March 31, just ahead of the April 1 deadline CAISO is required to meet each year to open a new interconnection window, which kicks off a two-year cluster study process.
CAISO sought the tariff change to extend study deadlines for Cluster 14 and pause Cluster 15 because of the “unprecedented increase” in new interconnection requests received for those clusters combined with a lower percentage of interconnection customers withdrawing after Phase one of the process. (See CAISO Seeks FERC’s OK to Shut 2024 Interconnection Window.)
The rule revision will help CAISO “avoid compliance issues, the need for waiver or exacerbating the queue’s challenges before CAISO can comply with Order No. 2023 and implement needed reforms,” the order states. “Further, CAISO contends that forgoing the 2024 interconnection request window will allow sufficient time to study existing interconnection requests.”
Stakeholder Concerns
In comments submitted to FERC, several stakeholders said closing the 2024 interconnection window would affect much-needed resource procurement and fail to address the root causes of the clogged queues.
While the Northern California Power Agency did not oppose the move, it did note that the backlog is particularly problematic for load-serving entities that will struggle to acquire the clean resources needed to meet procurement mandates without sufficient projects coming online in a timely manner.
The Six Cities group of Southern California municipal utilities opposed the move, saying that while CAISO remains engaged in the Interconnection Process Enhancements stakeholder initiative, delaying the request window will cause a gap in implementing necessary reforms.
“Six Cities contend that the elimination of the 2024 interconnection request window should not be permitted to prolong the gap in making these necessary changes to the process,” the order noted.
Six Cities also acknowledged the challenge of bringing new resources online amid the delay. FERC noted the utilities said “they have experienced considerable challenges in procuring capacity to meet reliability requirements during the past two years.”
CAISO asked the commission to disregard those concerns due to “meaningful progress” made in its stakeholder initiative and highlighted that it will propose significant reforms to the process when the ISO submits its compliance filing for Order 2023, expected April 3.
FERC agreed with CAISO, saying the stakeholder comments fell “outside of the scope” of the proceeding.
“We agree with CAISO that its proposed revision will enable CAISO to work with stakeholders to develop and implement meaningful reforms for processing Cluster 15 and will avoid exacerbating the queue’s challenges,” FERC said. “Further, we find that forgoing the 2024 interconnection request window is a just and reasonable solution to prioritize the significant volume of existing interconnection requests in a timely manner.”
Survey: Customer Satisfaction down, but Still ‘Very Good’
The NYISO Management Committee was informed March 27 that the ISO received a total satisfaction and performance score of 84.7, according to the eighth annual assessment by the Siena College Research Institute.
Siena, a New York-based pollster, independently evaluated two aspects of NYISO’s operations: customer satisfaction, which gauges the quality of consumer interactions and engagement; and assessment of performance, which determines if the ISO is “realizing [its] mission through [its] performance.”
NYISO scored 91 in satisfaction and 75.4 in performance; the final score, 1.7 points lower than last year’s, is weighted 60% on satisfaction and 40% on performance.
Siena Director Don Levy explained that the survey involves asking both market participants and senior executives throughout the year to “assess the degree to which NYISO is enacting its mission, including things like reliably operating the grid, administering open and competitive markets, and providing factual information.”
NYISO achieved its highest scores the previous year, with 92.3 in satisfaction and 77.6 in performance. “That score was a historic high and was bound to decline, so now the ISO has just regressed back to where it was in previous years,” Levy said. (See NYISO Receives ‘Exceptional’ Customer Survey Scores.)
The ISO “deserves a pat on the back” for consistently scoring high in customer satisfaction, Levy said, but he noted that it should strive to enhance its performance assessment by market participants, which declined about 5 points from last year and is “lower than it has been over the past four previous years.”
Specifically, NYISO should focus on improving its perceived underperformance in reliably operating New York’s grid, Levy said. That metric dropped 6.8 points from last year. However, he also acknowledged that NYISO’s professionalism consistently scores above 90 points, with respondents frequently writing how the ISO is “excellent, excellent, excellent at handling all interactions.”
Levy urged NYISO to redouble its efforts to improve communication channels and engage more directly with market participants, emphasizing that the results are not “a call to jump off a cliff” but a reminder that the ISO has merely “dropped from exceptional to just very good” and has room for improvement.
Co-located Storage Resource Participation
The MC approved proposed tariff changes allowing energy storage resources (ESRs) co-located with a dispatchable generator behind a single point of interjection to participate in the ISO’s energy markets.
The revisions, approved by the Business Issues Committee on March 13, broaden the list of resources that can be included in the ISO’s co-located storage resource (CSR) models and are part of the wider hybrid storage resource (HSR) effort to couple generators with ESRs and further integrate them into New York’s energy markets. (See “Co-located Storage Resources,” NYISO Business Issues Committee Briefs: March 13, 2024.)
NYISO aims to file the proposed HSR model and the approved CSR updates in the second quarter and implement the CSR updates by year-end. However, the changes will necessitate additional modifications to comply with FERC Order 2023 that will not be developed until the ISO submits its final compliance filing.
