A rent control plank prompted the greatest opposition to a Washington Senate bill to trim the carbon footprint of roughly 50,000 buildings in the state.
Senate Bill 5722 is being modified to include a cap on rent increases in order for building owners to receive state money to trim carbon emissions from their structures, Anna Lising, senior policy adviser to Gov. Jay Inslee, told the Senate Environment, Energy and Technology Committee Thursday at a public hearing. The bill is part of Inslee’s package of climate-related legislation unveiled in December. (See Flood of Climate Bills to Greet Wash. Lawmakers.)
While the size of the incentive fund is currently not in the bill, speculation emerged in Thursday’s hearing that it could be in the range of $150 million.
The bill by Sen. Joe Nguyen (D) calls for the state’s Department of Commerce to set draft standards to trim carbon by Dec. 1, 2023, for buildings ranging from 20,000 to 50,000 square feet. A 2019 law already addresses the carbon footprints of buildings that are greater than 50,000 square feet, which number about 10,000 in the state. The state must inform the affected building owners by July 1, 2025.
The Commerce Department would fine-tune the standards and submit a report to the legislature in 2029. It would have to adopt the standards in 2030, and the new rules would go into effect in 2031.
Twenty-seven percent of Washington’s carbon emissions come from buildings, the second largest emitter behind vehicles at 45%. In 2018, Washington’s carbon emissions totaled 99.57 million metric tons (MMT). A 2008 law set emission goals of 50 MMT by 2030, 27 MMT by 2040 and 5 MMT by 2050.
“We cannot meet our greenhouse gas limits without substantial action in the building sector,” said Emily Salzberg, an official with the Commerce Department.
The rent control cap prompted pushback from construction, real estate, utilities and business lobbyists. They argued that linking rent control — tentatively set for four years after the improvements are made — with receiving state aid for that work will lead building owners to stay away from applying for state financial help.
“We want the government to have more skin in the game with the incentives,” said Rod Kauffman, president of the Building Owners and Managers Association of Seattle King County.
Environmental groups, the cities of Shoreline and Olympia, and several private citizens supported the bill. Twelve people testified in favor of the bill and 13 against it. Three hundred twenty-eight people signed up to state their positions without testifying with 290 supporting the bill and 38 opposing it.
MISO on Thursday told stakeholders it had removed a 10-MW size limit on aggregations of distributed energy resources (DERs) from its FERC Order 2222 compliance proposal.
During a Distributed Energy Resources Task Force (DERTF) meeting, DER Program Manager Kristin Swenson said MISO removed the limit and will not propose a size limit on either aggregations or a single asset within an aggregation.
The RTO surprised stakeholders late last year by announcing the 10-MW limit. It has been on record multiple times saying it wouldn’t limit the size of aggregations in its markets under Order 2222.
Several stakeholders attending a late November DERTF meeting said it was the first they heard of a maximum threshold on DER aggregations. Staff cited market power concerns and simplified generation outage coordination for setting the size limit.
Swenson said MISO may have to revive discussions on size limits if unusually large aggregations seek wholesale market access. She said staff expects most aggregations to be relatively small but said it’s possible that an 80-MW wind farm on the distribution system could expect to participate in the markets without first entering the generator interconnection queue.
The grid operator plans to rely on its electric storage resource participation model to let DER aggregations participate in the wholesale market. It also said aggregations must be limited to a single pricing node and must self-commit. MISO has said it will not provide output forecasts for the aggregations. (See MISO Draws on Storage Model for DER Aggregations.)
The RTO is currently drafting the compliance filing.
“We’re in the crunch time here. There’s going to be a lot of tariff language,” Swenson warned stakeholders late last year.
Staff has said they don’t expect the Order 2222 compliance to cover all DER applications in the wholesale market.
“We have a lot to learn about DERs and how they will participate in the market,” Swenson said.
MISO is also contemplating whether it needs a forum to discuss DERs after it achieves FERC compliance.
The DERTF is slated to sunset July 31. Stakeholders are debating extending the sunset date by a year or transitioning it into a working group to address evolving and growing DER participation.
MISO says stakeholders can modify the group and reestablish a charter that doesn’t explicitly mention Order 2222 compliance once the RTO has a compliance ruling. It is accepting stakeholder input on whether to maintain a dedicated DER stakeholder group.
WEC Energy Group’s Chris Plante predicted more DER issues will need to be discussed once states have more assets on their distribution systems.
