Bay State Wind Project Wins OK for Larger Turbines
The NEPO Reliability Committee on Tuesday approved the Bay State Wind project’s request to increase its capacity by 40 MW, reflecting a move to larger turbines.
The committee found no negative reliability impacts resulting from Bay State’s proposed array of 80 11-MW turbines south of Martha’s Vineyard, Mass. The project, a joint venture of Ørsted and Eversource Energy (NYSE:ES), is scheduled to reach commercial service in May 2026.
The committee also signed off on transmission applications for the project including:
installation of two 140-MVAr synchronous condensers connected via 345/24-kV transformers;
construction of a 345/275-kV onshore substation;
installation and interconnection of two 275-kV submarine, landfall and land cable circuits;
installation of two 275/66-kV off-shore substations;
installation and interconnection of two 345-kV buried land cable circuits interconnecting at the Brayton Point 345-kV and Bay State Wind 345/275-kV onshore substations.
Order 2222 Compliance, Procedure Changes Approved
The committee also approved:
changes to Planning Procedure 10 (Planning Procedure to Support the Forward Capacity Market), including conforming changes for ER21-640, related to qualification of non-commercial resources in annual reconfiguration auctions, and ER19-343, related to the modeling of peaking generation in reliability reviews;
tariff revisions regarding auditing and installed capacity requirements as part of ISO-NE’s compliance with FERC Order 2222, which allows aggregations of distributed energy resources to participate in the RTO’s markets; the compliance filing is due Feb. 2, 2022;
changes to Operating Procedure 16K (Transmission System Data – Submission of Short Circuit Data), part of a biennial review with minor updates to process flow diagram; and
changes to Operating Procedure 3 (Transmission Outage Scheduling), part of biennial review with minor edits and grammatical revisions.
Other Projects
The committee also determined no negative reliability impacts from the following projects:
installation of a 200MW/400-MWh battery storage project in Milford, Conn., which will interconnect to a new 345-kV breaker position at the East Devon substation (Able Grid Infrastructure Holdings, Eversource Energy and United Illuminating);
installation of a 20-MW solar PV facility in Leeds, Maine, interconnecting to the Leeds Substation (Central Maine Power on behalf of Walden Solar Maine);
installation of a 4-MW solar PV facility in Putnam, Conn., interconnecting to the Tracy 14M Substation (Eversource Energy on behalf of Glenvale Solar); and
a generation group study for a 35.4-MW distributed energy resources project in the Winslow/County Road area and a 29.8-MW DER project in the Lakewood area of Maine. The generation clusters represent 20 DER facilities that would interconnect into Central Maine Power’s sub-transmission and distribution systems.
The committee approved the following cost allocations for pool transmission facilities:
$64.7 million of transmission upgrade costs for work associated with 115-kV and 230-kV wood structure replacement projects in Massachusetts, Connecticut and New Hampshire (Eversource);
$186.3 million for 345-kV structure replacement projects in Massachusetts, Connecticut and New Hampshire (Eversource);
$23.9 million for replacement of wood structures on the 1261/1598 115-kV line (Eversource).
Stein Re-elected Vice Chair
The committee re-elected Robert Stein, a consultant who represents H.Q. Energy Services, as vice chair for 2022. There were no other candidates.
PJM kicked off what it said will be a multiyear initiative on the increasing integration of renewables Wednesday with the release of a study on the transformation of generation.
The paper, Energy Transition in PJM: Frameworks for Analysis, includes the RTO’s preliminary five-year strategy built on three pillars: facilitating state and federal decarbonization policies, planning for the grid of the future and fostering innovation for the transition.
PJM told the Markets and Reliability Committee the study is designed to help the RTO identify gaps and opportunities in the current market construct and provide insights into the future of market design, transmission planning and system operations.
“As the generation mix continues to rapidly evolve in PJM, we must be ready to maintain the reliable, cost-effective delivery of electricity at all times,” said CEO Manu Asthana. “This study represents an important step in understanding how PJM can best work to facilitate the energy transition and make the grid of the future possible.”
Study Overview
Emanuel Bernabeu, director of PJM’s Applied Innovation and Analytics department, presented a high-level overview of the study, saying PJM believes it can “play a major role” in facilitating the decarbonization transition through reliability and cost-efficiency measures.
PJM is also working on defining what the grid of the future will be and how it will be operated, Bernabeu said, and fostering innovation both internally at the RTO and within the stakeholder community.
“These are pretty heavy pillars, so it does require a strong foundation,” Bernabeu said.
The first phase of the study was not meant for PJM to propose solutions, Bernabeu said, but to inform stakeholders on broad issues and initiate a discussion to “put some light” on areas that need focus.