Capacity Accreditation
The MC also approved proposed tariff revisions intended to enhance the ISO’s capacity accreditation modeling by more accurately reflecting factors such as natural gas constraints and correlated derates essential for calculating capacity accreditation factors (CAFs) and capacity accreditation resource classes (CARCs).
Approved by the BIC last year, the revisions would ensure capacity resources receive compensation that aligns with their performance, availability and marginal contribution to reliability needs. They came after resource adequacy analyses indicated capacity accreditation models were producing inaccurate CAFs and CARCs for some resources and failing to account for metrics not represented in installed reserve margins and locational capacity requirements.
The revisions would also update the installed capacity (ICAP) supplier bidding requirements. Suppliers, unless exempted, must now either schedule a bilateral transaction or bid energy in the day-ahead market (DAM) with a normal upper operating limit (UOLe) at or above their ICAP equivalent of unforced capacity or notify the ISO of any outages. This would address a loophole in which existing market rules did not explicitly prevent ICAP suppliers from meeting their availability obligations by offering only a portion of their capacity in the DAM at an UOLe.
Order 2023 Update
NYISO CEO Rich Dewey informed the MC that amendments FERC made to Order 2023 necessitate delaying the ISO’s final compliance filing beyond the originally scheduled April 3 deadline.
Dewey said the exact submission date remains uncertain as staff “are still reviewing the details,” but a presentation scheduled for the Transmission Planning Advisory Subcommittee’s (TPAS) meeting April 1 suggests the ISO plans to submit its filing by May 1.
FERC on March 21 modified and clarified its new generator interconnection rule and extended the compliance deadline, after rejecting multiple challenges that sought rehearing. (See FERC Upholds, Clarifies Generator Interconnection Rule.)
Dewey assured the MC that more information about NYISO’s Order 2023 filing will be shared at the TPAS meeting, with stakeholders commenting on further revisions at the Interconnection Issues Task Force’s meeting April 15.
Board Compensation
Dewey also reported to the MC that the ISO’s Board of Directors approved a $3,500 increase in the annual retainer for directors, to $80,000.
The board adjusted its retainer about a year ago, raising it by $5,000 to $76,500, and will reassess the need for additional compensation changes annually instead of every three years, as had been the practice. (See “Board Compensation,” NYISO Receives ‘Exceptional’ Customer Survey Scores.)
Dewey mentioned that the board continues to interview potential members but has not yet met to formalize any decisions, though it hopes to do so in April.
NYPSC Confirmations
The New York State Senate confirmed Uchenna Bright and Denise Sheehan as the new commissioners at the state’s Public Service Commission on March 27.
Uchenna Bright | E2
Gov. Kathy Hochul (D), who nominated both in late February, praised the confirmation, saying in a statement that the new “commissioners will bring unique and invaluable expertise to the PSC at a pivotal time for New York’s energy future.” These are Hochul’s first nominations to the seven-member PSC, with each commissioner serving a six-year term.
Bright, a longtime environmental advocate, was Northeast lead for E2, a nonprofit group of business leaders that lobbies for green policies and partners with the Natural Resources Defense Council. Sheehan, a former New York Department of Environmental Conservation commissioner, was an executive vice president at Capitol Hill Management Services, an Albany-based association management company. She has also served as a senior adviser to the New York Battery and Energy Storage Technology Consortium. Their confirmation hearing was March 26.
Denise Sheehan | NYLCV
Gavin Donohue, president of the Independent Power Producers of New York, said in a statement that Sheehan “brings a balanced point of view between safe, reliable and affordable service, and her decorated career within government and the industry speaks for itself.” Bright “will provide expertise on environmental policies with economic costs and benefits at the front of mind in a way that balances a good economy and environment,” he said.
The New York League of Conservation Voters praised Hochul’s nominations, saying their expertise and environmental advocacy make them “welcomed additions to the PSC.”
SPP filed its Markets+ tariff at FERC on March 29, the culmination of a more-than-yearlong collaboration with potential participants and stakeholders to draft rules and protocols for the grid operator’s day-ahead market offering in the Western Interconnection.
The tariff was formally approved by the SPP Board of Directors last week. The language previously was endorsed by Markets+ stakeholders and a panel of independent SPP directors. (See SPP Board Approves Markets+ Phase 1 Tariff.)
“SPP’s mission and success [depend] on working together effectively, and it’s been a privilege to work alongside our new western stakeholders to craft market policy that will create a brighter, more resilient energy future in the West,” CEO Barbara Sugg said in a statement.
Sugg added she’s looking forward to “bringing Markets+ to life.”
SPP requested that the commission issue an order by July 31. It also asked for an extended 31-day public comment period, and it committed to specifying a precise effective date before implementation, currently targeted for the second quarter of 2027 (ER24-1658).
As SPP doesn’t yet have an effective date, it followed FERC precedent in setting a date of 12/31/9998 for tariff records submitted in the filing.