MISO legal counsel Michael Kessler said he doesn’t see a need for stakeholder work on Order 2222 or DER aggregation participation until FERC’s ruling.
“We’re going to be in a hold mode waiting on FERC,” Kessler said.
With the New Mexico legislature’s 2022 session scheduled to start Tuesday, the state has released a discussion draft of a bill that would set a statewide target of net-zero greenhouse emissions by 2050.
The bill, known as the Zero Emissions Economy Act, would also set an interim target for reducing GHG emissions by 50% below 2005 levels by 2030.
The New Mexico Environment Department (NMED) distributed the draft bill by email this week. Comments will be accepted through noon on Jan. 18 and may be sent to 2022act@state.nm.us.
The bill would allow the use of carbon offsets to help meet the 2050 net-zero goal. But even with offsets, GHG emissions would be capped at 10% of 2005 levels in 2050 and beyond.
This would “provide a check on absolute emissions to ensure they do not increase just because they are offset,” NMED said.
The bill would require the New Mexico Energy, Minerals and Natural Resources Department (EMNRD) and NMED to release an annual greenhouse gas inventory, showing progress toward reaching GHG reduction goals. Each year agencies would also assess the impacts of climate change on disadvantaged communities and whether new policies are needed to meet the GHG reduction targets.
NMED would have until June 30, 2025, to petition the Environmental Improvement Board to promulgate rules to lower GHG emissions from sources subject to the Air Quality Control Act.
Camilla Feibelman, director of the Sierra Club Rio Grande Chapter, said the group was still reviewing the draft bill. But she noted that the bill’s 2030 goal of reducing GHG emissions by 50% relative to 2005 levels was more ambitious than the 45% reduction that the governor set as a 2030 target in 2019.
Another positive is that the 50% reduction by 2030 would be actual emission reductions, without the use of offsets, she said.
“Taking real action to put greenhouse gas reductions in law … is essential,” she said.
In addition to the net-zero bill, Feibelman said she’s hoping to see a substantial “earth shot” investment in the state budget to drive a just transition on climate.
Steve Michel, deputy director of the Clean Energy Program at Western Resource Advocates, said WRA generally supports the bill.
“It’s moving us in the right direction, and it’s meaningful,” Michel told NetZero Insider.
Michel said he’d prefer a bill with more frequent benchmarks on the road to net zero, along with additional details on how to get there. And moving more quickly toward net zero would be preferable, he said, given the seeming acceleration of the climate crisis. Still, he called the bill an important step.
Governor’s Support
The state legislative session will run through Feb. 17. The focus of the 30-day session that takes place in even-numbered years is budgets, appropriations and revenue bills, as well as bills introduced at the behest of the governor — known as the “governor’s call.”
The bill is one of three that Democratic Gov. Michelle Lujan Grisham committed to including in her governor’s call during a two-day climate conference in October. The others are a bill that would establish a clean-fuel standard for transportation fuels and a hydrogen hub act. (See NM Draft Bill Would Encourage Hydrogen Buildout.)
In a January 2019 executive order, Lujan Grisham directed the state to join the U.S. Climate Alliance and set a goal for the state to reduce greenhouse gas emissions by 45% by 2030 compared to 2005 levels. The order also established an interagency climate change task force.
During the October conference, Lujan Grisham stressed the importance of codifying the GHG reduction targets into state law.
“If you don’t have that framework in statute, it’s too easy to not work as diligently or as quickly or as effectively,” she said.
The proposed legislation follows the failure of last year’s House Bill 9, the Climate Solutions Act. HB9 would have required “quantifiable and enforceable statewide greenhouse gas emissions reductions” of at least 50% percent below 2005 levels by 2030 and net-zero emissions by 2050. The bill stalled in committee.
Feibelman and Michel pointed to factors that might make this year’s Zero Emissions Economy Act more likely to succeed. The bill is much simpler than the Climate Solutions Act and has the direct backing of the governor, they said.
PJM on Wednesday proposed moving the upcoming Base Residual Auction originally scheduled for later this month to the end of June to comply with FERC’s order partially reversing its decision on the RTO’s energy price formation revisions.
Pete Langbein, of PJM’s capacity market and demand response operations, updated the Market Implementation Committee on the capacity auction dates, saying FERC recognized the RTO will need to delay the BRA to implement a revised energy and ancillary services (E&AS) offset, a key variable in calculating the net cost of new entry (CONE) for resources in capacity auctions.
