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November 1, 2024

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Tesla Ineligibility to Shake up Calif. Clean Vehicle Rebate Program

A price increase for certain Tesla models has made the cars ineligible for California’s clean vehicle rebate incentives, a change that could slash short-term demand for the incentive by nearly 60%, according to data presented last week.

Tesla hiked the MSRP for its Model 3 and Model Y on March 15, and Tesla vehicles are no longer eligible for the rebate, according to the Clean Vehicle Rebate Project (CVRP) website.

The program sets a cap of $45,000 on the manufacturer’s suggested retail price (MSRP) for electric cars. The MSRP cap for SUVs, trucks and vans is $60,000. The Tesla price increase in March brought the price of the least expensive Model 3 to $46,990, according to news reports.

The rebates are available for new battery electric vehicles, fuel cell vehicles and plug-in hybrids, and range from $1,000 to $7,000, based on the buyer’s income and vehicle type.

The California Air Resources Board (CARB) held a work group meeting on May 11 to discuss CVRP.

The Tesla ineligibility is projected to decrease CVRP applications for battery-electric vehicles by about 70%, and by about 59% for the program overall, Francis Alvarez, a research analyst at the Center for Sustainable Energy, said during the workshop.

“The 83% to 88% of funds going to Tesla vehicles will become available over time, likely reducing program use initially and then normalizing again as other products fill the gap,” Alvarez said in his presentation.

CVRP Changes

The Tesla ineligibility was one of several changes to the CVRP program that were discussed during last week’s workshop.

The CARB board in November approved $515 million in funding for CVRP, intended to last for three years. At the same time, the agency is planning to ramp down the program as ZEV adoption increases, while shifting the focus to lower-income car buyers.

A first set of changes was implemented in February, when statewide ZEV sales topped 1 million.

The annual income cap for car buyers dropped to $135,000 for single tax filers, down from $150,000 previously. The new MSRP cap of $45,000 is a decrease from $60,000.

Another round of changes is proposed for when ZEV sales hit 1.25 million, a milestone expected in February 2023. The income cap would drop further, plug-in hybrids would lose eligibility and the rebate amount could be reduced.

CARB is still gathering feedback on the proposed changes and watching ZEV sales trends, and the agency could decide not to implement the second phase.

Other potential changes to the program include giving rebate recipients a prepaid card to use for EV charging, in a yet-to-be-determined amount. Another possibility is to expand car-buyer prequalification so that low-income buyers could use the incentive at the point of purchase.

“In making changes to the program, we also want to make sure that we leave some funding on the table for future model releases,” said Raquel Leon in CARB’s Innovative Light-Duty Strategies Section.

Rebate Perspectives

Some workshop attendees supported holding off on CVRP changes proposed for February 2023.

“Continued programmatic changes to this program as well as other rebate programs create confusion among dealers as well as consumers,” said Anthony Bento, director of legal and regulatory affairs at the California New Car Dealers Association. “I think we need to be very cautious on making further changes.”

Eileen Tutt, executive director of the California Electric Transportation Coalition, said it’s clear that CVRP is about to become undersubscribed. Not only should the second phase of changes be dropped, she said, but the income cap should be returned to the pre-February levels.

Tutt said she knows people who were interested in buying an EV but went with a conventional vehicle after losing CVRP eligibility because of the income cap decrease.

“As we move into a 100% ZEV requirement and we really need every single person … to pick an electric vehicle, now is not the time to make it ineligible to a very large group of people,” Tutt said.

CARB staff said a second work group meeting may be scheduled in coming weeks. The agency expects to release a draft funding proposal for clean transportation incentives in mid-July.

The funding plan, which would include proposed changes to CVRP, would then go to the CARB board for approval in November.

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US and Canada Working to Deepen Energy Collaboration

Jennifer Granholm (CSIS) FI.jpgU.S. Secretary of Energy Jennifer Granholm | CSIS

U.S. Secretary of Energy Jennifer Granholm on Thursday decried efforts by some Maine residents to stop a state-approved New England Clean Energy Connect (NECEC) power transmission corridor that would link Hydro Quebec to New England.

“Hydro Quebec wants to make sure that they are able to deliver … hydropower, and a state votes against it, and that state is a critical state to be able to make that connection to the Northeast. It’s extremely frustrating because it’s left in the hands of local interests,” Granholm said without mentioning the state by name.

“We should take local interests into account, but sometimes those local interests are funded by bigger interests that don’t have necessarily the big goal of getting to 100% clean electricity,” she added in a reference to utility funding of a successful grassroots referendum drive to block the construction of an already-approved transmission line through Maine delivering Canadian hydro power to Massachusetts.

Granholm’s remarks came during an energy policy discussion with Canadian Minister of Natural Resources Jonathan Wilkinson and sponsored by the D.C.-based Center for Strategic and International Studies.

