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November 2, 2024

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SEIA Top Priorities: Build Back Better, Supply Chains, Diverse Workforce

WASHINGTON — The message coming out of the Solar Energy Industries Association’s 30×30 Policy Forum on Dec. 2 was optimistic and unequivocal: the Build Back Better Act would be passed by the Senate.

Exactly when and in what form the budget reconciliation package would make it to President Biden’s desk are still uncertain, but its $555 billion in energy funding — including 10 years of solar and storage investment tax credits (ITCs) — are not among the sticking points under debate in the Senate.

Build Back Better “is going to get done, and it’s the largest investment in clean energy by any country ever,” Trent Bauserman, senior policy adviser to House Majority Leader Steny Hoyer (D-Md.), said during a congressional update at the forum. “And the really interesting thing is, for all the trials and tribulations of getting this across the House floor, nobody was really talking about paring back climate.”

Bauserman was confident about passage in part, he said, because about 90 to 95% of the bill’s provisions were “pre-conferenced” with Senate moderates before it passed in the House of Representatives on Nov. 19. (See House Passes $1.75 Trillion Build Back Better Act.) And while the Clean Electricity Performance Program, which would have paid utilities to decarbonize their generation, was cut from the bill, those funds were reallocated to other energy initiatives, he said.

The focus now, for SEIA members and other speakers at the forum, are the tax incentives in the bill, which are seen as critical to reaching Biden’s goal of a clean power system by 2035, and SEIA’s target of 30% of U.S. power generation coming from solar by 2030.

Keynote speaker Ali Zaidi, deputy national climate adviser at the White House, said the bill would “help propel deployment [of clean technologies] — which we know is connected to manufacturing — over the next decade through a tax policy that incentivizes deploying [solar] in those lower-income areas; through a tax policy that incentivizes paying a good wage; through a tax policy that provides folks certainty to know that in 2030, we’ll still be there.”

Alice Lin, budget and tax policy adviser for the House Ways and Means Committee, recalled that Democrats had been fighting for two years to get a five-year extension for solar and wind tax credits. “Getting any extension at all was a tremendously difficult task,” she said. “I don’t have to tell you all what the outlook looks like with these one- [and] two-year extensions and what that does to the building of uncertainty.”

Including prevailing wage provisions in the tax incentives also helped build strong labor support for the bill, Lin said. Projects paying prevailing wages — the basic hourly rate for public works projects in a given area — are eligible for a “bonus” incentive.

“It was very clear that if we did not figure out how to ensure that our labor friends were fully part of the process, we would not be looking at the same conversation on extensions again,” she said. “We worked early and often with our labor friends in order to figure out a path forward,” which involved a lot of education on labor laws and domestic content standards, she said.

‘Locked and Loaded’

Ending a range of solar tariffs, primarily on components and panels from China, is another major target for SEIA. The U.S. International Trade Commission recently recommended extending the Section 201 tariffs imposed by former President Donald Trump, but the final decision rests with Biden.

During a session on building a U.S. supply chain, Costa Nicolaou, CEO of racking manufacturer PanelClaw, said the tariffs and other anti-dumping and countervailing duties (AD/CVD) intended to spur U.S. solar manufacturing have instead “crushed the industry [while] the value chain grew in other parts of the world.”

And although the solar industry as a whole showed strong growth in recent years, “it was in spite of, not because of AD/CVD,” said Nicolaou, who also chairs SEIA’s manufacturing division.

“One of the things that we’ve realized over the last 10 years is that trade and manufacturing policy are inextricably linked,” he said. “People aren’t just going to move here and move their businesses here out of the goodness of their hearts because politicians want them to. They need real incentives that allow them to grow their business, to hire people [and] invest in technology.”

The 10 years of tax credits for advanced manufacturing in the budget reconciliation bill will provide a long enough runway for companies coming to the U.S. to recoup their investments, he said.

At the same time, the tax credits — focused on solar panels, wind turbines and storage technologies — still create winners and losers, said Jessica Lawrence-Vaca, director of policy and stakeholder engagement for SOLV Energy (formerly Swinerton Renewable Energy), which builds and maintains projects. “At what point do we transition to a manufacturing tax credit … that will help the whole of the industry?” she said.

Pointing to system components that are not eligible for Build Back Better tax credits, Lawrence-Vaca said, “There’s another 50% of the solar value chain that is not being incentivized.”

The 10-year runway for building out a full manufacturing supply chain will also be critical, Nicolaou said. Many companies, he said, are “locked and loaded,” ready to start investing in new facilities once Build Back Better is passed, but they will have different time frames.

“It can be pretty quick on the panel assembly side, when the components from overseas [are] assembled here,” he said. “What will take longer is the cradle-to-grave [supply chain]; that will not be built for panels overnight. So, there’s a transition we have to manage.”

Zaidi agreed. “We’ve got real challenges when it comes to the supply chain,” he said. “And we’ve been, I think, having a really honest dialogue with the industry about what it’s going to take to create the conditions, again, for private capital to feel confident rushing in and making the sort of investments that we’re going to need to grow this market.”