PJM must submit a compliance filing with the commission by Jan. 21 proposing a new schedule for the BRA and subsequent capacity auctions impacted by the delay. FERC reversed its approval of PJM’s forward-looking E&AS offset on Dec. 22 (EL19-58). The commission said PJM must now revert to the previous, backward-looking offset. (See FERC Reverses Itself on PJM Reserve Market Changes.)
Langbein said FERC is not requiring PJM to rerun capacity auctions that utilized the forward-looking offset because doing so would “undermine the expectations of the parties who are making commitments for the 2022/23 delivery year.”
“This is a little bit of a rock and a hard place based on the holiday gift we got from FERC,” he said. The switch will impact net CONE for the reference resource used in the variable resource requirement curve, the market seller offer cap (MSOC) and the minimum offer price rule. PJM plans on making the compliance filing “as straightforward as possible,” Langbein said.
“We want to make sure we allow time for any activity that gets impacted by the E&AS change.”
PJM needs to maintain the current 120-day time frame for the MSOC unit-specific review process, Langbein said. The RTO also plans to allow sellers to maintain previously submitted and approved gross avoidable-cost rates.
The auction delay will also result in an update to calculations of the capacity emergency transfer objective and capacity emergency transfer Limit and the load forecast. Langbein said the updates impact the reliability requirement, the fixed resource requirement commitment and the elimination of one additional energy efficiency installation period.
Langbein said pre-auction activities not impacted by the E&AS change or updates in the load forecast will maintain existing information that was already submitted for the auction.
Updated Auction Schedule
PJM is attempting to get back to the normal auction schedule by the 2027/28 BRA, Langbein said, and the proposed schedule will allow that to happen.
Langbein said PJM has proposed conducting the 2022/23 third incremental auction (IA) based on the existing schedule of Feb. 28 and continuing to use the forward-looking E&AS offset, as it was used in the 2022/23 BRA.
The RTO wants to compress the timeline between auctions from 195 days to 175 days. The 2024/25 BRA would move from August to December; the 2025/26 auction would move from February 2023 to June 2023; and the 2026/27 auction would move from August 2023 to November 2023. The 2027/28 BRA would be back on schedule in May 2024.
The first and second IAs would be canceled for the 2023/24, 2024/25 and 2025/26 BRAs. The first IA would be canceled for the 2026/27 BRA.
Langbein said the proposed schedule has not been finalized.
“We’re still collecting input,” Langbein said. “But based on what we have today, this is what the schedule would look like.”
The California Public Utilities Commission heard nearly three hours of public testimony Thursday on its proposal to dramatically reduce the amount homeowners receive for sending excess solar power to the grid.
The plan has sparked a heated debate that now includes movie stars, a former NBA great, billionaire Elon Musk and Gov. Gavin Newsom. The CPUC is scheduled to vote on the plan Jan. 27.
At issue is the state’s net energy metering (NEM) framework, which pays homeowners full retail rates for electricity without requiring them to fund grid maintenance or pay interconnection fees. (See California PUC Proposes New Net Metering Plan.)
A CPUC proposed decision in December called for wholesale changes to net metering by imposing a new avoided-cost rate that would consider the value of behind-the-meter generation for resource adequacy and grid reliability, potentially slashing the reimbursement rate to less than half the original rate. It would also impose an interconnection fee that does not currently exist, averaging about $40/month.
The CPUC said the net metering rules in place since the 1990s unfairly require average ratepayers to compensate homeowners who can afford the upfront costs of rooftop solar arrays.
“Our review of the current net energy metering tariff … found that [it] negatively impacts nonparticipating customers, is not cost-effective and disproportionately harms low-income ratepayers,” CPUC Administrative Law Judge Kelly Hymes wrote.
About half the testimony Thursday came from the rooftop solar industry, homeowners with solar, and others who support their cause. They argued that altering net metering rules will decimate solar adoption and benefit the state’s large investor-owned utilities, which stand to profit from utility-scale solar.
“One of the most important policies that helped grow rooftop solar in California is NEM, and with the ongoing climate emergency it’s critical that we get buildings off gas and transition to a fossil fuel-free future,” Berkeley Mayor Jesse Arreguin said as he urged the commission to reject the proposed decision.