Bernabeu called the paper a “living study” because the assumptions that went into the work will continue to be refined as PJM continues to look for opportunities to improve market designs, operations and planning.
The study considers three scenarios in which an increasing amount of energy is served by renewable generation. The “base” scenario included 10% of the annual energy in the PJM footprint coming from renewable generation, while the “policy” and “accelerated” scenarios had renewables representing 22% and 50% of the annual energy, respectively.
In the accelerated scenario, up to 70% of the dispatch was considered carbon-free when combined with nuclear generation. The accelerated scenario includes 29 GW of offshore wind, 36 GW of onshore wind and 55 GW of solar.
As of 2020, renewables represented 6% of PJM’s annual energy, a total of more than 40% carbon-free including nuclear.
Bernabeu acknowledged that annual energy is “not the most intuitive metric.” In the accelerated scenario, he said, there are periods of time when PJM is serving 130% of the load with renewables — with any generation over the 100% mark exported to other regions.
PJM studied the resource adequacy of the three scenarios and simulated an entire year of the energy market with an hourly resolution to see how the renewable resources will operate.
Bernabeu said the study’s initial findings suggested five key focus areas for PJM’s stakeholder community, including correctly calculating the capacity contribution of generators. He said transmission systems with increased variable resources will require “new approaches” to assess the reliability value of each resource and the overall system.
The study determined the need for “operational flexibility” to address the uncertainty of variable resources, Bernabeu said, including lower capacity factors for thermal resources and average locational marginal pricing (LMP) decreases of as much as 26%.
The report says thermal generators provide “essential reliability services,” and an adequate supply will be needed until a substitute is “deployed at scale.” Bernabeu said PJM and stakeholders should ensure market structures provide the necessary incentives to maintain the generation for reliability.
He said expected increases in congestion, renewable curtailments and interchange with other regions “suggest opportunities for strategic regional transmission expansion.”
Reliability standards also must evolve, PJM said. The development of PJM’s markets, operations and transmission planning must be accompanied by the “advancement of comparable reliability requirements across interdependent infrastructure,” Bernabeu said. “Reliability cannot be achieved in a vacuum.”
Work on the study is expected to continue through 2022 with an updated report coming around the end of the first quarter of next year. “This study is not meant to be done and collect dust in your desk,” Bernabeu said.
Stakeholder Questions
Bernabeu was asked about the modeling done in neighboring RTOs and ISOs and the assumptions that were used. Wind projects in MISO were highlighted as an example of potential impacts on generation in PJM.
Bernabeu said the export and interchange numbers in the first version of the study were based on modeling neighboring regions maintaining the status quo with transmission and generation.
“The models tend to be extremely detailed inside PJM, and then the accuracy tends to degrade the further you move away from the footprint,” Bernabeu said.
Another stakeholder asked what PJM believes is an adequate supply of thermal generation.
Bernabeu said the first round of the study stopped short of making definitive quantitative assessments. He said there’s not a definitive quantity of supply for adequacy, so sensitivity analysis is going to continue to seek answers.
The most important aspect of the thermal focus area is how to incentivize behavior to maintain “essential reliability services,” he said.
“What is adequate? We haven’t found an answer yet,” Bernabeu said.
NERC’s Reliability and Security Technical Committee (RSTC) this week agreed to endorse several proposed reliability standard projects that were previously rejected by it and NERC’s Standards Committee.
The committee’s endorsement of two separate standard authorization requests (SARs) to modify TPL-001-5 (Transmission system planning performance requirements) and one to revise MOD-032-1 (Data for power system modeling and analysis) means the SARs will now go to the Standards Committee for approval. If the Standards Committee grants its assent, work can officially begin on a standards drafting project.
Teams Submit Competing TPL-001 SARs
One of the TPL-001-5 SARs was proposed by NERC’s Inverter-based Resources Performance Working Group (IRPWG), while the other came from the System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group. The first would clarify “terminology throughout the standard that is unclear with regards to inverter-based resources;” the second would revise the standard to better address distributed energy resources (DER).
It is not unusual for the Standards Committee to receive multiple SARs relating to the same standard. In such situations the committee often combines them into one project.
A previous SAR to modify TPL-001-5, supported by both IRPWG and SPIDER, failed to garner enough votes for endorsement at the RSTC’s meeting in March. (See “DER Standard Request Denied,” NERC RSTC Briefs: March 2-3, 2021.) Brian Evans-Mongeon of Utility Services Inc. was one of several members to raise concerns about the proposal, including that the SAR did not specify its applicability to non-bulk electric system devices.