Allies Needed

The rapid deployment of solar should mean more than just the 1 million jobs SEIA estimates will be created by reaching its 30×30 target — up from the 231,000 jobs counted in the 2020 Solar Job Census, which SEIA co-sponsored with other solar advocates.

The goal here should be to “make sure that folks really do have an opportunity to have a long-term career in the clean energy industry and feel fully supported both from a salary perspective, a benefits perspective and everything that comes along with that,” said Nicole Steele, senior advisor for equity and workforce at the Department of Energy.

Attracting and retaining a diverse, inclusive clean energy workforce that “looks like America … requires targeted recruitment and targeted mentorship and really thoughtful training and skills development,” Steele said during a video address to the forum.

DOE is working with the Department of Labor to leverage their existing programs, she said, but incorporating equity into workforce development should be industry-driven.

Labor unions’ training centers and apprenticeship programs, and their 20,000 instructors, could be a good fit for solar workforce development, said Jason Walsh, executive director of the BlueGreen Alliance, a group that includes 13 labor unions and environmental organizations.

“If the system were a four-year, degree-granting institution, that would be the largest four-year institution in the country,” Walsh said.

He also stressed the political upside of a solar industry-union partnership. “Opponents of renewable energy have a playbook. … It is to use every siting, permitting and regulatory and legal lever to slow down or block deployment of solar energy,” he said. “Whether it is in any of your county commission meetings or PUC meetings or state legislatures, the solar industry will need allies to show up with you,” something that labor unions are “very, very good at,” he said.

George Hershman, CEO of SOLV Energy, said his company works on projects across the country and hires 85% or more of their workforce locally. “It’s diverse by nature” and geography, he said, “and then a portion of those employees want to stay in the industry, and they want to travel.”

Building a diverse solar workforce also provides “an opportunity to push back on, frankly, some larger cultural trends,” Walsh said. “We have devalued blue-collar work over decades. This is incredibly important, incredibly skilled work. The more we can demonstrate that it is those things … the more you change that cultural conversation, and you change the profile of this workforce.”

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NJ Legislators Back Alternatives to Electric Heat

New Jersey legislators backed a bill Monday that would prevent state agencies from requiring buildings to use electric heating or hot water boilers as part of the state’s carbon reduction efforts, echoing efforts in 20 states to keep natural gas and other alternative fuel options viable.

New Jersey’s Senate Community and Urban Affairs Committee voted 5-0 to support the bill, S4133, which would prohibit any state agency from enacting a requirement that makes electric heating the “primary means” of heating or providing hot water to commercial or residential buildings in the state.

Although some supporters of the bill acknowledged that the state has made no move to mandate the use of electric heating, they said that such a mandate could result from Gov. Phil Murphy’s 2019 Energy Master Plan, and his drive to power the state with 100% clean energy by 2050. Murphy’s plan calls for heavy investment in electricity infrastructure, including solar and offshore wind facilities, and in promoting the use of electric vehicles (EVs).

The plan also calls for the building sector, which accounts for 62% of the state’s end-use energy consumption, to be “largely decarbonized and electrified” by 2050, with a focus on “new construction and the electrification of oil- and propane-fueled buildings.”

Following his narrow re-election last month, Murphy signed an executive order setting a new target for greenhouse gas reduction in the state — 50% over 2006 levels by 2030 — moving toward his goal of an 80% reduction by 2050. (See Murphy Toughens NJ Emission-reduction Goals.)

The bill’s advance follows the introduction of so called “preemption bills” that would prevent electrification requirements in 20 states this year, 16 of which have been enacted or await their governor’s signature, said Rita Yelda, spokeswoman for the Natural Resources Defense Council (NRDC). Another four such preemption bills designed to stop electrification took effect in 2020, Yelda said.

Preemption legislation is put in place to stop the later enactment of a policy that the preemption supporters oppose. Media reports depict the opposition to electricity as a campaign waged by the natural gas industry to protect its interests. The impetus for these laws can be traced back to ordinances in more than 20 cities in California either requiring or encouraging building electrification in new construction.

The committee’s approval came as the Assembly Telecommunications and Utilities Committee amended and supported a bill, A5655, that could also put a damper on Murphy’s focus on electricity. The bill would require the state Board of Public Utilities (BPU) to create a program to “encourage the procurement of renewable natural gas (RNG) and utility investment in supporting infrastructure.”

The bill, which defines RNG as biogas, hydrogen gas or methane gas, initially set a target that by 2022 5% of gas used in the state should be RNG, rising to 30% by 2045. But an amendment removed the targets before the committee released the bill. It also sets out a mechanism by which ratepayers would fund investments made in line with the bill’s requirement to encourage the use of RNG. The funds will be “recovered from ratepayers by means of a periodic recovery mechanism established by the” BPU, the legislation states.

Neither of the two bills is close to enactment, as both still need Senate and Assembly approval, before going to Murphy’s desk. To be enacted, they will need to pass both houses by the time the session ends in mid-January or start the legislative process again in the new session.