The other half of the public comments came from residents who said their utility bills are too high because they subsidize rooftop solar, and from union workers who build utility-scale solar.
“I support the [proposed] decision,” Mark McCray, a member of the International Brotherhood of Electrical Workers, told the commissioners. “Rooftop solar costs six times more than utility-scale solar, and we simply cannot afford to overpay for a resource, especially now that we have a lot of wildfire costs. People are hurting financially from the COVID pandemic. The decision is what California needs for its clean energy future, so for more affordable electricity and for high quality jobs, please adopt the decision.”
The session was the first meeting with new CPUC President Alice Reynolds presiding. She replaced former President Marybel Batjer, who retired in December.
Martha Guzman Aceves, the lead commissioner in developing the proposed net metering decision, also left the CPUC late last year to head EPA’s Region 9.
With a new president and without Guzman Aceves, the fate of the net metering plan remains uncertain. Reynolds, a former energy adviser to Newsom, did not give any indication Thursday on whether she would support the proposal.
But on Monday, in a press conference announcing his 2022-23 budget plan, Newsom said he felt the NEM proposal needs more work. “Do I think changes need to be made? Yes, I do,” the governor said in response to a reporter’s question.
Celebrities also have entered the debate. Actors Edward Norton and Mark Ruffalo opined on Twitter that the CPUC’s plan was wrongheaded.
“Please don’t let new California net metering rules derail rooftop solar,” Ruffalo said on Twitter, addressing Newsom.
Norton posted a dozen times on Twitter about the proposal, saying “California utilities like PG&E want to maintain their monopoly and look for every opportunity to kill rooftop solar which liberates customers from their control.”
Tesla CEO Musk tweeted that the net metering proposal was a “bizarre anti-environment move” by the California government.
And former NBA star and commentator Bill Walton wrote an open letter to Newsom urging him to “do the right thing … and send this disastrous CPUC ‘solution’ back to the beginning.”
None of the celebrities offered public testimony at Thursday’s CPUC meeting.
Government officials and utility planners lack the tools and policies needed to address climate change, despite growing awareness that it is an increasing threat to infrastructure and public health, researchers said Wednesday.
“There’s clear evidence that [severe events’] likelihood and intensity are increasing under climate change. And yet there’s very little understanding of how to model their amplified impacts on infrastructure, energy systems and communities,” Roshanak Nateghi, a Purdue University professor of industrial engineering, told an Energy Bar Association webinar.
Nateghi, whose research focuses on the resilience of energy systems, said federal relief policies that are responsive to “rapid onset events” like hurricanes fail to recognize long-term threats such as droughts, heat waves and sea level rise.
“Droughts and heat waves are amongst the most costly and lethal [events] in the U.S. Just one example is the Chicago heat wave back in 1995, where 50,000 customers lost power; over 700 people died,” she said. “And yet when you go back to the disaster relief database, you’ll see very disproportionately less … investment.”
Clockwise from top left: Roshanak Nateghi, Purdue University; Heather Payne, Seton Hall University of Law; Judsen Bruzgul, ICF, and Michael Craig, University of Michigan | Energy Bar Association
Heather Payne, professor of energy and environment at the Seton Hall University School of Law, said the “poster child” for the disconnect is Kivalina, an Alaskan native village that has sought federal funding to relocate because of sea level rise “and yet has been denied that multiple times by [the Federal Emergency Management Agency] because they don’t view the impacts from climate change as within their discretion.”
Payne also cited the Nuclear Regulatory Commission’s 2019 decision to relicense the Turkey Point nuclear plant south of Miami through 2052 despite concerns over sea level rise.
Nateghi said FEMA’s policies encourage perverse incentives. “For FEMA to release some of those [disaster] funds … the damage needs to be a certain [number of] dollars per head. … So in a way, you’re encouraged to sustain a lot of losses … to be able to qualify.”
Lack of Data
The recognition that severe events can be longer in duration and cover a wider region demands “a different, or at least complimentary, approach to reliability, planning and investment,” said Judsen Bruzgul, senior director of climate resilience for consulting firm ICF International.
University of Michigan professor Michael Craig, who models regional power systems to test their resilience, said the industry hasn’t done enough research on how different parts of the power system will interact under extreme events.
In the past, utilities used decades of past meteorological data for planning. “That prior 40 years is not representative of what we will see in the future. … So where do I get my meteorological data now?” he asked. “The unsatisfactory answer is you get it from climate models. But the climate models were not built to give that data to utilities. They don’t capture these extreme events well. They’re not at the resolution that they want them at.”