SPIDER and IRPWG could still have proceeded to the Standards Committee for approval but elected to go back to the drawing board on separate proposals, working with the RSTC in hopes of identifying potential problems ahead of submitting them for endorsement. At this week’s meeting, SPIDER Chair Kun Zhu of MISO detailed the changes the working group made to its SAR, including:
clarifying that transmission planners with minimal DER impact do not have to study DER contingencies under a threshold established by the standard development team (SDT);
removing a statement that system peak net load is the most stressful condition;
recognizing that DER modeling and study requirements are based only on data made available and are not dependent on any SARs to modify MOD-032-1; and
removing recommendations related to inverter-based resources.
By contrast, the IRPWG’s SAR incorporated only one change based on feedback from the RSTC, removing a bullet from the section on the project’s scope that committee members considered overly broad. Otherwise, the working group’s leadership elected to leave the SAR intact despite members expressing concern on topics such as the lack of a section on applicable facilities, and the desire to include provisions for amending MOD-032 to better identify applicable entities.
Both of the SARs related to TPL-001-5 received endorsement, though Evans-Mongeon moved to delay a vote on the IRPWG SAR until no later than Jan. 15, stating that the agenda packets sent out before the meeting did not include all of the members’ comments. He and others had not had time to review all of the comments and IRPWG’s responses prior to the meeting, he said. However, his motion failed with 10 votes in favor, 14 opposed, and two abstentions; subsequently the IRPWG’s SAR passed with 24 votes in favor and two opposed, while the SPIDER SAR passed with 25 votes in favor and one abstention.
SPIDER Hopes for Standards Committee Reassessment
The MOD-032-1 SAR also revisits a previously rejected standards proposal, albeit one that got farther along in the development process. In this case the Standards Committee voted last year to end Project 2020-01, SPIDER’s previous attempt to update the standard, on the grounds that the project’s SDT had not done enough to respond to concerns raised by industry during the informal comment period. (See “SAR Rejected over Industry Concerns,” NERC Standards Committee Briefs: Dec. 9, 2020.)
The committee’s grounds for rejecting the project led SPIDER members to vent their frustration and confusion at a subsequent meeting, with many arguing that the negative comments didn’t truly represent industry sentiment. Some RSTC members also expressed concern over whether the negative comments had been fully addressed. However, others — including NERC Chief Engineer Mark Lauby — agreed with SPIDER that if “enough people don’t come back and say that [they] like it, it looks as if everybody’s against it.”
To avoid more wasted effort, the RSTC voted to endorse the SAR and send it to the Standards Committee along with several “technical justification documents,” including a letter from RSTC and SPIDER leadership explaining the decision to resubmit the project and the changes incorporated into the new proposal.
The New York City Council voted Wednesday to ban the use of natural gas for heating or hot water in new construction or renovations beginning in 2024.
The statute prohibits the combustion of a substance that emits 25 kilograms or more of carbon dioxide per million British thermal units of energy, starting with buildings under seven stories permitted before Jan. 1, 2024, and in buildings seven stories and higher permitted on or after July 1, 2027. Mayor Bill de Blasio (D) negotiated changes to the bill this week and is expected to sign it.
“Buildings are responsible for nearly half of the greenhouse gas emissions that are destroying our Earth every day,” said the bill’s primary sponsor, Councilmember Alicka Ampry-Samuel (D).
Gas ban bill sponsor Alicka Ampry-Samuel (D. 41, Brooklyn) speaks to the Council on December 15, 2021. | NYC Council
The bill addresses both climate and racial justice and essentially codifies the city’s emission reduction goals, Ampry-Samuel said.
The law directs the commissioner of buildings to deny construction permits for buildings that would require the combustion of such emitting substances, with exceptions for emergency standby power, a hardship preventing compliance with the bill, and where the combustion of the substance is used on an intermittent basis in connection with a device that is not connected to the building’s gas supply line.
This statute also requires the Mayor’s Office of Long-Term Planning and Sustainability to conduct studies regarding the use of heat pump technology, and on the ban’s impact on the city’s electrical grid.
“This bill alone will yield a savings of 2.1 million tons of CO2 by 2040, which is equal to the carbon produced from 450,000 cars in a whole year,” said co-sponsor James F. Gennaro (D), chair of the council’s Environmental Protection Committee, which oversaw the legislation.
National Grid, which distributes gas in the city, opposed the ban, saying it could increase energy costs, with a disproportionate impact on low- and fixed-income families.
