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November 19, 2024

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PJM Reveals Preliminary Capacity Auction Timeline

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.

Proposed revised pre-auction activity schedule (PJM) Content.jpgPJM’s proposed revised pre-auction activity schedule. | PJM

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.”

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California PUC Takes Heat on Rooftop Solar Plan

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.

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Researchers: New Policies, Data Needed to Respond to Climate Threats

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.”

EBA Panel 2022-01-13 (Energy Bar Association) Content.jpgClockwise 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.

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EPA Coal Ash Enforcement Impacts Midwest Coal Plants

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.”

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Omicron Forces NERC to Retreat from Hybrid Board Format

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.

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Cap-and-trade Projected to Provide Wash. $500M Annually

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.

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Critical Minerals: America’s Achilles Heel?

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 (OurEnergyPolicy) Content.jpgSharon 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 (OurEnergyPolicy) Content.jpgMelanie 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 (OurEnergyPolicy) Content.jpgAaron 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 (OurEnergyPolicy) Content.jpgMorgan 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.”

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Washington Bill Would Factor ‘Climate Resilience’ into Water Systems

The big question on a Washington bill to add “a climate resilience element” to regulating residential water systems was: What would that rule physically do?

Sen. Mark Schoesler (R) posed that question Wednesday at a public hearing on the bill held by the Washington Senate’s Environment, Energy and Technology Committee.

Introduced by Sen. Christine Rolfes (D), Senate Bill 5626 would order the Washington Department of Health to require public water systems serving 1,000 or more connections to include a “climate resilience element” as part of water system plans, beginning Jan. 1, 2024. Local governments would be required to study how climate change could affect their water systems and then take remedial measures.

The bill would allocate $10 million every two years to help with those measures. That was the part that stumped Schoesler.

“What are we going to buy for $10 million?” he asked.

Rolfes said she had not seen the committee staff’s $10 million estimate until just before the Wednesday morning hearing. “The $10 million is new to me,” she said. Meanwhile, committee staff members were also unsure about what the allocations would be used for, other than acting on potential problems identified by studies.

Committee member Sen. Liz Lovelett (D) then pointed to her hometown of Anacortes on Fidalgo Island, which is long and narrow, and juts westward like a peninsula into Puget Sound from northwestern Washington. A water channel converts the “peninsula” into an island.

Lovelett noted that rising water levels from Puget Sound had periodically flooded water lines in and around Anacortes, prompting the town to move its water lines to higher elevations. She cited that as a possible remedial action that could have used a grant from a $10 million state fund.

Five people testified in favor of Rolfes’ bill, including representatives from the Sierra Club, the Washington Public Utility Districts Association and the Climate Impacts Group at the University of Washington. No one testified against the bill.

All stressed the need for studies to pinpoint threats from flooding and wildfires, which they linked to global warming.

Amy Snover, director of the Climate Impacts Group, said a data clearinghouse is needed to help local governments find information to evaluate potential threats from flooding and wildfires. Geography and topography would be major factors in those evaluations, she said.

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BOEM to Auction Six New Lease Areas in NY Bight

Increasing its bet on offshore wind, the Biden administration announced Wednesday that it will auction six lease areas in the New York Bight on Feb. 23, enough to site at least 5.6 GW of generation.

The six leases in the Bureau of Ocean Energy Management’s (BOEM) sale notice are the most ever offered in a single auction, totaling 480,000 acres. BOEM had solicited commercial interest for 1.7 million acres in the Bight but excluded 72% of the area to reduce environmental impacts and avoid conflicts with the commercial fishing industry and other ocean users. BOEM issued its final environmental assessment on the lease areas in December. (See BOEM Issues Final Environmental Review of NY Bight.)

Interior Secretary Deb Haaland, who announced the auction in a press conference Wednesday with New York Gov. Kathy Hochul and New Jersey Gov. Phil Murphy, said the leases will include stipulations to encourage the use of union labor, building of a domestic supply chain and “planned” transmission.