The comments also came just two days after the Maine Supreme Court heard arguments in the appeal of a lower court decision to vacate a 1-mile lease of public land for the project, halting construction of the entire corridor. (See Maine Supreme Court Hears Entangling Arguments in NECEC Appeals.)

The fight over the transmission corridor is an early warning of battles to come as the Biden administration backs utility efforts to build new transmission carrying renewable power to demand centers — key to its goal to sharply reduce power plant carbon emissions by moving to wind, solar and other renewable generating technologies.

“The barriers have always been on deployment of electricity. It’s always about the grid. And it’s always about the local NIMBY permitting challenges,” Granholm added.

She said the administration does have a new tool, a provision in the bipartisan Infrastructure Investment and Jobs Act that “allows the DOE to take a position of offtake so that those builders of transmission lines can feel some comfort that they are not going to be left holding the bag.” (See DOE Seeks Input on Tx Loan, ‘Anchor Tenant’ Programs.)

“Then we get paid back as they fill up the rest of the line,” she explained in a reference to other off takers of power flowing through a new transmission line.

“It’s a revolving fund,” she explained of the $2.5 billion allocated in the legislation to help jump start new transmission projects. “It’s a new mechanism that we’ve never used before … to ensure that we can actually get transmission [projects] going.”

“The opportunity is just so powerful to have a North American powerhouse … of an alignment on clean energy deployment and technology development,” Granholm said.

“I raised that because I think that all of our desire for peace in the world, so much of that can rest upon our movement to clean energy.

“If we are successful in converting our energy to clean, [we] can create energy security, not just for our individual countries, but around the world. We will not be under the thumb of petro-dictators. It could be a great peace plan, and that I think is a great aspiration.”

Wilkinson, in Washington to discuss energy security and climate change, said the two issues are “ultimately linked.”

“You often hear in Canada, and I assume it’s probably the case in the United States, the two polar kinds of views on this, which are: energy security has come to the fore [because] it’s so important [and] we should forget about climate change.

“On the other hand, you have voices who say climate change is an existential threat. It’s so important that you should essentially forget about energy security, at least as it relates to helping our friends and in Europe.

“There is a way for us to think about these things as being complementary, that we can work towards addressing the short-term energy security issues that have come out of Russia, that are arising from shifts in geopolitics generally,” he said.

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PJM Monitor: LMP Rose to Near Record in Q1

Energy prices in PJM increased by 75.5% in the first quarter of 2022 from a year ago, the Independent Market Monitor reported Thursday, driven primarily by higher fuel costs.

In its Q1 State of the Market Report for PJM, the Monitor said the real-time load-weighted average LMP increased from $30.84/MWh to $54.13/MWh. This is the highest first-quarter price since the polar vortex in the first quarter of 2014, the Monitor said, and the third highest increase in first-quarter LMP since the start of PJM markets in 1999. The second highest price occurred in 2003, when winter load increased and natural gas prices doubled to above $8/dekatherm that year.

Of the $23.29/MWh increase, 49% was directly from higher fuel and emission costs, especially higher natural gas prices. Both coal and natural gas prices were higher in the first quarter of 2022 compared to 2021, with prices doubling in the eastern part of the RTO.

Real-time hourly average loads in the first quarter increased by 2.4% from 2021, going from 89,887 MWh to 92,007 MWh. The total price of wholesale power increased from $53.30/MWh in the first quarter of 2021 to $80.28/MWh in 2022, an increase of 50.6%. Generation from coal units decreased 3.1% in the first quarter, while generation from natural gas units increased 6.9% compared to the first three months of 2021.

Monitor Joe Bowring said that despite the increased energy prices, PJM’s wholesale electric energy market produced competitive results in the first quarter.

“The steadily increasing role of gas-fired generation and the declining role of coal highlight the importance of ensuring that PJM has real-time, detailed and complete information on the gas supply arrangements of all generators and that PJM consider rules requiring capacity resources to have firm fuel supplies,” the Monitor said in its report. “It is also essential that FERC consider and address the implications of the inconsistencies between the gas pipeline business model and the power producer business model and the issue of market power in the gas markets under extreme weather conditions.”

Theoretical net revenues from the energy market increased for all unit types in the first quarter, the Monitor said, with theoretical energy net revenues increasing by 145% for a new combustion turbine, 94% for a new combined cycle, 54% for a new coal unit and 75% for a new nuclear plant.

Total energy uplift charges decreased by $5.9 million, or 17.2%, in the first quarter, going from $34.3 million in 2021 to $28.4 million.

Total congestion prices increased by $389.2 million, or 321.5%, going from $121.1 million in 2021 to $510.3 million in 2022. The Monitor said only 31.9% of total congestion paid by customers for the first 10 months of the 2021/2022 planning period was returned to customers through the auction revenue rights and self-scheduled financial transmission right revenues offset.