“National Grid shares New York’s goal for economy-wide decarbonization,” National Grid spokeswoman Karen Young told NetZero Insider. “We recently announced the progress we’re making with our own decarbonization plan to transform our networks to deliver smarter, cleaner and more resilient affordable energy solutions.”
State lawmakers have written a broader bill, the “all-electric building act,” currently in committee, that would require new buildings statewide to be all-electric beginning in 2024.
The American Council for an Energy-Efficient Economy (ACEEE) on Wednesday released its sixth City Clean Energy Scorecard, with San Francisco for the first time claiming the top spot, followed by Seattle, Washington, D.C., Minneapolis, and Boston and New York tied for fifth place.
Covering municipal clean energy policies from May 2, 2020 to July 1, 2021, the scorecard ranks 100 U.S. cities across 39 states, the District of Columbia and Puerto Rico. Based on a 100-point scale, ACEEE rates the cities on five key areas of clean energy policy and performance: community-wide initiatives (such as clean energy or emission reduction targets), building policies, transportation policies, efficiency and emission reduction programs of local energy and water utilities and of municipal operations.
The COVID-19 pandemic led many cities to delay or modify planned 2020 work, but cities increased their clean energy efforts in late 2020 and early 2021. | ACEEE
Top-scoring San Francisco received 74 points (up 1.5 points from 2020), while at the bottom of the list, Baton Rouge had a total of only 3.5 points (down 2.5 points from 2020). However, ACEEE reported that it had revised some of its scoring criteria to reflect current energy policies and give added weight to equity policies and performance. As a result, 65 cities scored lower than in 2020, the report says.
The report underlines the significant impact city policies and programs can have on climate change. Citing figures from the International Energy Agency, the report says, “Cities around the globe are responsible for nearly three-quarters of the world’s energy consumption and more than 70% of energy-related carbon dioxide emissions.”
The COVID-19 pandemic put a damper on clean energy programs in many cities through 2020, caused by funding, staffing and operational challenges, the report said. However, the first half of 2021 saw renewed momentum on clean energy, with a particular focus on the buildings sector.
While many cities have set targets for reducing GHG emissions from transportation, only eight are tracking data on emission reductions and of those, only three — Kansas City, San Diego and Providence — are meeting their goals. | ACEEE
“A lot of the activities were the creation of new incentive programs to encourage retrofits of homes and businesses,” said Stefen Samarripas, local policy manager for ACEEE, speaking at a Wednesday webinar launching the report. “There’s a lot of room to make further improvements in building energy efficiency by creating requirements that property owners make improvements to those properties.”
Data collection is another area for improvement, Samarripas said. Many cities “are not tracking consistently the data that would be needed to figure out if they’re on track to achieve [emission reduction goals],” he said, which is “particularly notable when it comes to transportation-specific goals.”
Only about one-quarter of the cities on the list have set emission-reduction goals for transportation, Samarripas said. Of those, only eight are tracking their data, and of those eight, only three — Kansas City, San Diego and Providence — are hitting their targets, he said.
The Total Buy-in Equation
The webinar also featured energy managers from three cities — San Francisco, Madison and Washington, D.C.
Debbie Raphael, director of San Francisco’s Department of the Environment, said her city has reduced its greenhouse gas emissions 41% since 1990, while its population has grown 22% and GDP 200%. The secret behind those numbers, she said is a “total buy-in equation.”
“It starts with the leadership of our mayor, our elected officials,” Raphael said. “We have business and educational institutions that are bought in — our community organizers, our residents and our voters. … So, this package of buy-in, this package of willingness to take risks and take bold action to prevent harm is what leads to those kinds of numbers.”
Raphael also noted that San Francisco had also recently released an updated climate action plan that is science-based, includes metrics and accountability, and is “centered on people, not just carbon,” she said. “It looks at the power unique within cities and that is land use, the power of land use to affect our greenhouse gas emission reductions. Our mayor [London Breed] loves to say, ‘Housing policy is climate policy.’”
Her advice to other cities is to approach climate and clean energy policy with “radical curiosity.”
“We’re going to have to challenge our assumptions about people’s behavior, about what people need, about what services are possible, what incentives are necessary,” Raphael said. “We really need to ask, with an open mind, what are the programs that will move the needle?”
The First Electric Fire Engine
Wisconsin’s capital is one of the most improved cities in ACEEE’s 2021 rankings, going from No. 64 in 2020 to No. 39 this year. At least part of that leap can be traced to the city’s progress toward running municipal operations 100% on clean energy by 2030. Madison is almost at 75%, said Jessica Price, the city’s sustainability and resilience manager, and “reaching this goal has really required us to take an innovative and multifaceted approach,” she said.
