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November 2, 2024

NERC RSTC Revisits Rejected Standards Projects

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.

NYC to Ban Natural Gas in New Buildings Beginning 2024

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).

Alicka Ampry (NYC Council) Content.jpgGas 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.

US Cities’ Progress on Clean Energy Rebounds in 2021

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.

New City Clean Energy Action Breakdown (ACEEE) Content.jpgThe 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.

GHG Emission Reductions (ACEEE) Content.jpgWhile 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.”

NAESB Starts Gas-electric Coordination Project

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 In-person Meetings Delayed to February

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 Grants Comment Extension for MISO Capacity Filing

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.

Stakeholder Soapbox: Low-cost, Reliable Power Service Depends on Large-scale Tx

By Barbara Tyran

Barbara Tyran (American Council on Renewable Energy) FI.jpgBarbara 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) Content.jpgForced 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.

Inslee Unveils $626M Climate Legislation Wish List

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.

Dominion’s Solar and Onshore Wind Plans Draw Heat

Dominion Energy’s proposal to develop new solar and energy storage resources faced harsh criticism in hearings before the Virginia State Corporation Commission (SCC) Monday and Tuesday.

Dominion is asking the SCC to approve its annual Renewable Portfolio Standard (RPS) Development Plan, which it filed Sept. 15 to comply with the Virginia Clean Economy Act (VCEA), which requires the utility to reach 100% clean electricity by 2045 (PUR-2021-00146).

Dominion is asking the SCC to approve:

      • its CE-2 plan to build and operate 13 utility-scale projects totaling 661 MW of solar and 70 MW of energy storage and related interconnection facilities;
      • two small solar projects totaling 4 MW;
      • 24 power purchase agreements (PPAs) for 32 resources totaling 253 MW of solar and 33 MW of energy storage; and
      • cost recovery for three utility-scale solar projects totaling 82 MW (CE-1), which the SCC approved in April at an estimated cost of $10.4 million (PUR-2020-00134). (See Virginia SCC Gives IOUs a Pass on RPS Plans — for Now.)

Dominion attorney Elaine Sanderlin Ryan of McGuireWoods said Monday that the company opposes an SCC staff suggestion to increase stakeholder input in the request-for-proposals process. “If it’s not broken, don’t fix it,” she said. She also opposed a request by environmental group Appalachian Voices to allow interested parties to submit additional models of future power production and consumption for the company to run.

“When left to its own devices, Dominion does not prepare or even attempt to prepare viable least-cost plans,” Will Cleveland, senior attorney with the Southern Environmental Law Center, said Monday on behalf of Appalachian Voices.

Energy Department also Calls for Stakeholder Group

The Virginia Department of Energy weighed in Tuesday, saying that while it supports approval of Dominion’s projects it “has concerns regarding the efficiency of planning and procurement for RPS compliant generation” and supports commission staff’s proposal to form a stakeholder group to help the company refine its request for proposal (RFP) procedures.

Virginia Energy Director John Warren said that the VCEA’s targets “require large-scale investments to occur within a near timeframe.”

“While the company’s current proposal represents an important step towards RPS and storage goals, there is a much greater volume of generation due to be proposed and built in the coming years, and it is essential that the company is operating a fair, transparent and efficient process for planning and procuring future projects,” he said in a filing.

Warren said the stakeholder group should “at a minimum, review general RFP development, including process transparency, scoring criteria and the value of employing an independent evaluator.”

The Solar Energy Industries Association also expressed concerns while supporting Dominion’s CE-2 projects. “We believe that this represents a diverse set of projects, and that these facilities will help the company comply with its mandatory obligations under the VCEA,” attorney William Reisinger said Monday on behalf of the group.

However, he said, the solar industry finds it “extremely concerning” that Dominion is saying it may not be able to meet the 1% RPS carveout for 2021 and may have to pay the $75/MWh deficiency payment for noncompliance. That should only be done as a “last resort,” and there are sufficient resources in Virginia for the company to meet the compliance goal, said Reisinger, who was also speaking for the Chesapeake Solar and Storage Association (CHESSA).

Walmart, which operates 94 stores and two distribution centers in Dominion’s territory, also expressed reservations about the utility’s RPS plans. “We see significant costs under VCEA that are not borne by the company or solar developers; they are borne by the customers,” Carrie Grundmann, attorney with Spilman, Thomas & Battle, said Monday. She urged the SCC to compel Dominion to adopt lower-cost power purchase agreements (PPAs) rather than build out its capacity at a higher cost.

