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November 20, 2024

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EPA Rules Will Slash Vehicle Emissions, Rev up EV Market by 2026

U.S. Environmental Protection Agency Administrator Michael Regan on Monday rolled out stringent new vehicle emissions standards, stating confidently that getting the U.S. light-duty fleet to an average of 40 miles per gallon by 2026 would be achievable even without the electric vehicle tax incentives in the now-imperiled Build Back Better bill.

“When we look at the technical analysis we’ve done, the conversations with the automakers, what we’re proposing today we believe is historic and we believe is capable” of being achieved, Regan said in response to reporters’ questions at a signing ceremony for the new rules. “That’s not to say that we’re not going to continue to fight tirelessly for those incentives that are in the Build Back Better proposal. But nevertheless, we believe that we proposed a rule that is doable. It’s affordable. It’s achievable.”

Prospects for passing the $2 trillion budget reconciliation package screeched to a halt on Sunday when Sen. Joe Manchin (D-W. Va.), the critical swing vote in the evenly divided Senate, said he could not support the bill in its current form. (See Manchin Says ‘No’ on Build Back Better.)

The new rules replace the Safer Affordable Fuel Efficient (SAFE) rules put in place by the Trump administration in 2020. Under those rules, automakers would only have had to reduce tailpipe greenhouse gas emissions 1.5% a year and achieve a fleet-wide fuel efficiency of 32 mpg by 2026, according to an EPA fact sheet. The new rules call for emissions cuts of 10% over the SAFE standard in 2023, and then cuts of 5%, 7% and 10% in 2024, 2025 and 2026, respectively.

Transportation electrification will be essential for reaching those goals, with the EPA projecting that hybrids will account for 12% of U.S. light-duty vehicles by 2026, and EVs, 17%, according to the fact sheet.

“In model year 2026, these standards will be the most ambitious standards in United States’ history,” Regan said. “We estimate that through the year 2050, this program will save American drivers up to $420 billion on fuel costs, gas that you won’t have to put in the tank, and avoid more than 3 billion tons of greenhouse gas pollution.”

Gas savings would also offset the higher cost of electric or more efficient vehicles by about $1,080 over the lifetime of a 2026 model year vehicle, the EPA estimated.

But other speakers at the signing ceremony focused primarily on the impact the new rules would have on public health, especially for children at risk for asthma or other respiratory disease caused by air pollution from cars.

Nsedu Obot Witherspoon, executive director of the Children’s Environmental Health Network, spoke of her own experience, riding in an ambulance with her youngest child, who suffers from asthma. “When you see your child struggling to breathe, take their next breath, we all become helpless, unable to provide them the security that they deserve,” Witherspoon said.

“Asthma is still the No. 1 chronic illness among children,” she said. “If you cannot be healthy enough to be in school to learn, that creates another ripple effect related to a child’s educational journey, their ability to focus and remain engaged. Childhood asthma is also a key environmental justice issue and has been as African-American and Latinx children witnessed higher incidence rates of asthma.”

EV Stocks Tumble

The final rule Regan signed today is even more stringent than the proposed rule the EPA released in August, which called for a 2026 target for fleet efficiency of 38 mpg. But new standards also provide flexibility for automakers “to help them meet standards in ways that are most appropriate and cost effective for individual companies,” according to the fact sheet.

CO2 compliance targets (EPA) Content.jpgEPA final fleetwide CO2 compliance targets, compared to the rules proposed in August and 2020 and 2021 rules. | EPA

For example, companies can carry over credits they may have accrued for “overcompliance” in 2017 and 2018 and apply them to meeting the 2023 and 2024 standards. Automakers can also receive extra “vehicle multiplier credits” for accelerating their rollout of zero- and near-zero emission vehicles, which could benefit the U.S. automakers, such as GM, that have already committed to a full transition to EVs.

At the same time, the rule sees a major role for vehicles with advanced, high-efficiency engine technology, predicting they will comprise more than half of the 2026 light-duty fleet.

But hitting the rules’ ambitious goals will require “a substantial increase in electric vehicle sales, well above the four percent of all light-duty sales today,” according to a statement from John Bozzella, CEO of the Alliance for Automotive Innovation, an industry group representing most U.S. automakers. “Achieving the goals of this final rule will undoubtedly require enactment of supportive governmental policies, including consumer incentives, substantial infrastructure growth, fleet requirements, and support for U.S. manufacturing and supply chain development.”

Significantly, EV stocks took a 7% tumble on Monday, according to CNBC, as the market reacted to Manchin’s abandonment of the bill.

Industry analysts ClearView Energy Partners are predicting that to get Manchin’s vote, a slimmed down Build Back Better might have to sacrifice some clean energy incentives. Manchin has previously spoken against one of the bill’s provisions: an additional $4,500 tax credit for union-built EVs.

Pedal to the Metal

Reactions from Democratic lawmakers and a key union leader supported the stricter standards. In an online statement, Sen. Edward Markey (D-Mass.) said he had urged the EPA to go beyond the August proposal and called for the agency to “put the pedal to the metal” to go even further in the next cycle of vehicle emissions standards.

Rep. Frank Pallone (D-N.J.), chair of the House Energy and Commerce Committee, similarly praised the stricter rules, but his email statement carefully skirted the status of Build Back Better.

“Paired with the investments in the bipartisan infrastructure law, this action will accelerate the process of transforming our transportation sector to the benefit of public health and the environment,” he said.

Ray Curry, president of the United Automobile, Aerospace and Agricultural Implement Workers (UAW), called the new rules a “win-win” for union members and other workers. “Well thought-out regulations, such as the Biden Administration’s emission rules today, will promote long-term U.S. investments while they protect and expand good-paying union jobs in vehicle production and advanced technologies that will allow manufacturers the flexibility necessary to meet these standards,” he said.

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NH EE Plan Approaches 2nd Year without Funding Certainty

New Hampshire is about to enter the second year of its 2021-23 Triennial Energy Efficiency Plan without a firm budget in place, and EE industry members are concerned about the consequences for their businesses.

In a Nov. 12 order, the PUC threw out a proposed triennial plan and a settlement agreement that would have more than doubled spending, saying it placed “an enormous burden on New Hampshire ratepayers.” The PUC instead directed the state’s utilities, which developed the plan and administer the efficiency programs, to submit a new EE budget with spending “similar to the 2018-20 plan.” It also ordered system benefit charges funding the programs to decline by almost half by 2023 (DE 20-092).