Madison has installed 1.3 MW of behind-the-meter solar at its city facilities, Price said, and the majority of those installations were completed through the city’s GreenPower workforce training program that prepares young people for jobs in renewable energy.
On the transportation side, she said, the city now has 60 electric vehicles and 100 hybrid EVs, and in June, it unveiled the nation’s first electric fire engine. Madison this year passed an ordinance requiring EV charging infrastructure in parking facilities.
Price also emphasized the need for regional collaboration, especially for mid-sized cities such as Madison. “Partnering with our local government neighbors can be a really powerful strategy for scaling up our work, creating regional change, sharing success stories, sharing failures and leveraging our resources,” she said. “Oftentimes we’re operating with limited budgets, limited resources, and the ability to collaborate with folks on shared priorities can be a great way to move things forward.”
Operationalizing Equity
Maribeth DeLorenzo, sustainability director for the nation’s capital, said ACEEE’s increased focus on equity reflected work now underway in her city. “Both at the mayoral level and on the council level, we have new offices of racial equity,” she said. “We’ve been working on racial equity impact assessments that are city-wide, so really moving from understanding how important racial equity is … to how do we operationalize that and what does it look like for us in D.C.”
One way, DeLorenzo said, is the city’s focus on affordable housing and the development of an affordable housing retrofit accelerator. The program helps affordable housing owners understand the city’s building energy performance standards and how to leverage opportunities for building efficiency, according to D.C.’s Sustainable Energy Utility.
D.C. also faces a complicated challenge in cutting its transportation emissions, a significant part of which are caused by commuters driving into the city from the Maryland and Virginia suburbs. To get people out of their cars, DeLorenzo said the city had rolled out three new car-free lanes for buses and bikes along key commuter routes, while also working on electrifying its own municipal fleet.
Echoing Raphael, she also emphasized the importance of buy-in. “In some places, it means focusing on adaptation. In some places, it means lining up partners who may have disparate interests with the same aim at the end,” she said. “And then in other places, it really means taking a hard look at our climate action through the lens of who has the ability to [have an] impact.
Room for Improvement
Funding in the bipartisan infrastructure bill — and in the Build Back Better Act, now stalled in the Senate — has cities excited and looking at how they will plug into the federal dollars.
One challenge, Raphael said, is that the money will come through the state in the form of grants or other funding opportunities before it gets to the cities. “How do we help cities communicate up to the state [and] states to the feds so that we at the implementation side, whether it’s affordable housing or transportation, get the money we need in the right ways that we need it so that we serve our communities?” she said.
The report also has recommendations for program development — with or without federal funds — stating that even the scorecard’s top-ranking cites have room for improvement. Key suggestions include:
A range of social equity policies, such as creating a formal clean energy decision-making body of historically marginalized community residents and helping minority-owned and women-owned businesses to secure local government clean energy contracts.
Mandatory policies designed to improve the energy performance of existing buildings, such as energy benchmarking and performance standards and policies to promote energy efficiency retrofits.
Higher targets for community-wide and transportation-specific clean energy goals. As noted, setting transportation goals and metrics are a major lapse in local clean energy policies.
“We know the actions that need to happen, on the building sector, on the transportation sector, on the social and environmental justice sector,” Raphael said. “It’s really a question of political will. And that political will gets built from a foundation of government power and expertise and support by our private sector and by our residents. That’s what we need. We need us all to lean in.”
The North American Energy Standards Board (NAESB) has started a standards project aimed at improving coordination between the natural gas and electricity markets, with the goal of helping to prevent issues like those that beset the bulk power system during February’s winter storms.
In a press release issued Tuesday, NAESB said its board of directors voted to approve the project, which was proposed by SPP, at its meeting Thursday. The organization hopes to complete the new standards and submit them to FERC by the end of next year.
February’s cold snap brought extremely low temperatures to large parts of Texas and the Midwest and led to widespread generation outages, derates or failures to start that lasted for days in some cases and led to more than 23 GW of manual firm load shed. (See Slow Storm Restoration Sparks Anger in Texas, South.) A report by staff from FERC, NERC and the regional entities released last month found that natural gas facilities accounted for more than 50% of generator failures, both in terms of the number of units and in their total nameplate capacity. (See FERC, NERC Release Final Texas Storm Report.)
The joint report urged that Congress, state legislatures, and regulatory agencies require natural gas facilities to implement and maintain cold weather preparedness plans, and that generator owners and operators “identify the reliability risks related to their natural gas fuel contracts.”