Mandate or not?

The Senate hearing on the possible prohibition of an electricity mandate drew support for S4133 from more than a dozen business groups and private companies, among them the New Jersey Chamber of Commerce and the New Jersey Business & Industry Association, two of the biggest business lobbying groups in the state. Supporters also included the New Jersey Propane and Gas Association, the Fuel Merchants Association of New Jersey and several advocacy groups for the building industry.

In opposition, environmental groups argued that the bill is misleading in its concept and would limit the state’s ability to fight climate change.

“This bill presumes that mandates are already happening, are about to happen, and they are not, not even close,” said David Pringle, a steering committee member of Empower NJ, which represents a coalition of environmental groups. “And it ties the hands of government to tackle the climate crisis, which is unacceptable.

“Making it harder to appropriately electrify means more people will die sooner,” he said, adding that the fossil fuel industry is “shamelessly using scare tactics.”

Proponents of the legislation said that the bill would merely allow the state to keep its options open and adopt low-carbon alternatives to electrification if such technologies are developed to the point where they are viable.

“We believe it’s far too early to pick winners and losers and force one type of energy on our residents,” said Robert Pohlman, managing director of innovation and strategic initiatives at New Jersey Natural Gas, a natural gas utility.

He said the ratepayers had invested $17 billion to create the infrastructure through which natural gas is supplied to their homes. That infrastructure could be used to bring alternative fuels, such as hydrogen or RNG, to consumers, but it would be discarded if buildings transitioned to electricity.

“The state must not close itself off from the future benefits of investment, innovation and competition happening around low-carbon fuels today,” Pohlman said.

Arguing that Murphy will ultimately want to mandate electric heating, Eric DeGesero, executive vice-president of the Fuel Merchants Association of New Jersey, cited proposed rules that the state Department of Environmental Protection issued Monday that would place additional permit requirements on fossil-fuel fired boilers. The proposed rules would also ban the use of No. 4 and No. 6 fuel oils, both of which can be used for space heating and power generation, according to the U.S. Energy Information Administration.

“It’s absolutely true,” that the master plan does not mandate electric heating use, DeGesero said. Instead, the master plan “says we’re going to get rid of heating oil and propane first, because you guys are smaller market share. And then we’ll get to natural gas later.”

Echoing other bill supporters, DeGesero said that the association agrees with Murphy’s climate change goals but not with the governor’s plan for achieving them. He said some of the policies create a scenario in which “the clock is ticking on putting the Fuel Merchants Association members out of business.”

Cost of Electricity

Much of the discussion centered on the cost of electrification and the cost of implementing Murphy’s masterplan. So far, his administration has not estimated the cost and in May moved to hire a consultant to make that calculation, with the outcome expected around the end of 2022.

Sen. Troy Singleton, (D), the committee chair, said there is little doubt that natural gas heating is cheaper than electricity and that some low-income homeowners would be “potentially priced out” if they had to convert their home to electric heat. But he added that even if the bill passed, and there could be no mandate to use electric heating in the state, there would be nothing to stop the government from offering incentives to persuade homeowners to convert.

“We do (that) in a whole host of other renewable energy spaces, which have proven to work,” said Singleton, who voted in support of the bill.

Eric Miller, energy policy director for the Natural Resources Defense Council, argued that the greater use of heat pumps would help keep costs down, and so make electrification attractive in the long run. Heat pumps employ an electric heating and cooling technology that extracts heat from the air, water or ground outside a building and transfers it inside.

He cited studies by the Acadia Center, a clean energy advocacy group, which has reported that a home that fully converts from propane to heat pumps could save $1,650 a year on fuel. He argued that the bill could limit the ability of government departments to back energy programs that their studies show are effective and consumer friendly.

“Those programs need the flexibility to adapt to new technologies and make sure that customers have affordable and clean heat in their homes,” he said.

Sen. Declan J. O’Scanlon, (R) a committee member and sponsor of the bill, said he is concerned about the cost of the governor’s master plan. He said the legislation is designed to stop “the government putting its hand on the scale,” and restricting consumer choices by picking one particular way to get to a carbon-free energy.

“It’s got to save money,” he said. “And (if) you’re saying that it will ultimately save money, people will naturally choose these things.”

Joseph Uglietto, president of Diversified Energy Specialists, a Massachusetts-based renewable energy consultant that helps biofuel distributors reduce their carbon emissions, said the topic is key because so many households in the state use fossil fuels to heat their homes, He cited a project by the Massachusetts Clean Energy Center that concluded that retrofitting an existing building with a heat pump costs on average $20,000.

DeGesero, who has been working with Uglietto, said, “It sounds very expensive, very time consuming and very inefficient.”

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Experts Put Interregional Tx Under a Microscope at CLEANPOWER

Planning and developing interregional transmission is “one of the greatest challenges” to building a clean and reliable power grid, Hunter Armistead of Pattern Energy said at CLEANPOWER 2021 on Wednesday.