“Congestion belongs to customers and should be returned to customers,” the Monitor said. “The goal of the FTR market design should be to ensure that customers have the rights to 100% of the congestion that customers pay.”

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NERC Board of Trustees/MRC Briefs: May 11-12, 2022

Positive COVID-19 Test Prompts Return to Virtual Sessions

Multiple attendees at NERC’s Board of Trustees and Member Representatives Committee meetings this week praised the organization’s staff after a last-minute pivot from what would have been the groups’ first in-person gathering in more than two years into yet another virtual session.

The meetings — along with those of NERC’s Finance and Audit Committee, Technology and Security Committee, and Corporate Governance and Human Resources Committee — were to have been held on Wednesday and Thursday in Arlington, Va. (See “Face-to-face Meetings to Return in May,” NERC Board of Trustees/MRC Briefs: Feb. 10, 2022.) However, after an attendee tested positive for COVID-19 at the conference site Tuesday morning, NERC announced that all events would be held virtually, following up with webconference links the same day.

Speaking at the MRC meeting on Wednesday, Board Chair Ken DeFontes acknowledged that the events of the past two days were another reminder of the ongoing pandemic. He said NERC still intends to hold the August and November meetings in Vancouver, Canada, and New Orleans, respectively, though with appropriate precautions in place.

“There’s no question that we’re not done with COVID yet, and we saw the evidence of that this week,” DeFontes said. “So we are thinking about how we can shape that meeting to encourage people to come, but at the same time be prepared in the event that we have to do another virtual setup, maybe even try to look at some hybrid options.”

Standards Actions

The board voted to approve the new reliability standards FAC-001-4 (Facility interconnection requirements) and FAC-002-4 (Facility interconnection studies), bringing to an end the work of Project 2020-05.

The project began nearly two years ago with the aim of modifying FAC-001-3 and FAC-002-3. The former standard requires transmission owners and generator owners to “document and make facility interconnection requirements available,” while the latter requires GOs to “study the impact of interconnecting new or changed facilities on the bulk electric system.”

At issue with the standards was the term “materially modified,” which both FAC-001-3 and FAC-002-3 implied should be used to determine what facility changes should be studied and which should not. However, neither standard said who would determine what counts as a material modification. The existing language also created confusion with FERC’s open access transmission tariff implementation, because in FERC-jurisdictional areas, “material modification” means the impact of a new generation project on other generators in the interconnection queue.

To address these issues, the revised standards replace the phrase “materially modified” with “qualified change” throughout. In addition, a new requirement in FAC-002-4 specifies that the planning coordinator will define what constitutes a qualified change and will make the definition publicly available.

After the board accepted the new standards, Howard Gugel, NERC’s vice president of engineering and standards, delivered an update on Project 2021-07, which NERC began last year in response to the joint FERC-NERC report on the winter storms that knocked thousands of megawatts of capacity offline in Texas and the Midwest. (See NERC Standards Committee Agrees to New Cold Weather Project.)

According to Gugel, the standard drafting team (SDT) has completed an initial draft of the new standards and plans to submit it to the Standards Committee at its meeting next week for initial formal comment and ballot period. The SDT is further requesting that the comment period be reduced to 30 days from the standard 45, in hopes of finishing the standard and submitting it to FERC for approval as soon as possible.

Summer Assessment Highlights Risks in Texas, West

Large parts of North America face “elevated or high risk of energy shortfalls during peak summer conditions,” according to NERC’s upcoming Summer Reliability Assessment, due to be released next week. NERC staff previewed the assessment, along with the 2022 Long-term Reliability Assessment, during Thursday’s board meeting.

As Mark Olson, NERC’s manager of reliability assessments, explained, droughts and heat events are a major concern across the Western Interconnection and Texas.

In WECC’s footprint, these risks take the form of depleted water resources for hydroelectric generators, as well as “another active wildfire season,” Olson said. Extreme heat in Texas raises the potential for demand-related shortfalls, while thermal generators may face challenges in SPP because of lowered river water levels.

MISO faces potential shortages because of a 2.3% reduction in generation capacity since last year. Olson said extreme temperatures, high generation outages or low wind conditions could lead to outages even at normal peak demand. The assessment rates the region as the highest risk in North America.

New Québec Agreement Approved

The board also approved revisions and amendments to the agreement between NERC, the Northeast Power Coordinating Council and Québec’s Régie de l’énergie.

The existing agreement, originally approved in 2014, spells out how NERC’s Compliance Monitoring and Enforcement Program (CMEP) activities will be carried out in the Canadian province, along with establishing a Québec-specific CMEP (QCMEP). NERC, NPCC and the Régie agreed to modify the document in 2020.