Staff also called on the electric and natural gas industries to strengthen their winter preparedness and coordination, in light of the mutual interdependencies exposed by the storms. For example, some parts of the gas distribution system failed because they lacked power, leading to further outages at gas-fired generators.
NAESB’s project is intended to build off of the joint report’s findings, as well as the work of its own Gas-Electric Harmonization Committee, which “has been meeting since June to … complement the joint inquiry.”
The organization has worked with FERC on gas-electric coordination before; the commission first adopted coordination standards submitted by NAESB in Order 698, issued in 2007. FERC in 2015 approved an update to the standards with Order 809. The standards provide requirements for communication between interstate pipelines and gas-fired power plants regarding fuel requirements and operational issues that might impact gas delivery.
Earlier this year the commission ordered utilities to implement the latest version of NAESB’s Standards for Business Practices and Communication Protocols for Public Utilities (RM05-5). (See NAESB Standards Gain Final FERC Approval.)
In an email to ERO Insider, a spokesperson for SPP said February’s storms drove home to the RTO the importance of fuel supply issues, leading the organization to add its first member from the gas pipeline industry, Southern Star Central Gas Pipeline, in order to “strategically align with fuel resources and enhance the coordination between the electric and gas industries.” The email called NAESB’s standards project a chance to “kick-start the industry process with gas and electric market participants already at the table.”
“I am pleased that the NAESB board of directors endorsed this standards project and determined to place the item on all three quadrant annual plans with a goal of initiating the development of new and enhanced gas and electric coordination business practices early next year,” said Michael Desselle, SPP’s chief compliance and administrative officer, as well as the chairman of NAESB’s board.
ERCOT has pushed back the resumption of in-person stakeholder meetings from January to February, the grid operator said Tuesday.
The grid operator had expected to resume face-to-face meetings next month with the Jan. 26 Technical Advisory Committee. It told market participants the meeting will now revert back to a virtual format. Staff will provide another update in January to “manage expectations.”
The postponement was caused by a delayed transition to ERCOT’s new headquarters facility, which was approved by the Board of Directors in 2020. The 37,000-square-foot facility was expected to be ready in January.
Stakeholder meetings will continue to be conducted virtually, as they have been for almost two years now.
FERC has granted stakeholders a 24-day extension until Jan. 14 to file comments on MISO’s plan to redefine its capacity market during the 2023-24 planning year. Interested parties originally had until Dec. 21 to comment.
MISO has requested commission approval to conduct four seasonal capacity auctions, with separate reserve margins and using a seasonal accreditation based on a generating unit’s past performance during tight conditions (ER22-495).
The grid operator has also filed separately to create a minimum capacity obligation, where a MISO load-serving entity must demonstrate that at least 50% of the capacity required to meet their peak load is secured ahead of the voluntary capacity auction (ER22-496).
The RTO originally intended that a minimum capacity rule would be part of the seasonal auction design, but stakeholders said including the rule could risk FERC’s rejection of the entire capacity design.
The grid operator made both filings on Nov. 30 despite stakeholder discomfort with the design’s capacity accreditation and minimum capacity requirement components. They asked MISO to only file the seasonal auction and do further work on the availability-based accreditation before sending it to FERC. (See Last-minute Unease over MISO’s Seasonal Accreditation.)
Entergy asked for more time to comment on the seasonal auction and accreditation and a coalition of clean energy groups asked for an extension of the minimum capacity obligation. Both said the filings were too long and complex to digest and file comments before the holidays.
“The MISO region is experiencing significant shifts in generation resource retirement, increased reliance on intermittent resources, significant weather events with correlated generator outages, and declining excess reserve margins,” the RTO explained in its filing.
Organization of MISO States President Julie Fedorchak said the current annual reserve margins and accreditation have clearly become inadequate.
“The dynamics of the system are far, far different today,” she said during MISO’s December Board Week.
MISO’s Richard Doying said the new accreditation is necessary because it no longer relies on a forced outage rate for generators, but on a question of “were you there when we needed you?”
“We’re trusting that we’re setting ourselves up for the situation that’s on the doorstep,” MISO Executive Director of Market Development and Design Scott Wright said during a special November workshop to discuss the filing with stakeholders.
MISO made two late additions to its seasonal proposal in November. It will now factor in when generation owners make facility upgrades that stand to increase their capacity accreditation. In those cases, the RTO said it will reflect the generators’ increased capability in accreditation values.
The grid operator also said its zones can seasonally clear beyond its annual $257/MW-day cost of new entry (CONE). It said some seasons could clear in near-shortage conditions, making a clearing price of up to $1,000/MW-day appropriate.