The proposed triennial plan is the second installment under the state’s Energy Efficiency Resource Standard established in 2016.

Response to Order

New Hampshire stakeholders’ responses to the PUC order came in rapid succession in December.

On Dec. 7, the nonprofit Clean Energy NH (CENH) led a group of EE industry members in filing an emergency motion in New Hampshire Superior Court for a temporary injunction staying the order, calling the PUC’s ruling “arbitrary and capricious.”

The effect of the PUC’s order “defunding” the 2021-23 budget will “deprive all Granite Staters of the decreased electric and gas rates and decreased emissions of airborne pollutants that come from using energy efficiently,” the petitioners said.

CENH filed a companion complaint to its Dec. 7 emergency motion asking the Superior Court for immediate emergency relief to prevent layoffs in the efficiency sector and harms that “will imminently worsen prior to the holidays.”

State utilities have already suspended energy efficiency work orders, said a Dec. 6 affidavit of William Newell, owner of weatherization firm Newell and Crathern. If the PUC’s order stands, he said, the company will have to lay off most of its employees by the end of the year. Other businesses that work with the state utilities to provide program services said in affidavits that they have contracts for the New Year that are under threat if the PUC does not stay its order. A court date for the complaint is set for Dec. 27.

Eversource Energy (NYSE:ES), other state utilities and advocates and the New Hampshire Department of Energy (DOE) filed motions Dec. 10 for rehearing or clarification.

In orders on Dec. 6 and Dec. 13, the PUC provided some clarity on petitioners’ immediate questions about the order and stayed a Dec. 15 filing deadline, but it has yet to rule on the request for rehearing. The PUC has until Jan. 10 to respond to the rehearing requests.

New Budget

Under the settlement filed in December 2020, the utilities’ total 2021-23 budget request was $378.4 million, a $202.4 million increase over the 2018-20 budget of $176.2 million.

Proponents of the plan said the increase was justified because it would reduce energy costs and provide customer net savings.

Adopting the plan “will result in a net reduction of system costs for delivering energy services of more than $600 million,” said David Hill, managing consultant at Energy Futures Group, in October 2020 testimony on behalf of CENH. The bill savings for customers, he said, would be $1.3 billion over the three-year plan.

In the original plan, a bill impact analysis showed that the proposed three-year budget would reduce the utilities’ long-term revenue requirements by $470 million.

The PUC, however, said the budget goes against the commission’s preference for market-based mechanisms and proposed “ratepayer-funded energy efficiency that is entirely utility sponsored.” In addition, the commission determined that the utilities did not prove that the new budget is just, reasonable and in the public interest.

The commission ordered the EE programs funded for 2021-23 “at a level consistent with the previous triennial plan.”

The commission noted the energy efficiency portion of the system benefits charge (SBC) rose from 0.198 cents/kWh in 2017 to 0.528 cents/kWh in 2020, a 167% increase. The proposed settlement would have increased the charge to 1.259 cents/kWh for commercial and industrial customers and .863 cents/kWh for residential customers by 2023.

Instead, the commission limited the EE portion of the SBC rate for all rate classes to 0.528 cents/kWh in 2021, the same as 2020, declining to 0.373 cents/kWh in 2022 and 0.275 cents/kWh in 2023.

“While the overall level of the 2021–23 plan will be similar to the 2018–20 plan, consistent with the commission’s longstanding preference for gradualism in ratemaking, the rates set by the commission … will descend gradually year-on-year until they return to a reasonable level, and transition toward market-based programs,” the commission said.

It directed the utilities to identify EE programs “that provide the greatest benefit per unit cost with the lowest overhead and administrative costs within the approved budget and file a program proposal” for the commission’s review.

In compliance with the order, the utilities on Dec. 15 and Dec. 16 filed a new budget for the three years of $183.9 million. The new budget starts at $81.9 million for 2021 and declines to $44.9 million by 2023. But they said they “maintain all arguments and positions made in the joint motion for rehearing, clarification and stay” of the order.

State of the PUC

The PUC responded to the settlement proposal at the end of December 2020 with an order that maintained the existing budget until the commission reached a final decision. That final decision was expected by February 2021 but didn’t come until Nov. 12, nearly a year overdue for the January 2021 effective date of the 2021-23 plan.

Now, stakeholders are concerned that the commission’s final order on the plan only further delays implementation, hindering the utilities’ ability to continue funding programs and projects already in process.

CENH said that emergency relief is necessary because the PUC is “incapacitated,” and motions filed in the docket, therefore, might not reach a resolution until 2023.

Of primary concern to the petitioners is the commission’s ongoing flux since it became part of the newly formed Department of Energy in July. Newly appointed commissioners, CENH said, do not have the “institutional knowledge” necessary to rehear the case or have a conflict of interest.

The commission’s order was signed by then-Chair Dianne Martin, who resigned on the day of the order to take a job in the state court system and Commissioner Daniel C. Goldner, now the chair, whose term expires in 2025.

Carlton Simpson, a former attorney for utility Unitil was confirmed by the New Hampshire Executive Council on Nov. 10 to complete Martin’s term. Commissioner Pradip Chattopadhyay was appointed in December to a full six-year term expiring in 2027.

The state’s consumer advocate told the PUC in September that Chattopadhyay should not participate in triennial plan proceedings due to his prior work in the advocate’s office at the docket’s start in 2020. Chattopadhyay, who received approval for his seat earlier this month, filed a memorandum in the docket on Tuesday saying he would not recuse himself from the case. He worked as a senior advisor for the commission from August to December.

His work at the advocate’s office, he said, did not include access to information related to the plan that would be inappropriate to know as a commissioner. The Consumer Advocate, however, filed a motion on Friday seeking Chattopadhyay’s disqualification from participation in the docket, saying his position was high ranking in the advocate’s office and as such, he would have been privy to docket details in both formal meetings and informal conversations.

Governor’s Input

In a Dec. 14 letter to DOE Commissioner Jared Chicoine, Gov. Chris Sununu applauded the DOE for seeking a rehearing, but he also agreed with the PUC’s assessment of the settlement agreement.

“Had the proposed settlement agreement in this docket been approved, New Hampshire’s ratepayers would have seen significant increases to the system benefits charge — increases as high as 168% for some commercial and industrial customers over the 2020 rates,” he wrote.