The announcement of the new leases came the same day the Department of Energy issued a report identifying five strategic priorities for maximizing the value and reducing the costs of offshore wind. The Biden administration has set a goal of 30 GW of offshore wind by 2030; with states on the East Coast already committed to a pipeline of 39 GW by 2040, DOE said the country could deploy 110 GW by 2050 — equal to 6% of current demand.

Murphy said the Biden administration’s enthusiastic support for OSW was a marked change from the Trump administration. “I think the most charitable word I can use is [the Trump administration] slowed whatever progress we were making; [I] wouldn’t necessarily say they stood in the way,” Murphy said. “They started out [wanting] to drill for oil and gas offshore. … So this is just night and day.”

Supply Chain, Labor

Like state officials, the Biden administration has promoted the new generation as economic development projects.  

BOEM said it will require lessees to describe their plans for contributing to development of a domestic supply chain and will offer a 50% reduction in the “fee rate” for five years for lessees that “meaningfully and substantially” assemble or manufacture major components in the U.S. That would reduce the fee rate from 2% to 1%.

The operating fee will be based on a proxy for the wholesale market value of the power generated from each project. The proxy will assume a 40% capacity factor for the first six full years of commercial operations, with potential adjustments based on actual generation in future years. BOEM will use the simple hourly average of the spot price for NYISO’s Zone J in New York City. At a wholesale power price of $40/MWh, the annual 2% fee for a 1,028-MW facility, would be $2.9 million.

New York, which has targeted 9 GW of OSW by 2035, will base procurement of offshore wind renewable energy credits (ORECs) in part on economic benefits provided by the projects, including domestic supply chain and port infrastructure investments, benefits to disadvantaged communities and creation of jobs and workforce training programs.

New Jersey, with a goal of 7.5 GW, has approved $350 million in tax credits tied to capital investments in offshore wind-specific facilities in the state.

Officials from BOEM and the two states have created a supply chain working group that will meet quarterly to coordinate their efforts.  

“We are now going to have a very significant regional cluster between New York and New Jersey that will make it very compelling … for folks to not just install, but build the stuff here,” Murphy said.

“This opportunity we’re presented with today is absolutely transformative, not just for New York and New Jersey, but for our nation,” said Hochul.

BOEM also will require lessees to “make every reasonable effort” to sign contracts with labor unions for construction.

“We’ve been laser focused on offshore wind for several years because we think that this can be the sector that is the shining example of how the clean energy economy can create high-road, high-quality jobs,” said Liz Shuler, president of the American Federation of Labor and Congress of Industrial Organizations (AFL-CIO), who also took part in the press conference. “… I can speak from the perspective of workers in the energy industry. They’ve been skeptical of the transition, because [they] have not seen the same quality, stable careers in clean energy that they have in the industries that they’ve worked in in the past. And there hasn’t been a commitment historically to high-quality jobs in the clean energy economy. But it doesn’t have to be that way.”

Transmission Planning

BOEM’s sale notice urged strategic planning of transmission, saying the agency is considering “the use of cable corridors, regional transmission systems, meshed systems, and other mechanisms.” It said it may condition approval of construction and operations plans “on the incorporation of such methods where appropriate.”

The DOE report said “strong near-term efforts” are needed to plan transmission to incorporate OSW “without long delays or lost opportunities.

“There is a lack of sufficient onshore transmission capacity to transmit power from the strongest offshore wind resources to load centers,” DOE said. “…Creating incentives to plan and share transmission across multiple offshore wind projects, states, and transmission planning regions can encourage collaboration in infrastructure planning, cost allocation, and transmission system development that can benefit all states within and across regions.”

Sites

The sites to be leased will be 20-69 nautical miles from New York and 27 to 53 miles from New Jersey, with minimum depths of 31 to 50 meters and maximum depths of 46 to 63 meters. BOEM has established a minimum bid of $100 per acre for the leases, which the agency said could produce 5.6 GW based on 3 MW per square kilometer.

BOEM listed 25 companies eligible to bid in the auction, each of which posted a $5 million deposit. BOEM said it would limit each company to only one lease to maximize competition in future procurements and limit consolidation of the offshore wind market.