Under MISO’s current planning resource auction setup, the maximum clearing price is set at CONE, which is calculated by dividing the new generator costs over 365 days. Now, CONE will be divided by a season’s days.
MISO said multiple seasons could possibly clear in near-shortage conditions, stacking revenues in excess of the annual CONE value. Should that happen, staff would retroactively reduce the clearing prices. Because the adjusted prices could create revenue sufficiency problems for generators MISO has proposed issuing make-whole payments in those instances.
Stakeholders have asked the RTO to first estimate the impacts of the auction’s greater offer cap. Some said pivotal suppliers in certain zones could manipulate an auction by making higher offers.
Staff has said suppliers are still bound to the Independent Market Monitor’s conduct thresholds and their own facility-specific reference levels.
Barbara Tyran | American Council on Renewable Energy
As the frequency and severity of extreme weather events continue to increase and the clean energy transformation accelerates, grid operators and regulators across the country are faced with difficult decisions on how to ensure cost-effective, reliable service.
Two new studies illustrate the value of interregional transmission in solving an important part of this challenge. Their commonality reinforces the significance of their findings: We have the opportunity today to “read postcards from the future.”
The first, Potential Customer Benefits of Interregional Transmission, submitted by GE International to the American Council on Renewable Energy (ACORE), points to three geographic areas today with greater than 70% renewable penetration: California, Denmark and SPP. The report posits that the entire U.S. will have 20 to 50% renewable energy penetration by 2035. We can learn valuable lessons about load management and system operations from the areas with higher renewable energy penetration now. The report recommends examining the value of regionalization that has been validated for SPP, California and Denmark in an overall assessment for the broader U.S.
The second report, Fleetwide Failures: How Interregional Transmission Tends to Keep the Lights on When There is a Loss of Generation, highlights the asset value of the U.S. transmission system: 600,000 miles, of which 240,000 miles is intraregional and interregional high-voltage transmission. The report, written by Grid Strategies, describes the performance of the grid during several recent examples of extreme weather, including the 2021 Texas power outage, the 2021 California heat wave, the January 2019 Polar Vortex, and the 2017-2018 Bomb Cyclone. The analysis illustrates the benefits of interregional transmission access, which can serve as a “lifeline” during periods of interruption. As documented in other studies, including a FERC-NERC investigation, the localized nature of extreme weather underscores the important role of interregional cooperation and access to new electricity supplies. As an example, each additional gigawatt of transmission capacity connecting ERCOT with neighboring states in the Southeast could have saved $1 billion in damages and provided energy to 200,000 homes during February’s winter storm.
Forced outages in PJM during the 2019 polar vortex | PJM
The “postcard from the future” in both reports aligns around the utilization of today’s best practices to guide future energy planning efforts. Because decarbonization mandates will likely continue/increase — as will extreme weather events — geographic regions with higher renewable energy penetration provide a window into how to operate future power systems reliably and affordably in the new paradigm. As pointed out in the GE report, resilience is based on three types of reliability: 1) adequacy (fuel diversity); 2) operations (flexibility); and 3) stability (grid strength). We can begin to address these three attributes today to achieve resilient decarbonization. The report concludes, based on contemporary experience, that interregional transmission access (“greater regionalization”) is the most cost-effective mechanism for achieving resilience in a world with higher renewable energy penetration.
Today’s experience also reveals that it is difficult to accurately evaluate consumer benefits on a regional basis and that guidance must be established at the national level in order to be fully effective.
We can glean important information today from those geographic areas with higher renewable energy penetration that will help prepare us for a seemingly inevitable path ahead. Let’s study those examples now so that we arrive together in 2035 with empirical knowledge and confidence in our power system. Reading “postcards from the future” is smart and highly useful.
Barbara Tyran is the director of the American Council on Renewable Energy’s Macro Grid Initiative, which seeks to expand and upgrade the nation’s transmission network to deliver job growth and economic development, a cleaner environment and lower costs for consumers.
Washington Gov. Jay Inslee on Monday unveiled a $626 million climate change policy wish list for the state legislature to tackle in its upcoming session.
The measures have the support of several key Democratic leaders, whose party controls both legislative chambers in Olympia.
The wish list includes massive decarbonization efforts in buildings down to 20,000 square feet in size. The second largest source of Washington’s carbon emissions — 23.4% — comes from heating residential, commercial and industrial structures.
Another item calls for plans to help Washington companies keep up with foreign competition as they trim their emissions. Tax rebates for buying new and used electric vehicles are also proposed. Money will be sought for hybrid electric ferries.
State money will be sought to help restart a dormant aluminum smelter with equipment that produces lower carbon emissions than before, and to build a solar panel manufacturing plant in the middle of the state. Many other programs also are scheduled to be included in a group of bills that Inslee’s allies will introduce to the legislature.