The order, he said, also presented operational complications for the state’s energy efficiency programs, saying there are “legitimate questions” about the effect of the order for state programs in the “very near future.”

Sununu urged the PUC to address stakeholders’ concerns about the order.

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CAISO Reevaluating WEIM Resource Sufficiency Test

The Western Energy Imbalance Market Governing Body met twice last week, once by itself and once in a joint session with the CAISO Board of Governors, receiving briefings in both meetings on potential changes to the interstate market’s resource sufficiency test, which is being re-examined in a stakeholder initiative.

The test is meant to ensure that each WEIM participant enters a trading hour with enough capacity and ramping capability to supply its own needs and to prevent participants from “leaning” on the market to meet internal demand.

Participants raised objections to the test, including the recent addition of components that account for the unpredictability of weather-dependent resources such as solar and wind generation, transmission outages and other variables. Some contended the “uncertainty” components skewed results and led to periodic test failures, including by CAISO during intervals last summer.

A revised final draft proposal in the resource sufficiency evaluation (RSE) enhancements stakeholder initiative was released Thursday, when the board and governing body met in joint session. CAISO Vice President of Market Policy and Performance Anna McKenna provided a briefing on the proposed changes, as she had done in the governing body’s regular meeting Wednesday.

Stakeholders had four areas of concern over test accuracy, McKenna said.

“The first category is with regards to the measurement of uncertainty used in the capacity test,” she said. “After hearing more concerns about the current measurements that we use to capture uncertainty and the adders that we’ve put into the test, we are now considering suspending … uncertainty in the tests.”

Participants also raised concerns around demand response resources, capacity counting rules and consideration of load conformance.

CAISO planners had proposed increasing penalties for including demand response resources in the sufficiency test that do not materialize, but they now recommend shelving that plan because the penalties could have a “detrimental impact on how (participants) use demand response,” McKenna said.

A third category of stakeholder concerns involved CAISO’s proposed rules for counting resources toward the sufficiency test. CAISO still intends to enhance the counting criteria “so that the resources that are used to count to meet the test … can better reflect their actual reliability,” McKenna said.

The fourth category of concerns involves “how conformance of load forecast, which is done by our operators, can trigger EIM transfers to meet the [resource sufficiency] test,” McKenna said. CAISO continues to believe that understanding and adjusting for the impact of load forecast is important, but additional analyses showed complexities that deserve further testing and evaluation, she said.

“So, we’re proposing to take that additional time with regard to this one item,” McKenna said.

CAISO already had extended its timeline for the RSE initiative to take stakeholder comments into consideration and now plans to submit a final proposal to the board and governing body in a joint meeting Feb. 9.

Thursday’s joint meeting was the first to be held under new governance rules adopted by the CAISO and WEIM in August. The vote on the sufficiency test will among the first joint decisions under the new rules.  (See CAISO Agrees to Share More Power with EIM.)

A meeting on the latest draft RSE draft proposal is scheduled for Dec. 21, with stakeholder comments due Jan. 10.

The WEIM now has 15 participants with seven more scheduled to join in the next two years, eventually accounting for more than 80% of load in the Western interconnection. Participants have amassed more than $1.7 billion in benefits since the market started in 2014 by buying and selling excess power across state lines.

CAISO is undertaking a major effort this to year to expand the real-time market to a day-ahead market (EDAM), further increasing cooperation among the West’s 37 balancing authorities.

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Jones Working to Restore Confidence in ERCOT

Brad Jones 2021-12-17 (RTO Insider LLC) FI.jpgInterim ERCOT CEO Brad Jones | © RTO Insider LLC

DALLAS — Brad Jones, ERCOT’s interim CEO, opened his conversation Friday with the Dallas Friday Club as he always does on what he calls his Listening Tour: stepping away from the podium and eschewing the use of a mic. The better to wander the stage and connect with his audience.

“This will take about two and a half hours,” Jones said, drawing a few laughs.

His story began on Feb. 15 during a winter storm, “one you’ve never seen and one your grandparents never saw.” Jones, retired from the electric industry at the time, says he was on his couch and watching television coverage of the winter storm disaster that left millions without power and caused human and financial suffering.

“Things have changed for me, haven’t they?” Jones said in a quick aside.

“Were you in Texas?” asked a voice from the back of the room.

“Yes.”

“Did you have power?”

“Electricity, but no water.”

It’s that mixture of charm, humor and candor that serves Jones well as he explains to Texans what happened to the grid during the storm and why it won’t happen again. Several members of the public affairs organization exchanged smirks as Jones began his comments. An hour later, most everyone in the room was listening in rapt attention.

Jones admitted to ERCOT’s poor communication during the storm, when “each piece of the market was telling different stories.” He said the subfreezing temperatures shut down almost 50 GW of the grid operator’s capacity — more than the 48-GW demand peaks CAISO sees on its hottest days, he said — and left the grid within about 10 minutes or so of a black start situation when generators automatically shut down.

“Things would have been much more difficult to manage,” Jones said.

He explained the lack of interconnections with neighboring RTOs wouldn’t have helped much, as they were experiencing the same emergency conditions. That led into an explanation of why ERCOT, “an island to itself,” is exempt from FERC jurisdiction.

When Jones began taking questions from the audience, he was asked how Texas can again say it has the best grid in the nation. He said his flippant answer is that New York has had three blackouts and California two while the Lone Star State has not had one.

“The real answer is simple,” he said. “We have to show the country we’ve changed the way we operate.”

Jones mentioned the RACE acronym he uses to denote “reliable, affordable, clean electricity.” Until the February storm, he said, RACE had been turned into CARE.

“For 20 years, we let the market dictate what we need for reliability,” Jones said. “We need to move reliability back to the front. That will be how we change.”

Jones handled every following question with similar ease. When the luncheon concluded, he took time to visit with the diners that stayed behind before doing on-camera interviews with the local media.

Asked if he is the perfect spokesman for this role as the communicator in chief, Jones laughed loudly.

“It’s an extremely important role,” he said. “The reason I came back to ERCOT after the winter storm was so ERCOT can begin to restore confidence among Texans in what it does.”

Jones served as ERCOT’s COO before leaving to take the top job at NYISO. He has watched the industry from afar since abruptly leaving New York for personal reasons in 2018. (See Brad Jones out at NYISO.)