The new agreement includes the following changes:

    • NPCC, NERC and the Régie may update the QCMEP without seeking approval from Québec’s government.
    • Duplicative terms have been removed, along with specific processes that are already addressed in the QCMEP.
    • Another regional entity may take over NPCC’s responsibilities if it dissolves or otherwise cannot perform them.
    • Billing of simultaneous interpretation as needed for audits is permitted.
    • A mediation and arbitration clause was added.

NERC also said the agreement contains unspecified “other administrative changes.” With the board’s approval, all that is left for the document to take effect is the acceptance of Québec’s authorities.

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NYPSC Tracks Clean Energy Progress, Questions Process

The New York Public Service Commission on Thursday established a new proceeding to track state efforts to meet the environmental goals of the Climate Leadership and Community Protection Act (CLCPA), but some commissioners pressed for a more thorough cost/benefit analysis and better defined cost allocation (22-M-0149).

Jessica Waldorf (NYDPS) Content.jpgJessica F. Waldorf, NYDPS | NYDPS

“When taking our existing renewable energy generation and combining it with the projects that are awarded, existing and contracted, 63% of the state’s generation will come from renewable sources, well on the way to achieving 70% renewable energy by 2030,” said Department of Public Service Chief of Staff Jessica F. Waldorf.

With the requirements of implementing the CLCPA falling to the PSC and the DPS, the May 12 order does not conflict with the work of the Climate Action Council (CAC) or with the work taking place in the natural gas planning proceeding or any other related proceeding. It does not include any new funding decisions, nor does it ask the commission to make any new decisions on policy issues, Waldorf said.

The PSC on Thursday also announced new planning procedures for natural gas utilities to comply with the state’s greenhouse gas emission reduction goals, as well as new rules that set forth the process for initiating, operating and lifting a natural gas moratorium (20-G-0131).

The CAC is holding public hearings on its draft scoping plan through June 10, including emissions scenarios for natural gas, and will finalize the plan by year-end for submission to the state’s elected officials. (See NY Climate Council Ramps Up Natural Gas, Alt Fuels Planning.)

Flexible Policy

“I am concerned that in some ways the draft scoping plan does seem to try to narrow some of [the issues] in a way that may not leave enough flexibility for what is under our jurisdiction, or tries too much to direct things that may more appropriately need to be carefully analyzed under our jurisdiction by the technical experts over at DPS,” said Commissioner Diane X. Burman, who abstained on the vote.

Diane X Burman (NYDPS) Content.jpgNYPSC Commissioner Diane X. Burman | NYDPS

Commissioner David Valesky seconded Burman, saying the order “should be flexible enough to both react to whatever that final Climate Action Council scoping plan will be later this year, but also firm enough so that it continues to maintain the priorities of this commission, which as we all know has nothing to do with the Climate Action Council, with the exception of the chair holding dual role roles both here and on the council, so I think that that could be a delicate balance.”

The DPS is starting a process now with the utilities on decarbonizing the natural gas system and evaluating “what that means on a practical basis and also what the cost impacts and technical feasibility of actually achieving that look like,” Waldorf said. “So there is a reference to the draft scoping plan in the gas section of the draft order, but it was intentionally put in there to call attention to the fact that we’re not looking to conflict with any actions at the state level. We recognize them and to the extent that firm recommendations come out of that process, can get incorporated into future plans and we’ll incorporate that into ours as well.”

Commissioner Tracey A. Edwards said that while the CAC’s Climate Justice Working Group has three members from New York City, three from the rural communities, and three from urban communities in upstate New York, it does not include suburban communities and does not include anyone from Long Island.

“I’m particularly interested in what their responsibilities are and then taking a look at all of the different working groups, as the other one that piqued my interest was the Just Transition Working Group,” Edwards said.

Upstate Concerns

The CLCPA-tracking order locks in the volumetric load-share ratio for paying for renewables and associated transmission projects, which is neither fair nor adequate as policy, said Commissioner John B. Howard.

David Valesky (NYDPS) Content.jpgNYPSC Commissioner David Valesky | NYDPS

“I understand it’s an easy accounting mechanism, but I don’t think it really gets to the point,” Howard said, proposing instead that DPS staff do “an actual accounting of what things cost people” and what these new costs will mean to the broader economic competitiveness in each region of the diverse state.

Howard reiterated his oft-expressed concern that residents upstate, where more than 90% of the grid is zero-emissions, are being asked to pay a disproportionate share of the cost of greening the fossil fuel-fired generation fleet downstate. (See Stakeholders Question CLCPA Pace and Costs for New York.)

“Our entire state’s economy is shaky in its foundations, but I believe the upstate economy is shakier,” Howard said. “The legislature, either through its silence or total lack of action, has given this commission nearly the exclusive responsibility to reach into New Yorkers’ pockets to pay for the CLCPA mandates.”