Before the auction, BOEM will hold its fifth and final meeting with the fisheries community on Jan. 19 to describe how it decided on the final lease areas.

The final sale notice reduced the area by 22% from the preliminary notice, reflecting concerns by the fishing industry, the U.S. Coast Guard, the National Marine Fisheries Service and the Department of Defense (DOD).

It excluded lease area OCS-A 0543 in response to issues raised by the fishing industry and DOD and to make room for the siting of a “fairway” proposed by the Coast Guard to accommodate traffic travelling across the NY Bight from the Delaware Bay area to east of Montauk.

It also eliminated several areas that overlap with both fishing activity and seafloor features sensitive to impacts from construction. No leases were offered within 2.5 nautical miles of the Mid-Atlantic Scallop Access Area. BOEM also removed areas to the west of OCS-A 0539 that are used by the Atlantic surf clam fishery.

DOE Priorities

In addition to calling for planned transmission, the DOE report listed four other priorities for the nation’s OSW plans:

  • Expanded federal incentives to increase demand for offshore wind energy and grow the domestic supply chain;
  • Technology innovation and adaptations to reduce costs. “New system designs are required for U.S. operating conditions, such as deep water in the Pacific, hurricanes in the Gulf of Mexico, and ice formation in the Great Lakes,” DOE said. “Accessing wind resources in deep-water areas (~60% of the U.S. offshore wind resource) will be key to reaching long-term deployment goals. The deployment of floating offshore wind platforms … will be critical to development in the Pacific, Gulf of Maine and other regions with deep waters.”
  • Increase the transparency and predictability of regulatory processes and auction new lease areas. “The number of lease areas will need to grow significantly over the next decade to meet state and federal deployment goals,” DOE said.
  • Invest in supply chain development, including customized offshore wind ports and vessels. “Building a domestic supply chain and growing the industry will require dozens of port upgrades, numerous Jones-Act compliant vessels, and new factories for component manufacturing and assembly,” DOE said.

Interest in Gulf of Mexico 

In comments posted by BOEM on Jan. 11, Ørsted and Shell New Energies U.S. (NYSE:RDS.A) expressed interest in bidding for potential OSW leases in the Gulf of Mexico.

ClearView Energy Partners said BOEM could offer leases in the Gulf as early as the first half of 2023.

“While existing energy infrastructure and supply chains in [Gulf of Mexico] coastal states may attract offshore wind project developers (indeed, commenters note that offshore wind generation could facilitate green hydrogen production), we emphasize other factors could dampen interest in comparison to the East Coast, including lower electricity prices, the lack of strong state-led decarbonization policies in the GOM area and higher risks of severe hurricanes,” ClearView said in a note to clients.

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DOE to Tackle Tx Siting, Financing, Permitting in Better Grid Initiative

The Department of Energy on Wednesday announced the launch of the Building a Better Grid (BBG) Initiative, aimed at attacking the many obstacles to building out the long-distance, high-voltage transmission network that the Biden administration sees as key to decarbonizing the U.S. electric system by 2035.

“The foundation of our climate and clean energy goals is a safe, reliable and resilient electric grid that is planned hand-in-hand with community partners and industry stakeholders,” Energy Secretary Jennifer Granholm said in a press release. Using federal dollars from the Infrastructure Investment and Jobs Act (IIJA), the initiative will “upgrade the nation’s grid, connect more Americans to clean electricity and broadband, and reliably move clean energy to where it’s needed most.”

Getting to President Biden’s goals of a decarbonized grid by 2035 and a net-zero economy by 2050 will require the grid to expand by 60% by 2030, according to DOE, and by three times its size by 2050. Large renewable projects in remote areas, as well as offshore wind, will need high-voltage transmission lines to efficiently bring power to urban demand centers.

But, according to the DOE, about 70% of the nation’s existing transmission lines and transformers are more than 25 years old. At the same time, hundreds of gigawatts of clean power projects sit in grid operators’ queues, unable to connect because of a lack of transmission capacity.