On Tuesday, her cross-examination of Emil Avram, Dominion’s vice president of business development, led to a tense exchange. The subject was a clause of the VCEA that states that “35% of such [renewable] generating capacity procured shall be from the purchase of energy, capacity, and environmental attributes from solar or onshore wind facilities owned by persons other than the utility.”

“Is there anything in the code says that only 35% can come from PPAs?” Grundmann asked him. She had argued in her opening statement the day before that the company was treating this figure as a ceiling, which meant that Dominion had to build or acquire 65%, a method that she said would be more expensive for customers.

“It’s clear to us that the law says 35% must come from third parties,” Avram said. “It doesn’t say at least, it doesn’t say at most, it doesn’t say approximately. It says 35%.”

An attorney for the utility objected to Grundmann “badgering” Avram after they went back and forth on this point for several minutes.

As of Aug. 31, Dominion said, it had 1,958.1 MW of solar and onshore wind nameplate capacity, including operating facilities, those under construction and those that have been proposed, including the CE-2 projects it is now asking the SCC to approve. PPAs constituted 788.8 MW of that total, and another 52 MW qualify as distributed solar under the VCEA, because they are 3 MW or lower capacity projects.

Through 2020, Dominion says, 322.8 MW in solar and onshore wind generation facilities had reached the commercial operation stage, including PPAs, company-owned systems, and company-owned “ring-fenced” resources that are not under contract with a potentially eligible “accelerated renewable energy buyer.” The VCEA exempts such buyers from the costs of the RPS.

By the end of this year, Dominion expects to add another 240 MW to the total, followed by 492.5 MW next year, 1,063.1 MW in 2023 and 740 MW in 2024.

From 2025 to 2035, Dominion projects it will add approximately 14,865.1 MW more in capacity, which “will offset the 16,100 MW target for the development of solar and onshore wind” set by state law. As a result, the company expects its carbon dioxide output to decline from the 2021 total of more than 15 million metric tons per year to 5 million tons in 2035, although there will be a slight increase in this pollution in the next few years.

Cost

Dominion said the cost of the RPS program to residential customers who use an average of 1,000 kWh/month would rise from 37 cents/month this year, to $5.11 in 2022, and increase more than five-fold to $28 by 2035. Under a different “directed methodology,” the total added to monthly bills in 2035 would be $43.22, the company said.

Advocacy groups were not impressed with Dominion’s plans. “Once again, I believe Dominion has failed to conduct adequate long-term, least-cost implementation planning, and the commission should reject the plan proposed here,” consultant Karl Rabago said in written testimony submitted Nov. 16 on behalf of Appalachian Voices. “Given the company’s failure to submit least-cost VCEA compliant plans for the past two proceedings, I recommend that in future proceedings, the commission require the company to perform a set number of modeling runs and sensitivities as prescribed by other parties.” Additionally, he said, SCC staff, industrial and commercial customer groups, and environmental and consumer groups should be permitted to submit alternative plans.

In written testimony submitted Nov. 17, the Virginia Department of Environmental Quality and other state agencies focused on steps Dominion would have to take to protect the Chesapeake Bay, wetlands and other sensitive areas for its planned projects to go forward.

New Jersey Lawmakers Back Municipal Bonds for EV Purchases

New Jersey lawmakers backed legislation Monday that would allow local governments to issue bonds to fund the purchase of electric vehicles, adding to the surge in legislation focused on promoting clean energy that lawmakers hope to approve before the session ends in mid-January.

The Assembly Appropriations Committee voted 10-1 with no comment to advance the bill, A-2208, which would create an exception to an existing law that prohibits local and county governments from bonding projects that have a useful life of less than five years. The law also prevents governments from issuing bonds for the purchase of passenger vehicles and station wagons.

The bill approved Monday would amend that law to permit counties and municipalities to bond for passenger cars and station wagons that are “solely fueled by a battery or equivalent energy storage device charged from an electricity supply external to the vehicle or by a renewable power source.”

The committee’s support for the bill followed the advance last Thursday of several clean-energy related bills that lawmakers would like to send to the desk of Gov. Phil Murphy by the term ends. Bills that are not enacted by mid-January would have to be refiled to move forward.

Master Plan Triggers Competing Views

Among the most high profile and contentious of the bills that moved in recent days was A5720. The bill, advanced by the Assembly Science, Innovation and Technology Committee on a 4-2 vote, would codify into law the main elements of the 2019 Energy Master Plan crafted by Murphy. The vote follows support for the bill by the full Senate in June. (See Lawmakers Back Putting NJ’s Clean Energy Plan into Law.)