John B Howard (NYDPS) Content.jpgNYPSC Commissioner John B. Howard | NYDPS

The PSC needs clarity “to cut through this fog … created by a totally unworkable program from the 22-member Climate Action Council and the subsequent subcommittees. It is almost a Rube Goldberg way to make public policy,” Howard said.

Howard supported the tracking order but joined Burman in voting “no” on a consent agenda item to implement transmission planning pursuant to the Accelerated Renewable Energy Growth and Community Benefit Act (20-E-0197); and in voting against a pair of consent agenda items related to the public policy transmission planning needs of NYISO for 2018 and 2020 (18-E-0623; 20-E-0497).

“If the legislature does not want to pay for [CLCPA], I hope my colleagues on this commission understand that responsibility falls to us exclusively to the tune of hundreds of billions of dollars and it is an awesome responsibility that we got through statute and by default,” Howard said.

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Maine Supreme Court Hears Entangling Arguments in NECEC Appeals

The Maine Supreme Court heard oral arguments Tuesday in two uniquely entwined appeals related to the New England Clean Energy Connect (NECEC) transmission project.

A court determination on the retroactive application of a Maine voter referendum on transmission development passed in November could affect the outcome of an appeal of a lower court decision to vacate a 1-mile lease of public land for the project. The validity of that lease could, in turn, determine the outcome of the constitutionality of applying the law established by the referendum to the NECEC project.

Maine law prohibits public land — including state parks or land set aside for conservation — from being “reduced” or its uses “substantially altered” unless the Legislature approves the changes with a two-thirds majority vote. A group of state legislators, the Natural Resources Council of Maine and a group of residents challenged the Maine Bureau of Parks and Lands’ (BPL) grant of a public land lease to NECEC’s developer, Avangrid (NYSE:AGR) subsidiary Central Maine Power (CMP), because it did not seek the Legislature’s approval.

The Superior Court agreed, vacating the lease. The court also found that the agency did not provide notice to the Legislature or the public of the lease contracts.

Meanwhile, voters in November approved a referendum that would categorize any transmission construction after September 2014 as a substantial alteration under the law, thus requiring the Legislature’s approval.

CMP and its development partner, NECEC Transmission — as well as BPL — appealed the Superior Court’s decision. Arguing on behalf of BPL Director Andy Cutko on Tuesday, Maine Assistant Attorney General Lauren Parker said that the statute on park lands does not apply to BPL’s leasing authority over lands it manages for “specified beneficial purposes, including electric power transmission.”

At the time BPL executed the lease with CMP, she said, Cutko had the authority to issue 25-year leases for transmission, contrary to the lower court’s ruling.

CMP attorney Nolan Reichl, a partner in Pierce Atwood’s Litigation Practice Group, argued separately that the statute on park lands calls a BPL determination on land use into question.

“If there is no substantially altered use of the land, there is no two-thirds vote requirement,” he said. The BPL, he added, has no obligation to make any case-by-case determinations on usage.

The legislature, he said, has “never required BPL to run any particular administration process in that respect,” with thousands of executed leases all “consistently reported” to the legislature.

It’s not clear that BPL made a use determination, Chief Justice Valerie Stanfill said, adding that the court could, therefore, remand the case to BPL to do so.

Referendum Appeal

The developers had also challenged the constitutionality of the voter referendum because of its retroactivity and that it deprived them of their “vested right” to build the project. The Superior Court disagreed, upholding the change to the law.

James Kilbreth, an attorney at Drummond Woodsum representing the group that challenged the lease, on Tuesday argued before the Supreme Court that the referendum invalidates the lease and therefore makes all questions in the appeal of its vacatur irrelevant. The appeal of the referendum, which relies on the validity of the lease, would therefore also be irrelevant, he said.

The referendum “moots all the questions” in the lease appeal, he said. State law, he added, also clearly establishes that when laws change during an appeal, as is the case with the referendum, the court must apply the new law in that case.

Kilbreth argued that the lease appeal must be decided before the referendum appeal. To bring the referendum appeal, he said, the developers need a valid lease because they claim that the lease is the basis for their vested right.

John Aromando, a partner at Pierce Atwood and attorney for NECEC Transmission and Avangrid, said that the existence of the lease appeal does not invalidate the lease in and of itself. A valid lease, he argued, ensures that the referendum cannot take away their vested right.

With the validity of the lease under appeal, the outcomes of both cases are uniquely connected.

In defending the referendum, the state argued that the concept of a vested right is not straightforward.

The vested right “as Avangrid conceives it, does not allow for any consideration of the governmental interests at stake in legislation,” Maine Assistant Attorney General Jonathan Bolton said.