A 2021 study from the Lawrence Berkeley National Laboratory estimated that 750 GW of solar and wind and 200 GW of storage were backed up in U.S. interconnection queues at the end of 2020.

The need for grid flexibility and resilience has also been underlined by power outages caused by extreme weather or other catastrophic events, such as California’s wildfires, this summer’s extreme heat in the Northwest and the winter storm in Texas last February.

As detailed in a notice of intent released Wednesday, “DOE intends to launch a coordinated transmission deployment program to implement both IIJA and previously enacted authorities and funding.”

A transmission needs study will “identify where new or upgraded transmission facilities could relieve expected future constraints and congestion driven by [the] deployment of clean energy; … higher electric demand as a result of building and transportation electrification; and insufficient transfer capacity across regions.” Additional studies will look at viable pathways to a large-scale transmission system over the next 15 to 30 years, as well as transmission pathways for integrating offshore wind.

Provisions of the IIJA allow DOE to participate in public-private partnerships and to become an “anchor customer” for new and upgraded transmission lines, buying as much as 50% of a project’s planned capacity for a term of up to 40 years. The law also provides a $2.5 billion revolving fund to support the construction of new, replacement or upgraded high-capacity transmission lines, and another $3 billion in matching grants for grid-enhancing technologies, such as dynamic line ratings, flow control devices and network topology optimization.

The IIJA also gives DOE the authority to designate national transmission corridors in “any area experiencing or expected to experience electricity transmission capacity constraints or congestion that adversely affects consumers.” It also authorizes FERC to issue permits for the construction or upgrade of projects in such corridors. DOE intends to prioritize corridors that “overlap with or utilize existing highway, rail, utility and federal land rights of way.” It will also offer developers pre-application review of projects and coordinate with FERC on permitting.

‘Prioritize and Expedite’

The initiative was announced Wednesday by the Biden administration as part of a suite of energy initiatives.

Interior Secretary Deb Haaland kicked off the day with the announcement of next month’s auction of six offshore wind lease areas in the New York Bight, off the coasts of New York and New Jersey. The 480,000 acres in the six lease sites, the most ever offered in a single auction, could eventually generate 5.6 to 7 GW of power. The Bureau of Ocean Energy Management will hold the auction Feb. 23. (See related story, BOEM to Open Six New Lease Areas in NY Bight.)

The Interior Department also took the lead on the rollout of a new cross-agency effort to streamline reviews of wind, solar and geothermal projects on federal land. A memorandum of understanding signed by the Interior, Agriculture, Defense and Energy departments and EPA calls for the agencies to “prioritize and expedite” reviews of these projects. Interagency teams staffed with subject matter experts will help advance environmental reviews and “accelerate renewable energy decision making,” according to the MOU.

Making a Dent

All three initiatives drew praise from Democratic lawmakers and clean energy advocates, but reactions also included calls for the Senate to pass the Build Back Better Act, which includes tax credits for a range of renewable technologies and transmission.

While applauding BBG, Rep. Kathy Castor (D-Fla.), chair of the House Select Committee on the Climate Crisis, said, “I am determined to help communities lower costs with the transition to a resilient and clean energy economy, and I look forward to working with my Senate colleagues to ensure that the critical transmission investments in the Build Back Better Act reach President Biden’s desk, so he can sign them into law.” 

Gregory Wetstone, president and CEO of the American Council on Renewable Energy, said interagency efforts to streamline permitting “will ensure the American people benefit from the best solar and wind resources this country has to offer.” BBG will “unlock the potential of America’s clean energy economy by catalyzing the nationwide buildout of the long-distance, high-voltage transmission.”

Noting that China is investing 80 times more than the U.S. in transmission, Rob Gramlich, executive director of Americans for a Clean Energy Grid, said that BBG and the federal dollars in the IIJA “could make a big dent in the national transmission challenge.”

But he also cautioned that “the funding levels are nowhere near what is required for a national macrogrid. … Congress will also need to pass the Build Back Better Act with the tax credit for regionally significant transmission because there is no way to recover costs of large interstate lines presently.”