“The energy transition that we know is going to occur requires interregional planning,” Armistead, Pattern’s chief development officer, said during the American Clean Power conference in Salt Lake City.

In the absence of a single directive to make more connections between major U.S. regional grids, progress on that front is slow and cumbersome.

FERC has had a light touch on the issue, but stakeholders have suggested that that should change.

“We’ve heard an interest in maybe being a bit more specific with our requirements for interregional planning,” Elizabeth Salerno, FERC’s lead for transmission and technology initiatives, said during the panel discussion.

FERC could make interregional planning a requirement rather than only requiring coordination, which she said has produced varying degrees of participation by regions.

A planning requirement from federal regulators would also mean addressing the “tricky” issue of interregional cost allocation, she said.

Additionally, coordination efforts are hampered by regional differences, Salerno said.

“They have different inputs, different scenarios and different modeling methodologies, and that makes it really hard to coordinate across footprints,” she said.

It may be possible, she added, for FERC to build more consistency across regions, thereby making cross-regional coordination easier.

While regional interconnections are needed to transmit remote clean energy resources to demand centers, Salerno said there is also an important conversation to be had about the reliability benefits of interregional transfer capacity.

During the cold-weather event that devastated the Texas power grid in February, MISO and SPP were able to lean on PJM and bring in a lot of power, she said.

“That was able to alleviate some perhaps worse outcomes than what we faced,” she said. “Contrast that with the situation in Texas, which has limited interconnections, and how that event played out there.”

MISO’s interconnection with PJM was “fortunate,” MISO executive director Derek Bandera said.

“We were able to wheel a lot of power from the PJM region … and we were able to help our neighbors SPP to the west,” she said.

Much of the transmission that facilitated that exchange, he added, was built to help move wind power to the East.

“We saw a huge reliability and resilience benefit from that,” he said.

Given the immense challenges that come with interregional planning, Bandera said regions need the ability to innovate.

“One of the key takeaways as we think about making [interregional transmission] happen is making sure that the regions have the flexibility to come up with innovate solutions and not necessarily get hamstrung by some set of rules,” he said.

The work that MISO and SPP have done to recognize interregional transmission as a priority is an example of strong leadership on the issue, according to Andrew French, chair of the Kansas Corporation Commission.

“I don’t think I could have seen that happening eight or 10 years ago,” he said.

The two RTOs, he added, have been under political pressure from states and regulators to find solutions to interconnect the regions.

But that kind of pressure is not a “one-size-fits-all” solution, according to French, who says there’s more room for leadership on this issue.

“That’s where FERC and other policymakers can come in,” he said. They can “be the adult in the room and add the encouragement that [interregional] initiatives need to continue.”

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Stakeholders Approve ISO-NE Order 2222 Compliance Plan

ISO-NE’s proposed set of market rules to implement FERC Order 2222 carried the day Wednesday as stakeholders approved its compliance filing and rejected several amendments opposed by the RTO.

The NEPOOL Markets Committee recommended that the Participants Committee approve the filing, which must be submitted by Feb. 2, and rejected six amendments proposed by Advanced Energy Economy (RM18-9).

Order 2222 is intended to allow distributed energy resource aggregations to provide all wholesale services that they are technically capable of providing, and the RTO has been working on its compliance filing for the past year. (See “AEE Offers Amendments for Order 2222 Compliance Proposal,” NEPOOL Markets Committee Briefs: Oct. 13-14, 2021.)

AEE proposed a series of individual amendments that are not part of an overall package, including allowing sub-metered load to participate as demand response and sub-metering by third parties. A proposed amendment to incorporate a periodic review requirement was withdrawn by AEE following consultations with the RTO.

Several stakeholders abstaining on the amendment votes said they needed more time to consider the tariff changes and would look forward to having another chance to vote on at least some of them at the Jan. 6 Participants Committee meeting.

The NEPOOL Transmission Committee is scheduled to vote on the Order 2222 proposals Dec. 13, as the Reliability Committee is the following day.

Filing Specifics

The compliance filing passed the MC with 71.11% in favor, with16.7% of the Generation sector in favor, with one abstention; 16.7% of the Transmission sector in favor; 14.31% of Suppliers in favor, with 2.39% opposed and five abstentions; 16.7% of Publicly Owned Entities in favor; 6.7% of Alternative Resources in favor, with 9.8% opposed and two abstentions; and 16.7% of End Users opposed, with one abstention.

The RTO said that additional tariff changes associated with the energy and ancillary services markets were designed to address stakeholder feedback. For example, one change would clarify that a DER aggregation with non-storage resources may participate using the continuous storage facility or binary storage facility model.

UMass-Solar-Canopies-(UMass)-Alt-FI.jpgUMass Amherst in 2021 is installing 4 MW of solar canopies with Tesla battery storage to produce electricity. | UMass

Other changes would clarify DER size requirements; include procedural details in the registration coordination process; further clarify responsibilities of the host utility (or its agent) and DER aggregators; and clarify the dispute resolution process between DER owners and aggregators.