The Brad Jones Listening Tour continues. Dallas was the 13th stop, with four more on the schedule. That is expected to change, however. Jones has yet to come across a city council or town hall that he won’t attend.

Contrast that with Texas Gov. Greg Abbott, who has guaranteed the grid will not fail this winter. While Jones has been crisscrossing the state, Abbott held a closed-door meeting Thursday with “Texas energy providers” to discuss the grid’s reliability and “preparedness ahead of the winter season.”

The governor’s office said in a statement that Abbott and “energy leaders” discussed actions already taken and improvements made by both the providers and the state, including updated winter preparedness plans, meetings with plant managers and “winterization of all components of the power grid.”

The office also said several providers “discussed their efforts to ensure that natural gas supply is available this winter to fuel power plants, including on-site storage of natural gas and designation of natural gas facilities as critical to ensure they maintain power during energy emergencies.”

NRG Energy (NYSE:NRG), Vistra (NYSE:VST), Calpine and several pipeline companies were among those involved in the meeting.

434 MW Back for Late Winter

ERCOT will have an additional 434 MW of gas-fired capacity to play with before this winter is over, thanks to a pair of decisions related to retired power plants.

Vistra told the grid operator on Friday it is bringing its 69-MW Wharton County Generation facility out of retirement and making it operational as of Feb. 4. The plant, located southwest of Houston, was decommissioned and retired last December after a forced outage. (See “Luminant, 1 Other File NSOs with ERCOT,” Vistra to Shut down Another Texas Coal Plant.)

ERCOT and CenterPoint Energy, the interconnecting transmission service provider, may delay the proposed return date if any studies, testing, metering or facility upgrades are necessary.

NRG notified ERCOT on Dec. 14 that Gregory Power Partners — a three-unit, 365-MW facility near Corpus Christi currently under seasonal mothball status — will change the start date of the operating period from May 1 to Jan. 1.

The plant was shut down in late 2016 when its cogeneration partner, Sherwin Alumina, filed for bankruptcy and ceased operations. NRG returned it to seasonal operations in 2019. (See ERCOT Approves Seasonal Plan for NRG Cogen Units.)

The announcements will help make up for the loss of almost 500 MW of capacity following recent suspension-of-operations notifications filed by the cities of Austin and Garland for aging gas-fired generators. ERCOT approved the notices earlier this month. (See “500 MW to Depart Market,” ERCOT Briefs: Week of Nov. 1, 2021.)

The 405-MW Austin unit will be available through the winter before being retired.

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CAISO Board Elects New Leaders

In its last meeting of 2021 on Friday, the CAISO Board of Governors elected a new chair and vice chair and voted to fund new technology to settle billions of dollars in yearly market transactions.

The five board members continued their policy of rotating leaders annually, electing Vice Chair Ashutosh Bhagwat as chair and naming Governor Mary Leslie to take his place as vice chair.

Bhagwat, a law professor at the University of California, Davis, who has served on the board since 2011, took over the top spot from Angelina Galiteva, whom colleagues praised for her leadership in difficult times. The first woman to chair the CAISO board, her term included the pandemic, the state’s struggle to prevent summer blackouts and a changeover in CEOs.

“You are the perfect chair to have led this effort because I think you brought a really nice warmth and understanding and vision to being chair, and I think it’s served us really well,” Leslie told her.

Galiteva responded, “Well, thank you. It was a pleasure to be the first woman chair. It was about time we had a woman chair at the ISO, and now we’ll have many more. It’s wonderful to see that now women are the majority on the board, which is also a first, so it has been it has been a very good period.”

Bhagwat lauded Galiteva for her work as an ambassador between the CAISO board and the Western energy community and asked her to continue with those efforts.

Accepting his new role, Bhagwat said, “I appreciate the confidence you’re showing in me, and I hope to live up to it.”

Settlement Upgrades

CAISO management requested a $15.6 million upgrade to CAISO’s settlement system, which handles billions of dollars in transactions annually and will likely handle more in the coming years as CAISO expands its Western Energy Imbalance Market.

“Every week, the ISO settles between $60 [million] and $219 million dollars of market transactions, and in 2020 that totaled $11.4 billion dollars,” Vice President for System Operations Dede Subakti and CFO Ryan Seghesio said in a memo to the board. “In order to achieve this, the ISO settlement team must process between 18 and 51 trade dates each week, as mandated by our tariff. This results in roughly 31,000 system files being published to 585 market participants weekly.”

The current system is aging, they said.

“It [now] takes between three and seven hours of work to process each trade date, leaving very little room for error,” they wrote. “As a result, the ISO is sometimes challenged to meet the tariff-defined statement publishing deadlines.”

“As we look toward a future with more market participants, new customer types, new market products and an expanded ISO footprint, it is time to address the shortcomings in the current settlement system,” they said. “Failing to do so would be too risky to the ISO and our stakeholders.”

The board unanimously approved the request.

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Manchin Says ‘No’ on Build Back Better

Work on the Democrats’ $2 trillion Build Back Better Act came to a screeching halt Sunday morning as Sen. Joe Manchin (D-W.Va.) stated unequivocally that he could not vote for the bill in its current form.

“I have always said if I can’t go home and explain it to the people of West Virginia, I can’t vote for it,” Manchin said on “Fox News Sunday.” “And I cannot vote to continue with this piece of legislation. I just can’t. … This is a no.”

President Joe Biden “has worked diligently; he’s been wonderful to work with,” Manchin said of his negotiations with the White House. But he said the government should focus on inflation and the new surge in COVID-19 cases, driven by the fast-spreading Omicron variant.

White House Press Secretary Jen Psaki said the administration was blindsided, labeling Manchin’s statements “a sudden and inexplicable reversal in his position and a breach of his commitments to the president and the senator’s colleagues in the House and Senate.”

Manchin had repeatedly told Biden he was committed to working on the bill, Psaki said. “On Tuesday of this week, Sen. Manchin came to the White House and submitted — to the president, in person, directly — a written outline for a Build Back Better bill that was the same size and scope as the president’s framework and covered many of the same priorities. While that framework was missing key priorities, we believed it could lead to a compromise acceptable to all. Sen. Manchin promised to continue conversations in the days ahead and to work with us to reach that common ground.”

In his own statement, released following his appearance on Fox, Manchin said that the bill represented efforts by Democrats to “dramatically reshape our society in a way that leaves our country even more vulnerable to the threats we face.”