None of those bills have been filed yet. The 60-day legislative session begins Jan. 10, 2022.
‘Jobs Program Like No Other’
At a press conference Monday, Inslee said the $626 million is already on the state’s financial books. “These are existing revenues,” he said. “There are no new revenue sources in the package.”
The governor’s calculations do not include potential income from the federal Build Back Better program being debated in Congress. “Whatever comes out of that, we will massage the numbers” Inslee said.
Inslee acknowledged that none of his prior spending proposals have survived the legislature unscathed, but he voiced optimism that most of this package will likely make it through. “This is a jobs program like no other,” said Inslee, who has contended for years that a green economy will lead to more jobs.
At the press conference, state Sen. Reuven Carlyle (D), chairman of the Senate Environment, Energy and Technology Committee, said he believes Democratic support will be strong. “We have a policy framework, and this package builds on that infrastructure.”
The bulk of that framework lies in three Washington laws.
One sets overall carbon-reduction targets of 45% below 1990 levels by 2030, 70% by 2040 and 95% by 2050. A law passed last spring ordered carbon emissions from gasoline and diesel fuel sold in Washington be cut by 10% below 2017 levels by 2028 and 20% by 2035. Transportation accounts for 45% of Washington’s carbon emissions. Another law passed last spring was the nation’s second cap-and-trade bill following a California law.
Washington’s cap-and trade law would create a system to set total industrial carbon emissions annually, a cap that slowly decreases through the years. Large emitters would submit bids to the state quarterly in an auction for segments of that year’s overall limit and be allowed to emit that amount in greenhouse gases. Companies would be allowed to buy, sell and trade those allowances. Washington policy makers anticipate the auctions will raise several hundred million dollars that the state can allocate to various programs.
Rep. Mary Dye, ranking Republican on the House Energy and Environment Committee, argued that Inslee’s proposals are ineffective.
“The governor’s proposal to decarbonize buildings, to get rid of the natural gas industry and retrain workers whose jobs would be eliminated from his policies would do nothing to reduce deadly, destructive wildfires and the smoke they emit,” Dye said in a statement. “The governor’s proposal to spend millions of dollars in rebates for electric vehicle purchases would do nothing to prevent flooding or address drought that threatens our farmers. … Where are his proposals to address the top concerns he mentioned at the beginning of the press conference?”
The Details
The biggest planks of Inslee’s requested legislative package include:
A push to have all new construction in the state “net zero ready” by 2034. “Net zero” in this context means a building’s heating sources result in no net carbon emissions. A 2019 Washington law allows the state to regulate the energy performance of buildings 50,000 square feet or larger. Inslee’s proposal would expand that regulatory authority to buildings down to 20,000 square feet.
A bill to require that gas utilities submit decarbonization plans to the Washington Utilities and Transportation Commission every four years. These plans would include emission reduction strategies and how to support renewable hydrogen and electrification efforts.
A call for the legislature to create a state climate office to coordinate all of Washington’s global warming measures.
A $50 million allocation to tackle how Washington companies can compete with foreign competitors that don’t have to implement carbon emission measures. These industries include steel and aluminum production, pulp and paper mills, and food processors.
A request to have tribal consultants advise on climate change matters, including early notification of ventures that would impact their lands and treaty rights. Inslee faced political blowback after vetoing that provision in the cap-and-trade bill passed last spring.
The creation of tax rebates for residents buying EVs. To qualify for the rebate, a person would have to earn less than $250,000 as a single tax filer, or a couple less than $500,000 as a joint household filer. The proposed rebates are $7,500 for a new vehicle and $5,000 for a used one. An additional $5,000 rebate would go to an EV purchaser earning less than $61,000 annually, which is 60% of the state’s median income.
Money allocated to build two 144-car hybrid electric ferries and to convert another regular ferry to a hybrid electric model.
Appropriations to help restart the dormant Italco aluminum smelter in Whatcom County in northwestern Washington. The proposed restart would come with equipment that would trim carbon emissions below August 2020 levels, when Alcoa shut down the plant, leading to the loss of 700 jobs. Two unidentified companies have expressed interest in buying and reviving the plant. A political wrinkle is that most of Whatcom County is in a legislative district represented by two Democratic House members and Republican Sen. Doug Ericksen, a climate change skeptic who is the legislature’s leading opponent of most of Inslee’s environmental measures. Ericksen’s position is usually that environmental measures kill jobs.
A state grant to help build a solar panel manufacturing plant in Grant County in central Washington.