Another change would require a DER aggregation’s designated entity or demand designated entity to comply with both ISO-NE’s and the host utility’s procedures and requirements to the extent applicable.

The proposed effective date for the changes to the Forward Capacity Market would be during the fourth quarter of 2022 to allow the RTO to implement changes in time for the Forward Capacity Auction 18 qualification process, which starts in the spring of 2023.

Assuming that the commission accepts the compliance filing by Q4 2022, distributed capacity resources will be able to participate in FCA 18, which will be conducted in February 2024 for the capacity commitment period beginning June 1, 2027.

The proposed effective date for the E&AS markets changes would be in the fourth quarter of 2026 to allow resources to be commercial and integrated before the CCP beginning June 1, 2027.

Amendment Details

The MC voted against AEE’s proposed amendment to expand baseline calculation optionality for DR resources and aggregations by using an add-back baseline methodology under which such resources would receive no positive settlement payments for either the day-ahead or real-time energy market. The amendment received only 26.78% in support.

AEE characterized the proposed changes as designed to further ensure a facility would be unable to receive payments if they take no action to reduce their consumption from the grid.

The MC also voted against (with only 32.98% in favor) a proposed amendment to expand baseline calculation optionality for DR resources and aggregations by allowing generation to count as load reduction.

The RTO noted in its memo on the amendments that its proposed implementation of Order 745, which stipulated that DR providers be compensated at the same rates as generators, was opposed by a coalition of DR providers and an industrial energy consumer group.

“These parties wanted to be able to measure demand response performance by directly metering behind-the-meter generation, which is what AEE’s proposed revision would allow. The commission considered the evidence presented and found [ISO-NE’s] approach to be the preferred one,” the RTO said.

The MC also voted against proposed amendments to:

  • allow sub-metered load to participate as DR (36.02% in favor);
  • allow DERs associated with an aggregation to use a third-party meter reader to meet its metering and meter data service requirements (40.7% in favor);
  • remove barriers for DERs that can provide ancillary services by removing the requirement to clear in the energy market if providing spinning reserves (35.9% in favor); and
  • remove barriers for DERs that can provide ancillary services by allowing sub-metering for resources providing regulation (32.56% in favor).
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WECC Taking ‘Greenfield’ Approach to SOTI Improvements

In light of the evolving challenges facing the Western Interconnection, WECC plans to continue improving its annual State of the Interconnection (SOTI) report, staff said Tuesday.

Speaking to WECC’s Member Advisory Committee (MAC), Vic Howell, the regional entity’s director of reliability risk management, said the 2020 SOTI “marked a pretty significant change” in how WECC organizes the annual report, with a summary document added to the usual online portal. While similar “monumental improvements” were not possible for this year’s report because of “other priorities,” he said the RE hopes to “reimagine” the SOTI — both its final form and the process of creation — for next year’s version.

“We’re not real sure what that’s going to look like — we’re trying to get through this year for now. But we’re really going to take some time to think about what the SOTI could be [and] what it should be,” Howell said. “And we’re going to be talking to a lot of people and really thinking greenfield about this. … We’re going to be thinking big and bold.”

EEAs Rise while Misoperations Decline 

The 2021 SOTI — released in August — noted a steady rise in energy emergency alerts (EEAs) over the past four years, from 11 in 2017 to 46 in 2020. Thirteen of the EEAs experienced last year were Level 3, a decline from the previous year’s 19 but still accounting for 70% of the entire ERO Enterprise’s EEA Level 3 events for the second straight year.

Misoperations-rate-in-the-Western-Interconnection-(WECC)-Content.jpgMisoperations rate in the Western Interconnection by quarter | WECC

Authors of the report indicated that likely future increases in the incidence of extreme weather events like the August 2020 heat wave, during which 42% of all EEAs and 54% of Level 3 events occurred, means Western utilities need to prepare for more emergencies. The “growing frequency and intensity of wildfires across the West” is another major reliability risk.

While the level of EEAs has grown over the past four years, the protection system misoperation rate has fallen from over 7% in 2016 to below 4% in 2020. The SITO attributes the decline in misoperations to WECC’s “strong partnership with industry protection system experts,” through which it “vets and maintains” misoperations data to improve utilities’ performance.  

Current-capacity-by-fuel-type-(WECC)-Content.jpgThe Western Interconnection’s current capacity by fuel type in MW | WECC

This year’s SITO also warns about the interconnection’s growing reliance on variable energy resources such as wind and solar power, which together comprise more than 18% of the West’s current capacity, more than coal at 11%. In future years, the report says, both resources will exceed coal on an individual basis because of “drivers like clean energy policy, economics and customer choice.”

As generating capacity increasingly shifts to weather-dependent resources, grid planning must become more adaptable, particularly when it comes to resource adequacy. Small-scale resources like batteries and rooftop solar panels, which are harder for utilities to monitor, will add to these planning challenges.