Nateghi said utilities generally have access to some type of weather forecasting capability. “What I often find missing is a model that translates the climate impact to infrastructure impact. A lot of times I think that translation happens based on expert knowledge, which would have been fine if our climate system was stationary. But … that translation — based on gut feeling as opposed to in a data-driven way, which is guided by the physics of the infrastructure — is not always helpful.”
‘Duty to Serve’ Must Change
Payne, whose work focuses on the legal and policy changes needed for economy-wide electrification, said climate change requires a change to the common-law concept of utilities’ “duty to serve” all customers within their monopoly territory.
“As climate change alters the conditions of the natural world, utilities will find themselves in the situation where continuing to provide service, reinstalling infrastructure to provide service where it has been lost, or providing new service would be considered imprudent,” she argues in an upcoming paper.
“I take a fairly expansive view of what utilities and regulators can and should be doing,” she said Wednesday, reiterating arguments from a prior paper on what she calls the “natural gas paradox.”
“The first thing is that they need to not be making the problem worse, right? So you should not be putting any fossil fuel infrastructure into your system at this point. I mean, if you want to be part of the solution, I actually do view that it’s that simple.”
She said regulators should also repurpose existing spending on programs like energy efficiency in order to reduce ratepayers’ energy burden. “I can go to my local Home Depot, and energy efficiency money will make it so that I can purchase reduced-price LED light bulbs. I don’t think that’s necessarily the best use of our energy efficiency funds.”
Payne said she is dismayed by how little public participation there is in utility integrated resource plan proceedings. “I have looked at lots of IRP dockets where you have all of two filings: You have the initial plan that the utility put in, and you had order from the PUC accepting or adopting it. And that’s it,” she said. “Something that I think regulators need to work on is really finding more ways to have communication.”
Aligning Mitigation and Adaptation
Craig said researchers and planners don’t know yet whether it is possible to align adaptation policies with climate mitigation policies.
“These are things that we need to think of together rather than separately. These are long-lived assets: 20, 30, 40 years. So they’re going to be around as climate change intensifies.”
A carbon price that incentivized investment in low-carbon generation “does not necessarily make you more adapted to climate change,” he said. “You could be putting nuclear power plants or carbon capture and sequestration on the sea or on rivers that in 10 or 20 years … that are going to be affected by sea level rise.”
Craig said the traditional “beneficiary pays” principle of utility regulation can be unfair to those most impacted by climate change.
“You have situations where now people who are most impacted by climate change — wildfires are a perfect example — are exposed to tremendous costs, and upgrading the grid and those same communities might be the least able to fund it.
“If I have a rural community in Oregon that is now facing public safety power shutoffs, I can underground that line [at a cost of] millions of dollars. Can that community pay for it?” he said. “That is a challenge to me in terms of how we think about regulating and distributing these costs.”
ICF’s Bruzgul sees promise in the use of “adaptation pathways,” which seeks to escalate responses as the severity of climate impacts intensify rather than initially seeking the most expensive solutions.
The EPA’s Tuesday announcement that it will crack down on coal-ash ponds has an outsized impact on Midwestern coal plants.
The EPA proposed that three coal plants in the region stop dumping waste into unlined ash ponds and denied the facilities extensions of an April 2021 deadline to initiate the ponds’ closure. Affected plants include the Indiana Kentucky Electric Corp.’s 1.3-GW Clifty Creek Power Station in southern Indiana; American Electric Power’s 2.6-GW Gavin Power Plant in southern Ohio; and Interstate Power and Light’s 726-MW Ottumwa Generating Station in southeastern Iowa.
The agency opened a 30-day comment period on its proposed determinations. It also said East Kentucky Power Cooperative’s 1.3-GW H.L. Spurlock Power Station might receive an extension until Nov. 30, provided it fixes groundwater monitoring problems.
The EPA’s actions represent the Biden administration’s first steps to enforce coal-ash disposal regulations enacted in 2015. The EPA’s Coal Combustion Residuals Rule required most of the country’s 500 unlined ash pits to stop receiving waste and to begin closure activities by April 2021.
Coal ash contains toxic materials that can seep into groundwater, including mercury, cadmium and arsenic.