He also reiterated his longstanding argument that U.S. energy policy should be driven by innovation and markets, rather than regulation.

“If enacted, the bill will also risk the reliability of our electric grid and increase our dependence of foreign supply chains. The energy transition my colleagues seek is already well under way in the United States of America,” he said. “We have invested billions of dollars into clean energy technologies so we can continue to lead the world in reducing emissions through innovation. But to do so at a rate that is faster than technology or the markets allow will have catastrophic consequences for the American people like we have seen in both Texas and California in the last two years.”

‘This is not Over’

Clean energy advocates have lobbied hard for the bill, which contains $555 billion in funding for renewable energy tax credits and other programs aimed at achieving Biden’s goals of decarbonizing the U.S. electric grid by 2035 and cutting the nation’s carbon emissions to net zero by 2050. Supporters pledged to continue their efforts despite Manchin’s announcement.

Speaking on CNN’s “State of the Nation,” Sen. Bernie Sanders (I-Vt.) said Manchin is “going to have to tell the people in West Virginia why he’s rejecting what the scientists of the world are telling us, that we have to act boldly and transform our energy system to protect future generations from the devastation of climate change.”

Sanders also called for Democrats to “bring a strong bill to the Senate as soon as we can and let Mr. Manchin explain to the people of West Virginia why he doesn’t have the guts to stand up to powerful special interests.”

“This is not over,” said Gregory Wetstone, CEO of the American Council on Renewable Energy. “The clean energy tax platform and grid infrastructure provisions in the Build Back Better Act are our last, best chance to tackle climate change. We will be working with Congress to find a way forward and deliver the clean energy future Americans want and deserve. Failure is not an option.”

Erin Duncan, vice president of congressional affairs for the Solar Energy Industries Association, also signaled the organization’s determination to keep fighting for the bill.

“There have been many twists and turns in this legislation, but the need for jobs, particularly domestic manufacturing jobs, that help address the climate crisis is unrelenting,” she said. “This is not the end of the road. We will continue to advocate aggressively for policies that deliver jobs and clean energy to every state across America.”

The debate also exploded on Twitter, where Robert Reich, who served as secretary of Labor for former President Bill Clinton, said Congress’s adjournment at 4 a.m. Saturday ended any hope for passing Build Back Better this year. “Biden’s agenda is now at the mercy of the midterm election year,” Reich said.

Calling Manchin “the new Mitch McConnell,” Rep. Jamaal Bowman (D-N.Y.) questioned whether Manchin’s opposition to the bill was influenced by special interests. “When you say you’re a no on Build Back Better — is it you? Or is it the special interest that powers you?” Bowman tweeted. “I’m inviting you to my district to see just how badly we need this bill. Will you tell my community ‘No’ to our face?”

On the other side of the aisle, Rep. Dan Crenshaw (R-Texas) was jubilant, tweeting that Manchin’s no means that “America has dodged a serious bullet. BBB is dead. Merry Christmas!”

ClearView Partners, a D.C.-based research firm, anticipates the new year could bring a revised Build Back Better Act (BBBA) with trimmed down energy spending.

“Democrats could face a Hobson’s Choice on a next bill (i.e., a significantly smaller bill or nothing at all),” ClearView said in a note to clients. “A future draft therefore would seem unlikely to retain the breadth and depth of clean energy spending in the House-passed BBBA. … We would not yet bet against long-term green power tax credit extensions in some form, albeit for shorter durations and/or with less generous provisions.”

Keeping Coal in the Picture

As chair of the Senate Energy and Natural Resource Committee and one of two critical swing votes in the evenly divided Senate, Manchin, along with Sen. Kyrsten Sinema (D-Ariz.), has had an outsized ability to shape key legislation, especially anything related to energy policy.

His opposition had already cut key provisions from the bill, most prominently Biden’s Clean Electricity Performance Program, which would have provided incentives for utilities to accelerate their switch to carbon-free power.

Manchin describes himself as a “conservative Democrat,” but his opposition to aggressive clean energy programs reflects his strong ties to the coal industry in his home state of West Virginia. He earns hundreds of thousands of dollars annually from Enersystems, the coal company he started, which is now run by his son, Joseph Manchin IV.

Manchin has long maintained the family business does not constitute a conflict of interest because he put his investments in a blind trust.

But The Washington Post reported last week that his most recent financial disclosure showed the company paid him $492,000 in interest, dividends and other income in 2020 and was worth between $1 million and $5 million. The blind trust Manchin created with $350,000 in cash in 2012 generated no more than $15,000 last year, the Post reported.

Manchin regularly speaks in favor of bipartisan legislation, especially when it contains dollars for his home state of West Virginia and the coal industry. For example, the $1.2 trillion bipartisan infrastructure bill, which he helped shepherd through the Senate, includes billions for the development and deployment of carbon capture, storage and sequestration projects.

Similarly, on Thursday, Manchin and Sen. John Barrasso (R-Wyo.), ranking member on the Energy and Natural Resources Committee, introduced a bill that would establish a program to provide federal dollars for building advanced nuclear reactors and related supply chain facilities on or near retired coal plants.

“Advanced nuclear technologies provide an opportunity to repurpose shuttered coal and fossil generating plants,” Manchin said in the press announcement of the bill. Such projects “could bring new high-paying jobs and economic opportunities to communities throughout West Virginia and the nation while expanding our domestic nuclear supply chain.”

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Arizona Regulators Approve Transportation Electrification Plan

The Arizona Corporation Commission has approved a statewide transportation electrification plan developed by utilities and intended to accelerate electric vehicle adoption.

The commission voted 3-1 Wednesday to approve the plan. Commissioner Justin Olson voted “no” and Commissioner Jim O’Connor abstained.

The commission also voted 4-1 in favor of directing investor-owned utilities Tucson Electric Power Co. (TEP), Arizona Public Service Co. (APS) and UNS Electric Inc. to file transportation electrification implementation plans at least every three years, starting next year. Olson was opposed.

In addition, TEP and APS must file semi-annual reports detailing their progress in implementing the transportation electrification plan.

The commission was split on a proposal from Commissioner Sandra Kennedy that would have directed the three utilities to base their EV programs and investments on a “high adoption scenario” analyzed in the transportation electrification (TE) plan.

The high-adoption scenario envisions 1.5 million light-duty electric vehicles on the road in Arizona in 2030, or about 20% of all light-duty vehicles.