2021 Report Addresses Longer Time Frame

This year’s report did produce one significant change with the summary document including data from early 2021, though the online portal only covers the 2020 calendar year.

Howell said the scope of the summary document was expanded because “the timing of the release of the report” created an opportunity to include events from this year such as July’s wildfires, which led to the derating of the Pacific DC Intertie and the near shutdown of the California-Oregon Intertie. (See Wildfires Raise Concerns for Western Tx Lines.) However, the inclusion of these more recent events is meant to enhance the SOTI’s goal of identifying ongoing trends in the interconnection, rather than expand its focus into the following year.

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California Energy Commission Approves $500M for EV Charger Incentive Programs

The California Energy Commission on Wednesday approved allocating up to $500 million in grant funding for electric vehicle charging incentive programs.

Up to $250 million in funding will go to CALSTART, a nonprofit group focused on clean transportation technologies; up to another $250 million will be awarded to the Center for Sustainable Energy (CSE), a nonprofit that provides energy program administration and consulting services.

The two groups will design, implement and manage incentive programs for EV charging infrastructure. The groups will develop the programs after gathering stakeholder and community input and holding public workshops.

Although details of the incentive programs have not yet been worked out, the programs are expected to include a focus on disadvantaged and low-income communities as well as multi-family housing.

CEC voted 5-0 on Wednesday to approve $1 million each to CALSTART and CSE to cover program startup costs. The commission also gave its executive director authority to allocate additional funds, up to a total of $250 million to each group, to implement the incentive programs.

The incentive programs are expected to add thousands of EV chargers in California, helping the state meet its goal of 250,000 public and shared chargers by 2025. A recent report estimated the state will need 1.2 million chargers for light-duty vehicles by 2030.

The state now has an estimated 195,000 EV chargers planned or already in place, said Phil Cazel of the CEC’s Fuels and Transportation Division.

The funding is coming, in part, from the CEC’s Clean Transportation Program, which got a boost this year when the state legislature approved a record $2.7 billion for zero-emission vehicle programs in FY 2021/22. (See Calif. Earmarks $3.9B for ZEVs Through 2024.)

“We are going to be watching this really, really closely,” CEC Chairman David Hochschild said. “The stakes are extremely high for the state, for our climate goals. We want this money to be well deployed, well administered and to get out quickly.”

In a separate agenda item, CALSTART also was awarded $226 million to run incentive programs for medium- and heavy-duty zero-emission vehicle charging and refueling infrastructure. The funds are in addition to a $50 million award to CALSTART in March. (See Calif. Energy Commission OKs $50M for Truck Charging.)

In total, the CEC approved $730 million in grants for transportation electrification projects, the largest amount of grant funding voted on in a single commission meeting, Hochschild said.

“This is really an important milestone,” he said.

Other groups awarded grant funding include Rail Propulsion Systems LLC, which will receive $270,000 for a demonstration project showing that a battery-electric locomotive can be charged wirelessly. The system will allow the locomotive to recharge along an eight-foot stretch of track.

Commissioner Patty Monahan said she envisioned the system as “opportunity charging,” where the locomotive could get a little “extra juice” at the wireless location rather than fully recharging.

“There’s not yet a full-on business case for this, but we’re making these exploratory investments because the future of charging is changing so fast,” Monahan said.

Another grant award went to the Center for Transportation and the Environment Inc., which will receive $3 million to design, build, test and demonstrate two zero-emission vehicles to be used in emergency disaster relief. The hydrogen fuel-cell backup generation vehicles, also known as H2BUG, will be designed to travel 90 miles each direction and provide at least 35 kW of continuous power for 48 hours or longer.

The vehicles will be designed similarly to incident command vehicles. They will support charging of cell phones and other devices, lighting, refrigerators and communication systems.

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Virginia Adopts Advanced Clean Cars Regulations for 2025 Models

Virginia air regulators last week unanimously approved a measure to adopt standards that will reduce vehicle tailpipe emissions and set zero-emission vehicle sales requirements for car manufacturers.

The State Air Pollution Control Board during its regular meeting on Dec. 2 adopted low-emission vehicle (LEV) and zero-emission vehicle (ZEV) standards established by California’s Advanced Clean Cars regulation.

Virginia Gov. Ralph Northam signed a bill (HB 1965) in March that directed the board to adopt the regulations.

“Adoption of the Advanced Clean Cars regulation is a historic step in Virginia’s efforts to address air pollution and reduce harmful emissions associated with our transportation network,” said Michael Dowd, director of the Virginia Department of Environmental Quality Air’s Renewable Energy Division.

Under the LEV standard, manufacturers doing business in Virginia must meet California’s exhaust emission standards starting with model year 2025 for passenger cars, light-duty trucks and medium-duty vehicles. The ZEV standard, which is based on a system of compliance credits, requires manufacturers to achieve a certain number of ZEV sales for the same vehicle categories and model years as the LEV standard.