In the developers’ view, Bolton said, government and public interests are “irrelevant” if construction of a project has started. “The modern view is that due process by its very nature requires consideration of both private rights and public or government interest,” he said.

NECEC agreed last fall to discontinue construction activity for the project pending outcome of the appeals.

“Delaying the construction of the project by 12 months will make it impossible for the company to complete the project by the contracted deadline in mid-2024,” Thorn Dickenson, president and CEO of NECEC Transmission, said in a September affidavit to the Supreme Court. The delay, he added, could cost as much as $83 million.

In closing the hearing, Chief Justice Stanfill said there is a “great deal” of interest in the referendum appeal and, by extension, the lease appeal.

“I don’t think this courtroom has been this full since I’ve been here,” she said, adding that the court will try to issue a written decision as soon as possible.

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North Carolina OSW Auction Nets $315 Million

Duke Energy (NYSE:DUK) and France’s TotalEnergies (NYSE:TTE) agreed Wednesday to pay a combined $315 million to lease 110,000 acres off North Carolina that could produce 1.3 GW in offshore wind.

After 18 rounds of bidding, TotalEnergies Renewables USA agreed to pay $160 million for Lease OCS-A 0545 and Duke Energy Renewables Wind will pay $155 million for Lease OCS-A 054, the Bureau of Ocean Energy Management (BOEM) reported.

The winning bids in the Carolina Long Bay auction averaged almost $2,900 per acre, more than double the prices paid in BOEM’s 2018 auction for three sites off the Massachusetts coast, but a fraction of the record $8,837/acre paid for sites in the New York Bight in February. (See Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)

Lower prices were expected, because unlike many other East Coast states, North Carolina has no statutory offshore wind goal, although Gov. Roy Cooper issued an executive order in 2021 calling for 2.8 GW of offshore wind capacity by 2030 and 8 GW by 2040.

North Carolina House Bill 951, enacted in October, requires the state Utilities Commission to cut the state’s electric sector carbon emissions to 70% below 2005 levels by 2030, with carbon neutrality by 2050.

Duke Energy, the state’s largest utility, has proposed 2,650 MW of OSW by 2035 in two scenarios in its 2020 integrated resource plan.

ClearView Energy Partners said H.B. 951 was “a primary motivator” for bidders in the auction. “The law did not create offshore wind-specific targets, but it does require each electric public utility to submit a ‘Carbon Plan’ describing how it intends to achieve the targets” to the NCUC by May 16, ClearView said. “The law also compels electric utilities to propose a program for the competitive procurement of energy and capacity from renewable energy facilities, inclusive of offshore wind.

“We regard state-led offshore wind solicitations as the most important policy driving offshore wind in the U.S. today. However, today’s winning bids exceed that of all other offshore wind lease auctions held prior to the New York Bight sale,” ClearView added. “This could suggest that an emerging domestic offshore wind supply chain and demonstrable under development and in-service projects over the last few years may sufficiently validate the viability of some offshore wind in waters that do not directly serve active state solicitations.”

Bidding

BOEM removed hundreds of thousands of acres from consideration since its 2012 North Carolina call for information and nominations to avoid conflict with the habitat of the North Atlantic Right Whale. It also eliminated areas within 20 statute miles of the shoreline and areas that would have overlapped with a navigational fairway proposed by the U.S. Coast Guard.

Following the removals, BOEM said it divided the remaining lease area into two nearly equal lease areas with similar acreage, distance to shore and wind resource potential.

Bidding for the two 55,000-acre leases increased in virtual lockstep for the first 11 rounds, beginning at the minimum bid threshold of $2.75 million with a total of nine bidders. By round 11, prices had risen to $100 million each while the number of bidders dropped to three. Sixteen companies had qualified to bid.

Heather Zichal, CEO of the American Clean Power Association, said the lease sale should “be a sign to Congress to repeal the 10-year moratorium on offshore wind leasing off the coasts of North Carolina, South Carolina, Georgia, and Florida. Creating a stable policy platform for offshore wind development and facilitating the first wave of significant projects will provide certainty for the industry, strengthen the workforce, and bolster domestic supply chains up and down the coasts and across the country.”

Stipulations

BOEM included stipulations to encourage “construction efficiency” and development of a domestic supply chain. Lessees will be required to make reasonable efforts to enter a project labor agreement covering construction. (See Ørsted Inks Labor Agreement for US OSW Construction.)

“For the first time, the federal government used an auction system designed to spark investment directly into U.S. manufacturers, small businesses, shipbuilders and new workforce training, accelerating development of the already-emerging domestic supply chain,” said Liz Burdock, CEO of the Business Network for Offshore Wind.