That compares to a medium-adoption scenario, with 1 million light-duty EVs in the state by that year, and a low-adoption scenario, with about 250,000 EVs.

Kennedy’s proposal said that the high-adoption scenario would bring a projected $11 billion more in net benefits to the state compared to the medium-adoption scenario. But the proposal failed 2-2, with Olson and commission Chairwoman Lea Marquez Peterson opposed. O’Connor abstained.

According to the TE plan, TEP and APS support establishing an EV goal for their respective service territories based on the statewide medium-adoption scenario. For TEP, the goal is 95,000 EVs on the road by 2030. For APS, the goal is 450,000 EVs.

Aiming High

Several groups had urged the commission to aim for the high-adoption target. Doing so would allow utilities to better plan for peak loads and help certain regions of the state bring their air quality into compliance with federal ozone standards, they said.

But Marquez Peterson raised questions about the high-adoption scenario in a Dec. 13 letter to her fellow commissioners.

Marquez Peterson said the commission must base its decisions on facts and data. She said she found no evidence that the high-adoption scenario would prevent a reclassification of the Phoenix-Mesa area from “marginal” to “serious” ozone nonattainment, which is expected to occur in 2024.

The Arizona Department of Environmental Quality (ADEQ) told Marquez Peterson that the state would need to replace more than 1.3 million internal-combustion-engine vehicles with EVs within the next two years to avoid the reclassification. That assumes EV adoption is the only measure the state pursued to improve air quality.

In addition, the Maricopa Association of Governments (MAG) said that the large drops in traffic related to the COVID-19 pandemic “have not resulted in a comparable reduction in ozone air pollution,” Marquez Peterson said in her letter.

“Until MAG, ADEQ and other stakeholders determine the appropriate number of EVs necessary, there is no adoption scenario modeled in the Phase ll report [transportation electrification plan] that bears any relation to preventing or reversing ozone nonattainment in Arizona,” she wrote.

Marquez Peterson also said the commission does not have authority to require a specific number of EVs or adopt air quality mandates.

Overcoming Barriers

The transportation electrification plan is the result of a 2019 commission decision that ordered the state’s utilities to develop a long-term, comprehensive TE plan.

APS and TEP worked with consultants Energy and Environmental Economics (E3) and Illume Advising to develop the plan, which was released in March. A public workshop on transportation electrification followed in August. (See EV Growth Prompts Need for Managed Charging.)

The plan outlines barriers to transportation electrification and steps that TEP and APS are taking to overcome those obstacles. For example, to address a shortage of EV charging infrastructure, the utilities offer programs such as APS’ Take Charge AZ, which covers costs for installing EV chargers at businesses and multi-family housing.

The plan lists a wide range of recommendations from a stakeholder panel. The stakeholders advised electric utilities to devise EV rates and electrify their own fleets. The state is encouraged to enact zero-emission vehicle legislation and offer incentive programs for EVs and charging infrastructure.

As part of the plan, APS and TEP plan to track progress of transportation electrification through metrics that may include the number of public EV charging stations and plug counts, the number of customers enrolled in EV or time-of-use rates, or a summary of EV programs in each service territory.

Environmental groups were enthusiastic about approval of the transportation electrification plan.

“With more electric cars on our roads, we can lower utility rates, improve air quality, and boost public health outcomes,” Ellen Zuckerman, utility program co-director for the Southwest Energy Efficiency Project (SWEEP), said in a release. “This decision sends a strong signal that Arizona is serious about transportation electrification and all of its great benefits.”

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Mass. Adds 1,600 MW to OSW Portfolio in Latest Procurement

Massachusetts selected two projects on Friday with a total of 1,600 MW in generating capacity to move forward in its latest offshore wind energy procurement.

Mayflower Wind, awarded 400 MW and Vineyard Wind awarded 1,200 MW for its Commonwealth Wind project, will begin contract negotiations under the state’s 83C III request for proposals issued in May. If regulators approve the project contracts next year, they will bring the state’s OSW total to 3,200 MW.

“The bipartisan energy legislation our administration worked with the legislature to pass in 2016 has unlocked record low pricing and significant economic investment through three separate procurements, and the projects selected today further illustrate the potential offshore wind presents for our climate goals, our local workforce and our port communities,” Gov. Charlie Baker said in a statement.

In March, Baker signed climate legislation that authorized a new total of 5,600 MW of OSW procurements for the state by 2035. The 800-MW Vineyard Wind 1 project and the 804-MW first phase of the Mayflower Wind project won contracts under the 83C and 83C II RFPs, respectively. Vineyard Wind and Mayflower Wind were the only bidders for the latest RFP, with both entities providing multiple bid sizes. (See Mass. Governor Signs NextGen Climate Bill.)

Bidders had to address new provisions in the 83C III RFP relating to diversity, equity and inclusion. Their submissions included strategies to promote job access for disadvantaged community members and identified how projects would affect environmental justice populations in the state.

Commonwealth Wind

Avangrid (NYSE:AGR) subsidiary Avangrid Renewables and Denmark-based Copenhagen Infrastructure Partners (CIP) submitted the Commonwealth bids as a joint venture, but the companies announced a restructuring in September. Under the agreement, Avangrid will buy the Commonwealth project and the lease area for the proposed 804-MW Park City Wind project. CIP will take control of a nearby lease area for development. (See Partners Behind Vineyard Wind Divvy up Leases.)

If the restructuring is approved, the Commonwealth project will bring Avangrid’s OSW portfolio to 2,400 MW, the company said.

Contract approval for Commonwealth will move several major infrastructure initiatives forward for the region.

The developer will site an OSW control center in New Bedford, Mass., that will provide remote project monitoring. New Bedford also will be the home of a service and maintenance hub through Avangrid’s partnership with Semco Maritime.

In addition, Prysmian Group plans to build a transmission cable manufacturing facility in a former coal plant in Somerset, Mass. And Crowley Marine will develop a wind turbine assembly and staging port at Salem Harbor Station. (See Vineyard Wind to Build Salem OSW Port if Mass. Approves Newest Bid.)

Mayflower Wind

The 400 MW Mayflower Wind bid is the second award for a lease that is co-owned by Royal Dutch Shell (NYSE:RDS.A), EDP Renewables and Engie.

Development of the Mayflower project will support the buildout of an operations center in the city of Fall River. (See Mayflower Wind Pledges $81M for Economic Development in OSW Bid.) In addition, Mayflower said in October that it will work with Gladding-Hearn to build a crew transfer vessel.