“I’ve seen firsthand how coal-ash contamination can hurt people and communities. Coal ash surface impoundments and landfills must operate and close in a manner that protects public health and the environment,” EPA Administrator Michael S. Regan said in a Tuesday press release. “For too long, communities already disproportionately impacted by high levels of pollution have been burdened by improper coal ash disposal.”
4 MISO Plants Deemed Incomplete
The EPA also said four coal plants in MISO’s footprint submitted incomplete applications to postpone the closures of their ash ponds.
The agency said Ameren Missouri’s 1-GW Meramec Energy Center in St. Louis and its 1-GW Sioux Energy Center in West Alton, Mo., submitted inadequate information in their extension requests. It also singled out the City of Springfield, Ill.-owned 200-MW Dallman Power Station and the Lansing Board of Water & Light’s Erickson Power Plant in central Michigan for unfinished applications.
Ameren plans to retire the Meramec’s coal-fired units by the end of 2022 and to wind down operations at the Sioux Energy Center sometime in 2028.
The Lansing Board of Water & Light has said it will retire its Erickson Power Plant by 2025. Springfield retired an aging unit at Dallman last year following storm damage.
The EPA said it will make more decisions on extension applications for ash ponds or pit closure dates in the coming months. It said it has 48 more eligible applications to review from facilities that want to keep dumping waste into their unlined ash ponds.
The agency also said Tuesday that it will begin contacting facilities with coal ash ponds that have insufficient cleanup information or have poor monitoring records.
“As the transition from coal advances, it is also critical that we responsibly manage the legacy wastes that have been left from our historical reliance on coal,” Liesl Clark, director of the Michigan Department of Environment, Great Lakes, and Energy, said in a statement. “We support EPA’s ongoing efforts to provide clarity around the coal combustion residuals rules and to ensure that our world-class freshwater resources and the drinking water they provide are not impacted by these legacy wastes.”
Citing “continued concerns about traveling and the growth of the Omicron” variant of COVID-19, NERC Board of Trustees Chair Ken DeFontes confirmed Wednesday that February’s meetings of the board and Member Representatives Committee (MRC) will be held virtually, rather than partially in person as originally planned.
Speaking at the MRC’s informational webinar this week — intended to preview the agenda and topics of discussion for next month’s meetings — DeFontes acknowledged that the news would bring “significant disappointment” and leave attendees “frustrated.” But in light of the recent return to rapid spread of the coronavirus, the chair said the decision to keep the meetings online-only was “the prudent thing to do.”
The number of daily cases of COVID-19 reported to the Centers for Disease Control and Prevention has spiked in recent months beyond any previous high points in the ongoing pandemic. More than 1.4 million cases were reported on Monday, the highest single-day figure since the novel coronavirus was first reported in the U.S. nearly two years ago. As of the same day, the seven-day moving average stood at more than 750,000 cases, with a total death count of more than 837,000.
A major driver of the recent explosive growth is the Omicron variant, first identified in November 2021 and “exponentially increasing in multiple countries,” according to the CDC. Omicron possesses both “increased transmissibility and the ability to evade immunity conferred by past infection or vaccination,” the agency said last month, meaning that even those who are protected against the original coronavirus or the Delta variant that emerged last year are still vulnerable to the new strain.
“Concerns about lower vaccine efficacy because of new variants have changed our understanding of the COVID-19 endgame, disabusing the world of the notion that global vaccination is by itself adequate for controlling SARS-CoV-2 infection,” according to a study published last month in The Lancet.
The study emphasized that while there is some evidence that the effects of Omicron may be less severe to individuals than previous variants — particularly for fully vaccinated people who have received booster shots — the speed of transmission means that “existing public health prevention measures” such as masking, social distancing and avoiding enclosed indoor spaces will be necessary to control the spread of the virus and prevent the health care system from becoming overloaded.
No Word on Rest of 2022
NERC’s board and MRC have not met in person since Feb. 6, 2020, when they gathered in Manhattan Beach, Calif. (See NERC Board of Trustees Briefs: Feb. 6, 2020.) The organization curtailed all of its in-person gatherings, including technical committee and standard drafting team meetings, the following month, after many participating bodies enacted travel restrictions in light of the pandemic.