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Draft Plan Seeks Calif. Carbon Neutrality by 2045

The California Air Resources Board has released a draft plan for the state to reach carbon neutrality by 2045, tentatively rejecting alternatives that would achieve the net-zero goal 10 years sooner.

CARB released the draft climate change scoping plan on Tuesday and has scheduled a public hearing on the plan on June 23. Written comments are due by June 24.

The agency expects to adopt a final scoping plan by the end of the year.

The scoping plan is a roadmap for the state to meet greenhouse gas reduction goals. State law requires a scoping plan update every five years; the last update was in 2017.

In its process for developing the scoping plan, CARB analyzed four different scenarios. Alternatives 1 and 2 would bring the state to carbon neutrality by 2035, while Alternatives 3 and 4 would reach the target in 2045.

The alternatives differ in other key areas, including the rate of consumer adoption of clean technologies; reliance on carbon capture and sequestration (CCS) and CO2 removal; and the remaining demand for fossil energy after carbon neutrality is reached.

Choosing an Alternative

The draft scoping plan proposes moving forward with Alternative 3.

“It is the proposed alternative because it best achieves the balance of cost-effectiveness, health benefits and technological feasibility,” the draft plan states.

With its extra 10 years to achieve carbon neutrality compared to Alternatives 1 and 2, the proposed alternative provides more time for technologies to scale up and be deployed at lower costs, according to CARB.

The proposed alternative would reduce petroleum usage by about 90% by 2045 and achieve a state target of reducing GHG emissions 80% by 2050.

In comparison to Alternative 4, the other scenario with carbon neutrality in 2045, the proposed alternative includes a faster adoption rate of clean technologies and less reliance on CO2 removal.

The most aggressive of the scenarios is Alternative 1, which would nearly eliminate fossil fuel combustion by 2035. The alternative would require early retirement of millions of gasoline- and diesel-powered vehicles as well as natural gas appliances.

Alternative 1 has a limited reliance on CCS. It would include direct regulation of dairies to reduce methane emissions.

The scenario has the highest direct costs of the four options and would cause the most slowing of economic growth, according to CARB’s analysis.

Alternative 3 would have the least impact on employment and economic growth among the four options, the draft plan said.

CARB’s board has the option to choose another scenario. The board could also keep the proposed alternative but incorporate elements from other scenarios.

Sector Specific Strategies

CARB said the most significant part of the draft plan is the aggressive reduction in the state’s fossil fuel reliance. That would be accomplished by building on existing strategies, including regulations, incentives and carbon pricing.

And the 2022 scoping plan differs from previous plans in its focus on “the accelerated rate of deployment of clean technology and energy within every sector,” the agency said.

The draft scoping plan details carbon reduction strategies in several key sectors.

In the transportation sector, the plan includes a transition to zero-emission vehicles while ensuring there’s enough zero-carbon alternative fuel for the vehicles. To achieve the latter, the plan proposes incentivizing private investment in new zero-carbon fuel production in the state and looking at options to increase the stringency of the low-carbon fuel standard.

The draft scoping plan also envisions a 22% reduction in vehicle miles traveled by 2045 compared with 2019 levels.

In the electricity sector, decarbonization strategies include addressing challenges to resource buildout, such as permitting, interconnection and transmission network upgrades.

The draft plan proposes exploring rate designs to increase affordability and continuing to look at the benefits of regional markets.

Another strategy proposed for the electricity sector is use of incentives and other programs to improve disadvantaged communities’ access to renewable energy projects, such as rooftop and community solar, battery storage and microgrids.

In addition, the plan proposes to evaluate the cap-and-trade program, with changes to strengthen the program if needed.

Adoption of the 2022 scoping plan is just “the beginning of the next phase of climate action,” according to CARB.

Approval of the plan will lead to the development of new regulations or strengthening of existing programs and regulations, the agency said. The changes will take place at CARB and at other state agencies.

“The unprecedented rate of transition will also require identification and removal of market and implementation barriers to the production and deployment of clean technology and energy,” the draft plan said.

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SEEM Members Launch Engagement Series for Participants

Southeast Energy Exchange Market (SEEM) members began an informational series Wednesday to educate existing and prospective participants on how the market will function and what to expect before it goes live.

With a planned launch in the fourth quarter, SEEM’s founding utility members worked this spring to design the optimization platform that will drive the market, according to Chris McGeeney, manager of transmission services at Associated Electric Cooperative, a SEEM member.

“In late May, we’re going to start kicking the tires on the system and onboarding participants, and training will continue through the end of June,” McGeeney said during the first of three introductory webinars.

Participants will begin submitting their company information into the SEEM platform prior to the start of market trials scheduled for late summer, he said.

The region-wide, automated intra-hour platform will function as SEEM’s optimization engine based on inputs from market participants, such as bids and transmission capacity, to create bilateral matches between participants, according to McGeeney. An algorithm will process market participants’ inputs every 15 minutes for bids and offers, consider participants’ constraints, such as trading restrictions, and identify matches between the bids and offers.