“From their office on South Main to their O&M port at Borden & Remington and the tens of millions of dollars in support of education and training and supply chain growth, Fall River is poised to benefit city-wide and our residents — all of our residents — can celebrate in the new jobs and opportunities that the offshore wind industry promises to bring,” Fall River Mayor Paul Coogan said in statement.

Mayflower signed an agreement in May to use transmission assets developed by Anbaric Development Partners in Somerset to connect OSW to the New England grid.  The developers plan to interconnect both phases of Mayflower at Falmouth, Mass.

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Maryland Green Buildings Bill To Be Based on Commission Report

Commercial and multifamily residential buildings in Maryland would be required to eliminate their carbon emissions and new buildings would be all-electric under a bill being drafted in the state’s House of Delegates. And ideas in the recently released Maryland Climate Change Commission’s 2021 annual report are playing a key role, says the bill’s lead sponsor.

“I’ll be working in the House of Delegates on the buildings bill, and it’s likely we’ll be including a number of recommendations from the report, such as the electric code for new buildings and the emissions standard for existing buildings,” Del. Dana Stein (D), said in an interview with NetZero Insider. “The report has been very helpful for that.”

Stein’s proposal would seek to implement at least two of the 16 recommendations for the buildings sector, which the Commission’s Greenhouse Gas Mitigation Working Group (MWG) developed in a series of meetings earlier this year. (See Maryland Looks at Pathways to Net Zero Buildings by 2045.)

“I can’t say which of the recommendations beyond the electric code for new buildings and an emissions standard for existing buildings will be in the bill,” Stein said in an email. He said he is working on the bill with Del. Kumar Barve (D), chair of the Environment and Transportation Committee, and that he hopes they will finish drafting the bill before or shortly after the legislature’s next session begins Jan. 13.

Electric Code for New Buildings

The Mitigation Working Group recommended the Maryland Building Code Administration adopt a code that requires new buildings meet all water and space heating demand without fossil fuels (e.g., through electric heat pumps, solar thermal, etc.) and can accommodate solar panels, electric vehicle charging, and building-grid interaction. It would apply to all new residential, commercial and state-funded buildings beginning no later than 2024.

Exemptions would be allowed for building types for which compliance is not feasible. The Building Code Administration also would be required to develop a cost-effectiveness test, including the federal social cost of carbon, to allow building projects to seek variances to code requirements. A new commercial building that receives a variance and produces greenhouse gas emissions on-site would be required to participate in the proposed Building Emissions Standard and follow a “tailored plan” for reaching net-zero emissions. Residential building projects would also be permitted to seek variances using the cost-effectiveness test.

Annualized-lifecycle-consumer-costs-(E3)-Content.jpgAnnualized lifecycle consumer costs, including costs for equipment, operations and maintenance, and utility bills, for several types of buildings. | Energy + Environmental Economics (E3)

The Building Code Administration also would be charged with developing training courses on the benefits and challenges of all-electric and electric-ready buildings for developers, real estate agents, appraisers and lenders.

The MWG cited studies that it said found new all-electric homes have lower construction and energy costs than mixed-fuel homes, which would improve housing affordability and local air quality while also reducing greenhouse gas emissions. The group said heat pumps work well in Maryland’s climate and are the second most common heating system for buildings in the state.

But the MWG called for cost-effectiveness tests in recognition that all-electric design can increase construction and energy costs for commercial construction.

The MWG said the state could adopt the New Building Institute’s Building Decarbonization Code, which includes an all-electric pathway. It also pointed to recently adopted building energy efficiency codes in California and Washington.

Emissions Standard for Existing Buildings

The MWG also recommended the Maryland Department of the Environment develop a Building Emissions Standard to bring commercial and multifamily residential buildings to net-zero emissions by 2040, with state-owned buildings facing a 2035 deadline. Historic buildings would be exempt.

The state would require measurement and reporting of on-site emissions beginning in 2025 and provide financial support for implementing emissions reduction measures. Such measures would include building shell and other energy efficiency improvements and replacing fuel-burning equipment with heat pumps and induction cooktops.

It would provide an “alternative compliance pathway” allowing commercial building owners to pay a fee for emissions above target levels. The fee would be “reasonable,” perhaps corresponding with the cost of carbon sequestration or negative emissions technologies, “but not less than the federal social cost of carbon.” The MWG set the target date for 2040 to allow the state time to invest revenue from non-compliance payments into measures such as carbon sequestration or negative emissions technologies to address remaining emissions.

The proposal also would offer commercial tax credits and direct subsidy payments to reduce the simple payback period for decarbonization improvements to between three and seven years.

The MWG cited New York City and Boston as among the cities that have implemented building performance standards for commercial buildings to eliminate emissions.

The Climate Change Commission’s recommendations for single-family homes have to do with funding mechanisms to encourage conversion to electricity rather than the mandates proposed for commercial and multi-family homes.

Controversial Interim Goal Dropped

Stein said the building recommendations were “very strong.

“In buildings, there [previously] wasn’t a game plan for getting that sector to net zero. So, the focus and recommendations are very good,” he said.

But he added, “One area I wish they would have been stronger in was the building emissions sector — though the final goal is net zero, there is no interim goal.”

At its Oct. 13 session, the MWG set aside a proposed interim goal of a 50% reduction in direct emissions from covered, non-state-owned buildings by 2030. It will instead consider it for review in its 2022 work plan.

“There was a 50% interim goal, but some thought that was too aggressive, so it was tabled till next year,” Stein said.

Also supportive of the commission’s 2021 report was David Smedick, acting deputy regional campaign director for the Sierra Club’s Beyond Coal Campaign. “For two years in a row now, the Maryland Commission on Climate Change has delivered a clear message to the governor and General Assembly: The state must rapidly ramp down and eliminate fossil fuel use, grow clean energy, and electrify our buildings and vehicles,” he said in an email to NetZero Insider. “This isn’t a complicated formula, but Maryland has been stuck in debate and incremental climate progress for years.

“Now is the time for the bold action from Annapolis leaders to retrofit and electrify our building stock, plan the transition off coal and fracked gas power plants, commit big to offshore wind and solar, and transform the state’s transportation systems to grow public transit and electrify vehicles,” he said. “We’re in a code red climate emergency. Anything less than transformative action is failure.”