February’s meetings were to have been the first step of relaxing these constraints: At the November 2021 meeting, DeFontes said the plan was for the board and MRC to gather in person at NERC’s Atlanta office while all other attendees joined virtually. (See “Hybrid Meetings to Start in February,” NERC Board of Trustees/MRC Briefs: Nov. 4, 2021.) The May and August meetings were tentatively planned to be held in-person in D.C. and Vancouver, Canada, respectively, while the November 2022 meeting would have likely been another hybrid gathering.
At November’s meeting, DeFontes emphasized that these plans had not been finalized. While he did not elaborate on the remaining meetings for 2022 in Wednesday’s call, it is probable that they will have to be revised as well.
Cap-and-trade is expected to yield Washington $500 million a year in revenue, said the state agency charged with running the program.
Forty percent of that money will be targeted at disadvantaged communities that are especially vulnerable to climate change, and another 10% will go to the state’s tribes.
“It’s a simple fact that some communities are hit harder by pollution than others,” Kathy Taylor, Air Quality Program manager at the Washington Department of Ecology, said at a briefing of the state Senate Transportation Committee on Monday.
The rest will be earmarked for other climate-oriented purposes; two-thirds aimed at funding transportation projects, which are expected to receive $1.4 billion in cap-and-trade funds between 2023 and 2027 and $5.16 billion by 2037. Transportation accounts for 45% of Washington’s greenhouse gases.
Passed last year, Washington’s cap-and-trade law — dubbed “cap-and-invest” — goes into effect on Jan. 1, 2023. This year state officials will focus on regulatory rulemaking as well as tweaking the 2021 law. On Monday and Tuesday, Department of Ecology officials briefed the Washington Senate Transportation Committee and a webinar of industry representatives on separate portions of the 2022 efforts.
Washington was the second state to adopt a cap-and-trade law after California, which is in a cap-and-trade pact with Quebec, with the auctions handled by the Western Climate Initiative. Washington recently entered a contract with WCI to administer its auctions.
The cap-and-trade law calls for the Department of Ecology to develop proposed cap-and-trade regulations by this spring and to formally adopt the rules this fall.
At a Tuesday webinar, Ecology Department officials briefed industrial representatives on the state’s tentative plans. The industrial representatives limited their feedback to technical questions.
The agency’s plan calls for an undetermined number of emissions allowances to be auctioned four times a year to smokestack industries. The first two auctions are scheduled for the first half of 2023, and the state will set the number of “allowances” 60 days prior to the auctions.
Companies would bid on the allowances in clusters of 1,000 individual allowances. The number of allowances will be decreased over time to meet 2035 and 2050 decarbonization goals. Companies will be allowed to buy, sell and trade those allowances. If Washington chooses to join the California-Quebec pact, it would expand its purchase and trading territory to those two areas.
For each auction, a specific number of allowances would be made available to bidders. All bids must be above a certain price level set in advance by the state.
The highest bidder would get first crack at the limited number of allowances, while the second highest bidder would get second crack, followed by additional iterations. The auction ends when the last of the designated number of allowances is bid upon. Then all the successful bidders pay the same clearing price set by the lowest successful bid.
Bidding companies are limited to acquiring 4 -10% of the total number of allowances, depending on various criteria.
Rep. Joe Fitzgibbon (D), chair of the House Environment and Energy Committee, has introduced a bill(HB 1682) to tweak the 2021 cap-and-trade law by providing free allowances to “trade-exposed” state industries that compete with foreign entities that don’t have regulations decreasing their carbon outputs. Those free allowances would decrease by 6% annually from 2035 to 2050.
That bill has advanced to the Environment and Energy Committee, but no public hearing date has been set.
The Biden administration’s emphasis on decarbonizing the U.S. economy may be more vulnerable to foreign influence than oil ever was.
That the administration is aware of this vulnerability is apparent in the U.S. Geological Survey’s proposed expansion of its list of minerals critical to U.S. supply chains, now expanded to 50 from the 35 in the previous administration.
It also is in favor of domestic mining these minerals, as detailed in the Infrastructure Investment and Jobs Act approved in November that called for the departments of the Interior and Agriculture to work on streamlining permitting for the mining of rare-earth minerals on federal land. (See Energy Groups Quick to Praise Infrastructure Bill Passage.)
The importance of minerals and the vulnerability created by not sourcing them at home or through companies located in friendly nations could become an issue slowing the effort to move away from carbon-intensive fuels.
But developing policies to promote domestic mining and mineral refining as well as global sourcing while not alienating competing interests or making decarbonization look impossible is a balancing act.