Automated transactions, he said, will go to relevant transmission service providers, balancing authorities and generators for approval, and the SEEM platform will create transaction records between participants. At that point, energy flows will occur in the same way they do in the bilateral market.

“There’s no single clearing price or concept of financial congestion,” McGeeney said. “What’s going to turn the crank is this optimization engine looking for the optimal set of trades that benefits the entire region.”

Participation

Entities that want to voluntarily buy and sell within SEEM and are not formal market members must have control of a valid energy source or sink within the market’s footprint, according to Molly Suda, associate general counsel at Duke Energy (NYSE:DUK).

If that basic criterion is met, participants can sign up by executing the SEEM participation agreement, which is on file with FERC for review, she said.

Prospective participants also must have transmission service arrangements in place for the new non-firm energy exchange transmission service (NFEETS) product that all the transmission-owning members of SEEM will be offering.

Duke, Southern Company (NYSE:SO), LG&E and KU Energy, and Dominion Energy South Carolina (NYSE:D) have all filed with FERC and have, as part of their open access transmission tariffs, a form transmission service agreement for the NFEETS product that participants can execute, Suda said.

In addition, participants must have at least three enabling agreements with other non-affiliated participants. The enabling agreements function as an underlying bilateral contract that will allow participants to settle trades matched by the SEEM platform.

“That three-counterparty rule was put in place and contained in the market rules to establish a mechanism to prevent opportunities for parties to collude to gain preferential access to this new transmission service,” Suda said.

Operations

Matt O’Neal, project manager for energy policy at Southern, outlined some functional capabilities of the SEEM system during the webinar that attendees can discuss with their IT teams in advance of onboarding.

The SEEM platform will have several different authentication options for participant login, he said. And participants need to be thinking ahead to how they will access the platform. They can use the SEEM platform via a web user interface or APIs that connect to a company’s back-end systems.

“Many of our existing participants are building up internal systems that will formulate bids and offers, submit bids and offers or pull results back down to store in their energy trading risk management systems,” O’Neal said. “Many of the large vendors out there are offering SEEM add-ons or features to their products to interact with the SEEM.”

The onboarding process will also require participants to provide important details to help with the SEEM functionality, according to O’Neal. Those details include source and sink locations, tagging requirements and geographic constraints.

Consideration early in the onboarding process should go to how participants will formulate their bids and the volume of bids, O’Neal said, adding that with a fast-moving, 15-minute market, system automation could be “worthwhile.”

“If you do the math and think about a 15-minute market, that means you have … close to 35,000 trading intervals within a single year,” he said. “There is a lot of potential for deals; maybe more deals than you traditionally have today.”

Upcoming webinars in the series will take place May 20 and June 20 to give participants an overview of the SEEM network infrastructure and a closer look at tagging process and settlement.

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Colorado Law Requires Cities to Adopt Green Building Codes

In an effort to decarbonize the state’s building sector, Colorado lawmakers passed a bill Wednesday that will require local governments to update their building codes to maximize energy efficiency in new construction.

The Building Greenhouse Gas Emissions Bill (HB22-1362) aims to reduce carbon emissions from new commercial buildings and homes through changes to municipal codes. By July 1, 2023, local governments will have to adopt building energy codes that meet or exceed the energy performance of the 2021 International Energy Conservation Code. It will also require that updated codes include language for solar-ready, energy-efficient and low-carbon buildings.

The legislation will establish a new Energy Code Advisory Board that will model the language required in updated energy codes, acting as a resource for municipalities. The co-chairs for the 21-member board will be representatives from the Colorado Energy Office and Department of Local Affairs, according to a press release from the Southwest Energy Efficiency Project.

“HB22-1362 will facilitate adoption of rooftop solar systems, high efficiency heat pumps, and electric vehicles in homes and commercial buildings that do not include these features from the start,” Meera Fickling, senior climate policy analyst with Western Resource Advocates, said in a statement. “This will extend the climate benefits of the bill beyond those provided by the energy efficiency improvements in new construction.”

In addition to the new code requirements, the bill funds grants for nonprofits and government buildings to upgrade to high-efficiency electric heating equipment and appliances. The bill also establishes the Clean Air Building Investments Fund, which will transfer $21 million from the general fund to finance the grant programs.

“The energy code requirements as well as the grants programs will expand the market for high efficiency heating and cooling equipment, insulation/air sealing, building control systems and other energy efficiency measures,” Patricia Rothwell, executive director of the Energy Efficiency Business Coalition of Colorado, said in a press release.

HB22-1362 is currently awaiting Gov. Jared Polis’ signature, with the legislature confident that he’ll sign the bill into law.