The RTO’s staff worked with staff from 38 western entities that executed agreements to participate in the first phase of Markets+’s development.
“It’s been critical to us that the development of Markets+ be driven by western stakeholders,” said Antoine Lucas, SPP’s vice president of markets and sponsor of the Markets+ program. He said SPP’s approach has resulted in a market design that would improve the grid’s reliability and affordability, enable participants to meet clean energy mandates and goals and to do so in a way that “ensures equity for every market participant.”
In a news release, SPP provided positive statements from several western stakeholders, perhaps none more important than that of the Bonneville Power Administration (BPA). The federal agency operates more than 15,000 miles of transmission and nearly 17,500 MW of generating capacity in the Northwest, lending significant weight to its decision on joining a day-ahead market.
Rachel Dibble, BPA’s vice president of bulk marketing and a member of the Markets+ Participants Executive Committee (MPEC), told SPP she appreciated the grid operator’s “collaborative and transparent stakeholder-driven governance model” used to develop the tariff language.
“The result is an end product that recognizes the needs and perspectives of all participants and accounts for BPA’s legal obligations,” Dibble said.
Arizona Public Service’s Brian Cole, vice president of resource management, noted his customers’ energy needs will increase dramatically over the next few years. He said the utility is “thoughtfully exploring market options.”
“SPP’s Markets+ provides a promising framework to serve the West with dependable, diverse and cost-competitive power supplies,” Cole said.
Northwest & Intermountain Power Producers Coalition Executive Director Spencer Gray, a prominent voice for the independent sector, applauded the commitment and work by Markets+ participants, stakeholders and SPP staff for “improving wholesale energy markets in the West.” (See “Independents Sector Changes,” SPP Markets+ Participants Executive Committee Briefs: Jan. 23-24, 2024.)
SPP and western stakeholders will continue their work to define protocols for the market’s administration while awaiting FERC’s approval of the draft tariff.
With FERC’s blessing, MISO will synchronize its generator replacement process with its generation suspension and retirement process to give interconnection customers more flexibility when they decide to replace, retire or suspend a generating unit.
MISO received a favorable decision on a tariff change from FERC on March 29 and now will allow owners hoping to replace their generation with the option to simultaneously request to be evaluated for retirement or suspension if their plans for a replacement facility don’t pan out (ER24-1055).
MISO’s current generator replacement process requires an interconnection customer seeking to replace its generating facility with a new facility to submit a request for replacement at least a year before the existing facility halts commercial operations. MISO completes a replacement impact study on the new generation to figure out whether its addition will adversely impact the system and completes a reliability study to see if the system will suffer violations without the existing generation while the replacement generation is being built. If the project can proceed, MISO drafts a replacement generation interconnection agreement (GIA).
However, that roughly yearlong process bumps up against MISO’s generation suspension and retirement requirements, which expect generation owners to make a request to retire or suspend more than a year before the generating unit idles.
MISO said its generation owners often begin the process unsure of whether a replacement, suspension or retirement is the best decision for their generation and have only the results of MISO’s reliability and impact studies for replacement once the notification deadline to retire or suspend the unit has passed. That leaves owners who find that their replacement plan is not viable in a bind, MISO said, and beholden to a process “entirely driven by procedural timing requirements rather than engineering or economic considerations.”
Now generation owners will be able to request a suspension/retirement equivalency study alongside their option for MISO to perform generation replacement studies. If owners elect the equivalency study at the time of their replacement request, MISO will waive the yearlong lead time for suspensions and retirement requests and require only 30 days’ notice to begin suspension/retirement studies.
MISO said the rule change will allow generation owners whose replacement plans fall through and have elected the equivalency study to seamlessly transfer units to suspension status, “which will allow the interconnection customer to make the proper plans for the future of its unit.”
FERC said the change should allow MISO to process suspension, retirement and replacement requests more efficiently and give interconnection customers better data to make informed business decisions.
“We find that MISO’s proposal will integrate and harmonize its retirement and suspension processes with its generator replacement process by aligning the timeline for an interconnection customer with an existing generating facility to be considered for a suspension and/or retirement request with a replacement generating facility request,” the commission wrote.
FERC said the revisions will allow owners more freedom to pursue suspension and retirement decisions if their replacement facility requests are denied by MISO and lessen the risk that they miss deadlines to cease operations.
MISO also said it will apply its new process to partial replacement of generation facilities, where some interconnection rights are left over after a replacement facility is planned. In those cases, interconnection customers can make additional replacement generating facility requests for the remaining capacity of an existing generating facility up until the first GIAs are struck for some of the interconnection rights.
The Mississippi and Arkansas public service commissions, Entergy and WEC Utilities protested the filing, arguing that MISO’s plan would deprive generator owners of their residual interconnection capability by prohibiting additional interconnection requests of already-paid-for interconnection rights after the first GIA is signed.
FERC brushed those concerns aside, saying interconnection customers still have the opportunity to replace an existing generating facility up to the same level of interconnection service.