Manufacturers must produce ZEVs and plug-in hybrids that will receive credits based on driving range. Included in the authorizing legislation is a requirement that the board allow manufacturers to establish a Virginia-specific account for ZEV credits that can be traded or sold. The Virginia-specific credits also may be used to meet up to 18% of the manufacturer’s program requirements in any given year.

A proposal by the California Air Resources Board (CARB) would allow manufacturers to transfer their ZEV credits among states as part of the Advanced Clean Cars II regulation under development. Interstate credit transfers would be allowed for model years 2026-2030. (See CARB Plan Would Allow Interstate Transfer of ZEV Credits.)

Speaking at the Dec. 2 meeting, Walton Shepherd, Virginia policy director with National Resources Defense Council, said the board’s vote would be “one of the most beneficial clean air actions” it has ever taken.

The benefits would not end with clean air, he said, adding that transportation fueling dollars will stay in state when consumers charge their EVs with Virginia-produced electricity.

“Around 2025 is when your average electric vehicle will cost the same as an internal combustion car,” he said. “In 2025 and beyond … it would literally be irrational to buy a gas-powered car because you will lose money every time you fuel your car with gas.”

Virginia joins 15 other states that have already adopted the Advanced Clean Cars regulation, according to CARB. The standards in Virginia will go into effect in January 2024.

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MISO Sounds Alarm on Potential Winter Fuel Scarcity

ORLANDO, Fla. — MISO is raising the alarm over scarce fuel and increased forced outages should a severe arctic blast descend on the footprint.

Speaking Tuesday before the Markets Committee of the MISO Board of Directors, Renuka Chatterjee, executive director of system operations, said the grid operator expects anywhere from 36 to 50 GW in generation outages under an extreme winter scenario. MISO expects a 101-GW system peak this January and 108 GW in available capacity to meet the demand. (See MISO Warns of January Emergency Procedures.)

“Risk has increased beyond frozen coal piles this winter,” Chatterjee said, noting that coal suppliers have downsized their inventory. She also said gas storage is at relatively low levels nationwide.

Staff said up to 20 GW in natural gas generation is at risk because of non-firm transport arrangements, and another 11 GW of coal generation could become unavailable because generation owners haven’t fully contracted their winter supply. Natural gas prices in MISO have essentially doubled since late 2020, while coal costs have risen about 15%.

Chatterjee also said available wind generation could swing from 4 GW to 15 GW this winter.

“In light of the fuel risks this winter, MISO is asking members to help provide more visibility into their situation,” Chatterjee said.

The RTO has asked members with coal or gas availability concerns to reach out to both the grid operator and its Independent Market Monitor. It is also asking affected members to complete a weekly coal or fuel oil generator survey so staff can “assess and manage risk.”

“I urge continued vigilance on this. The reports on fuel security are concerning,” MISO Director Nancy Lange said.

MISO Executive Director of Market Operations Shawn McFarlane said in November that “arctic weather of some length” would carry system reliability risks.

Staff has concluded they will be forced to rely on non-firm imports from its neighbors to avoid load shed should punishing winter weather materialize.

“If PJM has a bad day the same day we’re having a bad day, the country will have a bad day,” MISO President Clair Moeller explained to board members. He said that under the normal nature of cold fronts, staff can rely on PJM imports because both systems don’t experience weather hardships simultaneously.

The Monitor’s David Patton said as MISO moves into wintertime, coal generation serves as an important backstop when gas pipelines fail. He said coal supply chain risks are concerning. He also predicted the RTO won’t see $2/MMBtu natural gas prices for quite some time.

“I was happy to see MISO identified this as a new risk because that is certainly a risk,” Patton said.

But Patton again lambasted “near-zero” per megawatt-day capacity prices in the 2021-22 planning year. (See MISO Capacity Auction Values South Capacity at a Penny.)

“If reliability is in fact an imperative, this market is not helping us,” he told board members.

Chatterjee said it’s becoming increasingly difficult to operate the system with intermittent resources growing share of the fuel mix while the system is beleaguered with extreme weather events.

MISO set a new all-time wind output record of 22 GW on Nov. 12. That accounted for 29% of the RTO’s demand.

Patton also said MISO’s congestion costs in 2021 are approaching $2 billion, an unprecedented amount. Chatterjee said that can be chalked up to February’s winter storm and this year’s higher natural gas prices.

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SPP Board Reviews 2021 Performance Metrics

SPP’s Board of Directors gathered virtually Monday to review performance metrics and stakeholder feedback for 2021 in what they hope will be their last remote meeting after almost two years of virtual gatherings.

“Clearly, everyone’s ready for in-person meetings,” CEO Barbara Sugg said.

She said not every board member filled out their surveys this year, a contrast to the normal 100% response rate. Including the Members Committee (MC), which advises the board, the rate was down from 81% to 75%.

“[Board Chair] Larry [Altenbaumer] and I will have to figure out a way to get people excited about filling this out next year,” she said.

The average board and members’ scores increased in 13 of 19 categories, dropping in only five. The average rate for meeting effectiveness fell from 4.50 to 4.43 (on a five-point scale) from 2020.