D.C.-based think tank OurEnergyPolicy presented a webinar on the issue Wednesday that focused on the underlying issues, including the politics, and the development of policies to make the nation less vulnerable. The webinar was part of the group’s Energy Leaders Webinar Series and will soon be publicly available online.
Sharon Burke, president of Ecospherics | OurEnergyPolicy
Sharon Burke, president of energy and environmental research group Ecospherics, moderated the discussion. She noted that the nation is more than 50% import-reliant on 31 of the 50 rare-earth minerals and 100% import-reliant on about a dozen of them.
Melanie Kenderdine, principal at the Energy Futures Initiative, said the politics surrounding the issue make it difficult for policymakers.
“It’s a little bit of an inconvenient truth,” she said. “There is a suggestion that ‘renewables’ that are free and everywhere are not necessarily as secure as we might think.”
Part of the problem, she suggested, is that the public and many policymakers “tend to think of energy security as fuel.”
“These are not fuels,” she said of rare-earth minerals. “They are capital costs. And so the lifespan of these technologies … that is what defines the draw on the metals and minerals that we are talking about here today. The lifespan of these technologies is defining the extent of the energy security problem we’re talking about here.”
Melanie Kenderdine, principal, Energy Futures Initiative | OurEnergyPolicy
Kenderdine suggested that the U.S. Department of Energy and Energy Information Administration begin keeping detailed statistics on strategic minerals and metals as they already do with natural gas, oil and refined products.
Morgan Bazilian, director of the Payne Institute at the Colorado School of Mines, agreed, but added that keeping track of metals and minerals “is not as simple in some ways as understanding the global oil market or the increasingly global natural gas market.”
“What we have in critical minerals is at least 35 and probably closer to 50, as you alluded to, and maybe even a little bit more of deeply fragmented, very small, poor price transparency and poor governance markets,” he said. “So it is much more difficult to group these things together because they are individually very different and so all of that combined, makes a very different problem.”
Asked to compare the Biden administration’s approach to minerals with that of the Trump administration, Aaron Thiele, legislative assistant for energy and natural resources to U.S. Sen. Lisa Murkowski (R-Alaska), said he thought that overall “there is a good level of continuity and urgency.”
Aaron Thiele, legislative assistant to U.S. Senator Lisa Murkowski (R-Alaska) | OurEnergyPolicy
“I think the administration is kind of grappling with some of their constituencies, and the critical minerals debate always comes down to whether or not it’s going to increase domestic mining and that has its sticky points in politics,” he said.
Thiele said moving from fossil-based technologies to renewables involves tradeoffs and new resource requirements.
“The question is, if we are taking this rapid transition to renewable energy resources, to electric vehicles, where are we going to be in 10 years if we don’t have either domestic [mineral] or partner agreements with nations to lessen that impact? The demand for these minerals is going to be there. The question is, where are we going to source it? Are we going to be able to recycle it, or are we going to substitute it? There is going to need to be a supply side,” he said.
Kenderdine said developing recycling technologies will be important because alternative technologies are not ready for commercialization.
“Recycling and reuse becomes very important,” she said. “I would prioritize that first. And looking at alternatives for these metals and minerals. That’s going to take time and infrastructure.
“Domestic mining, I think, becomes very important,” she added. “But there are a lot of issues with that as well. So I would put recycling and reuse very high up on the agenda, and we should be requiring it.”
Burke asked Bazilian whether the priorities outlined by Kenderdine and Thiele are the right strategy.
Morgan Bazilian, director of the Payne Institute, Colorado School of Mines | OurEnergyPolicy
“I think there has to be a bigger conversation about the balance between the kinds of things Aaron talked about, which is the domestic industry,” Bazilian said. “This is a big issue for developing economies; a lot of them take a lot of their GDP from extractive industries like mining. And focusing solely on our needs or the needs of one country, in general, is bad policy, right? It doesn’t work. We’re in a deeply interconnected world.
“I understand the politics of it, but it’s not the way to do something well. And so, you know, we have to really play a role in this international debate, and support some of these other countries and try to make a thoughtful balance between the domestic and the international,” Bazilian said.
“I recognize, however, that that sounds naive,” he quickly added. “In other words, that’s not how domestic politics go. The priority is clearly and always going to be on the domestic role for this and the jobs and those things at the state level. … [But] if you don’t look at this from a larger perspective, you’re going to make policies that are either inefficient or just bad.”