At the time of the Senate vote, the bill provided a way of ensuring that Murphy’s aggressive clean energy goals would stay in place even if he lost his re-election fight on Nov. 2. Murphy won re-election with a 2.9% margin against Republican Jack Ciattarelli.

The bill would codify key planks of the plan, including the goal of putting 330,000 light-duty vehicles on state roads by 2025. Other parts of the bill would require the state’s mass transit agency, New Jersey Transit, to have in development at least one battery-powered train by 2025 and that New Jersey generate 7.5 GW of offshore wind by 2035.

The bill, which now needs the support of the full General Assembly to land on Murphy’s desk, sparked a vigorous debate over the Master Plan’s merits, and whether the proposals are realistic enough to sustain the rigidity of codification into law.

Ray Cantor, vice president of government affairs for the New Jersey Business & Industry Association, one of the state’s largest business advocacy groups, argued that the plan failed to meet the most important criteria of being affordable and ensuring that the state’s energy system is reliable. He also expressed concern that the Murphy administration had never calculated the cost of meeting its requirements.

“The Energy Master Plan was meant to be a fluid document to be updated every three years based on new information, new technology [and] new policy directions,” he said. “This would lock it in place in 2021.

“This bill would set unattainable goals, unachievable goals,” he said. “And when that happens, regulators then make bad decisions. They tend to push the limits and make requirements that can’t be met. They waste money.”

Kate Gibbs, deputy director for the Engineers Labor-Employer Cooperative, which represents operating engineers and their employers, added that the plan is “not rooted in reality.”

“It’s more about virtue signaling and relies more on political science than the laws of physics,” she said. “Passing this legislation is setting our state up for a very expensive gambit, one that New Jersey residents and businesses cannot afford. And that will put an incredible strain on the potential for long-term economic development.”

The National Resources Defense Council, Environment New Jersey and Clean Water Action said that regardless of any deficiencies in the plan, the urgency of the need to combat climate change requires that legislators codify the main plan elements. That way there is a greater likelihood that the plan will be carried out, they argued, adding that the cost of not responding to climate change — through damage and destruction from extreme weather events — would be much higher.

Eric Miller, New Jersey energy policy director for NRDC, said the legislation would enable the state to keep its commitment to reducing carbon emission policies, such as the goal to produce 7.5 GW of offshore wind energy goals by 2035.

“Putting them into law is critical to prevent any potential for future backsliding on our climate commitments,” he said. “And it also provides a more stable regulatory environment. … We support codifying the 7.5-GW wind target, which currently just exists as an executive order, so that there’s certainty New Jersey will complete all of its planned offshore wind solicitations.”

Backing Microgrids, Low-carbon Concrete

Also Thursday, the Senate Economic Growth Committee voted 5-0 to back a bill, S3593, that would authorize the creation of a program to develop six electric microgrids around the state to provide power to charge medium- and heavy-duty EVs. The bill has yet to go before the full Assembly or Senate.

The program, to be created by the New Jersey Economic Development Authority in consultation with the Board of Public Utilities and Department of Environmental Protection, would require the authority to seek proposals for the creation one microgrid in each of the six utilities that serve the state.

The Senate Environment and Energy Committee backed two clean energy bills Thursday, including one, A2360, that would require electric utilities to charge “residential rates for service used by residential customers for electric vehicle charging at charging stations” in parking garages or other parking spaces tied to residential units.

While the New Jersey Chamber of Commerce, the South Jersey Chamber of Commerce and New Jersey Utilities Association opposed the bill, NRDC submitted comments in favor, as did the New Jersey Apartment Association. The Assembly passed the bill 68-4 in June.

The committee also backed a legislation, S3732, that would provide corporation business tax credits to concrete producers that provide more than 50 cubic yards of “low embodied carbon concrete” to a project built under contract with a state agency. Low-embodied means the concrete was made with a process that creates low carbon emissions. (See New Jersey Lawmakers Back Low-carbon Concrete.)

The producer could receive a credit valued up to 8% of the cost of the concrete, and the cumulative total of all the credits issued under the bill in the state could not exceed $10 million. The committee backed the bill 4-1.

Sen. Linda Greenstein (D), who sponsored the bill, said the aim is to encourage investment by New Jersey’s concrete manufacturers in the “latest low-embodied carbon concrete manufacturing techniques.” That would “increase supply and competition while building the infrastructure necessary for New Jersey to be at the forefront of this cutting-edge effort to reduce carbon emissions of construction materials,” she said.