Capitol Strategies lobbyist Erin A. Appel, who represents the International Association of Shopping Centers, said the group had no immediate comment on Stein’s proposal.

Tom Ballentine, vice president of policy and government relations for the Maryland chapter of the Commercial Real Estate Development Association, who serves on the MWG; Kristin Hogle, director of external communications for the Maryland Building Industry Association, and lobbyist Ashlie Bagwell, who represents Federal Realty Investment Trust, did not respond to requests for comment.

16 Recommendations

The climate change commission’s appendix on its Building Energy Transition Plan, released last month along with the annual report, made 16 recommendations. In addition to the two provisions Stein has embraced, they include a clean-heat retrofit program in which all low-income households would be retrofitted by 2030. Fuel-switching and beneficial electrification would be encouraged beginning in 2024 through EmPOWER, the state’s energy efficiency program. The retrofitting program would include a target of having heat pumps account for 50% of residential heating, ventilation, and air conditioning and water heater sales by 2025, and 95% by 2030.

The commission also called for developing utility transition plans, ending EmPOWER subsidies for fossil fuel appliances, and having the state lead by example through the electrification and decarbonization of buildings it owns. It also proposes allowing local jurisdictions to set higher fines for non-compliance on building performance, and identifying locations that need grid upgrades to accommodate all-electric buildings.

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NERC Identifies 10-Year Challenges from Weather, Resource Mix

The growing frequency of severe weather events and a rapidly diversifying resource mix will present closely intertwined challenges to electric reliability in the coming decade, NERC said in its annual Long-Term Reliability Assessment (LTRA), released Friday.

“Our traditional baseload generation plants like coal and nuclear are retiring, and lots of new natural gas and variable generation, mostly solar and wind, have been deployed,” John Moura, NERC’s director of reliability assessment and performance analysis, said at a media event accompanying the release of the report.

Moura called the transition to renewable resources “a really great thing for our decarbonization efforts,” but added that “it’s vitally important that we [build and operate] a bulk power system that can be resilient to the extreme weather we’re seeing.”

NERC produces the LTRA every year to assess North American resource adequacy in the next decade and to identify trends that could affect grid reliability and security. This year’s assessment identified resource adequacy as a serious concern in MISO, Ontario and the south-central U.S., while extreme weather poses the biggest concern in New England and Texas. The Western Interconnection — including California, the Northwest and the Southwest — faces both risks.

Transition to Renewables Continues

Tier 1 and 2 planned resources (NERC) Content.jpgTier 1 and 2 planned resources projected through 2031. Tier 1 resources are planned capacity that have completed or are under construction, or have a signed/approved interconnection service, power purchase, or wholesale market participant agreement. Tier 2 resources are capacity that have signed/approved completion of a feasibility, system impact, or facilities study; have requested an interconnection service agreement; or are included in an integrated resource plan. | NERC

The resource adequacy challenge is partially caused by the decommissioning of traditional generators. MISO, for example, is projected to retire more than 13 GW of resource capacity between 2021 and 2024, while the report warned that the planned retirement of California’s Diablo Canyon nuclear power plant could contribute to more than 3 GW of capacity shortfalls beginning in 2026. Across the bulk power system, total capacity retirements are expected to top 60 GW by 2031, with coal making up the majority of plants decommissioned.

NERC’s projections show a steady decline in coal and petroleum generation through 2031, with the greatest growth expected in solar. Natural gas, meanwhile, is set to expand into the gap left by the retiring coal plants.

The more than 100 GW of additions to the BPS over the next 10 years — considering only Tier 1 resources, which comprise completed and under construction projects, as well as those with signed and approved interconnection service or power purchase agreements — are almost entirely solar and natural gas facilities. Other forms of generation, such as wind, petroleum, hydropower and nuclear, account for around 20% of capacity additions, with wind comprising nearly half of these.

With Tier 2 resources added in — those with signed or approved feasibility, system impact, or facilities studies, or that have requested an interconnection service agreement — solar plants are expected to grow from the current level of 41 GW to around 331 GW during the next 10 years. By the same measure, wind resources are set to expand from 132 GW to more than 244 GW over the same period.

The simultaneous growth of gas and solar is no accident, said Mark Olson, NERC’s manager of reliability assessments. Solar panels are naturally dependent on the availability of sunlight, and while the resources planned for addition are sufficient to meet demand at peak hours — typically in the middle of the day — they actually pose a problem later in the afternoon. At these times demand is lower, but the output of solar panels falls off sharply because less light is present, requiring another resource to pick up the load.

“Even though the reserve margins are adequate, energy risks are reduced by having sufficient flexible resources, which are resources that can be dispatched by the operators to follow demand, balance the system and make up for drop-off in variable resources,” Olson said. “And natural gas-fired generation is an important resource, as are effective demand response programs, in helping to reduce risk associated with [that] drop-off.”

Climate Change Makes Demand Forecasting Harder

While the weather restrictions of solar and wind imply that balancing resources should be expanding with them, Olson noted that the opposite seems to be happening in some regions, with “flexible generation resources … falling in Texas, California and the U.S. Northwest.” He warned that without local flexible generation, such areas will be dependent on weather-dependent facilities and external transfers. However, “extreme weather conditions raise the likelihood for one or more of these resources to fall short … leaving other resources to make up for this gap or … load will need to be shed.”

The LTRA noted that this combination of new types of generating resources and growing climate challenges means that existing methods of measuring resource adequacy may not be adequate. In particular, the report noted that the reserve margin — NERC’s traditional metric for reliability, defined as the difference between projected on-peak capacity and forecasted peak demand, divided by peak demand — may be too limited to capture the nuances of new generating resources.

“It’s kind of a simplistic way of looking at one hour and coming to a conclusion for all other hours,” Moura said. “And that’s served us well, and [still] serves us well in certain parts of the [continent] … where you have a lot of dispatchable resources. But in areas where we’re seeing these energy constraints, like in California, the Northwest, and ERCOT, we need to look with a different lens.”

Moura said that NERC has “a close partnership on a project right now with [the] Electric Power Research Institute” to study new metrics for use in planning and decision making. He suggested that industry stakeholders may also draw on work from their counterparts in other countries, without elaborating on what these might be.

“That is only part of the solution because then you … actually have to” create and enforce new standards based on these metrics, he added. “But right now, we’ve got to define this measuring stick to really help and guide what that path looks like going forward.”