COO Lanny Nickell said SPP’s annual organizational effectiveness survey of its 21 stakeholder groups saw its lowest scores for member preparation and engagement during meetings. Members rated the groups’ overall effectiveness at 4.40 on a five-point scale, down slightly from 4.42 in 2020.

Larry-Altenbaumer-Barbara-Sugg-(SPP)-Content.jpgBoard Chair Larry Altenbaumer and CEO Barbara Sugg adjourn the SPP board’s final meeting of the year. | SPP

 

The response rate to the RTO’s annual stakeholder satisfaction survey was up slightly from 2020 to 13.8%, but still down from the high-water mark of 21.2% set in 2017. The survey was distributed to 1,672 organizational group members, market participants and other individuals who interacted with SPP during the previous 12 months through meetings, training, customer relations interactions or other exchanges.

Respondents indicated a slightly lower overall satisfaction with SPP’s service in 2021, with scores falling from 3.87 in 2020 to 3.61, similar to ratings in 2018 and 2019. The average scores evaluating staff’s performance in three specific areas also declined by an average of 6.3% year-over-year, falling in line with 2018 and 2019.

David Osburn, Oklahoma Municipal Power Authority’s general manager, suggested stakeholders might be experiencing fatigue from the number of high-level initiatives SPP has taken on during the last two years.

“The last two years have been incredibly fatiguing, and not just because we’re dealing with this remote world,” Sugg said. “We’ve just had some really big things that have taken so much time. I hope that doesn’t lead to us providing less quality service … we have to start delivering on all those things we’ve decided to take on.”

“I think the organization, the staff, board and stakeholders did just a fantastic job navigating through these past two years,” Altenbaumer said. “I know we’re all anxious to get into 2022, when the world will start moving in something that feels more normal.”

SPP plans to resume its in-person meetings in January after two years of COVID-19 pandemic restrictions. The board, MC and Regional State Committee will meet Jan. 24-25 in Little Rock, Ark., while the Markets and Operations Policy Committee and Strategic Planning Committee (SPC) will meet Jan. 10-12 in Oklahoma City.

New Groups, Stakeholder Reps OK’d

The board also unanimously approved two new stakeholder groups, chairpersons for several working groups and advisory groups, and two representatives for empty seats on the SPC, all brought forward by the Corporate Governance Committee.

The Emergency Communications User Forum’s creation was one of several recommendations made by SPP’s comprehensive report on February’s winter storm. The group will be responsible for providing feedback to identify, improve and prioritize SPP stakeholders’ energy emergency communications needs.

SPP staff proposed forming the Future Grid Strategy Advisory Group to “proactively address, drive and shape” some of the grid’s anticipated changes and to prepare for other changes.

Named as stakeholder group chairs were:

  • Allen Klassen, Evergy, Operating Reliability Working Group;
  • Robert Pick, Nebraska Public Power District, Regional Tariff Working Group;
  • Thomas Maldonado, Xcel Energy, Reliability Compliance Advisory Group;
  • Jim Jacoby, American Electric Power, Seams Advisory Group;
  • Phil Clark, Arkansas Electric Cooperative Corporation, Security Advisory Group;
  • Natasha Henderson, Golden Spread Electric Cooperative, Supply Adequacy Working Group; and
  • Derek Brown, Evergy, Transmission Working Group.

Usha Turner, Oklahoma Gas & Electric, and Steve Sanders, Western Area Power Administration, will join the SPC. Turner’s term ends in December 2023 and Sanders’ in December 2024.

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MISO Raises ORDC’s Lowest Level to $1,100/MWh

FERC on Monday approved MISO’s request to raise its four-step operating reserve demand curve’s (ORDC) lowest level from $200/MWh to $1,100/MWh, agreeing with the RTO that the final step is probably priced too low to entice generating resources (ER21-2797).

MISO’s ORDC is based on a $3,500/MWh value of lost load (VoLL) and begins at $3,300/MWh. It drops to $2,100/MWh for much of the curve when the RTO clears 8% of its requirement level. At 89%, the level falls to $1,100/MWh, remaining there until 96% or more of the requirement is cleared and the curve flattens at $200/MWh.

The fourth step will be raised to equal $1,100/MWh, better reflecting the cost of emergency actions necessary to meet reserve shortages.

In its filing, the RTO said the $200/MWh step undervalued reserve shortages and led to “inefficiently low prices that did not send signals to resources that may be expected to respond in future shortage conditions.”

FERC agreed that the $200/MWh price might not send appropriate signals to resources “and could lead to procurement of reserves below system need.”

MISO staffers have said the $200/MWh value was set before the grid operator had established emergency pricing. They have long said the starting point should be raised to reflect the value of energy in scarcity conditions.

The change should help raise the grid operator’s emergency prices, which MISO’s Independent Market Monitor has long criticized as too low. The IMM has called for an operating reserve demand curve that eradicates the step-based pricing in favor of gently sloped descent from a much higher starting point of about $10,000/MWh.

MISO has said it doesn’t plan to address raising its VoLL value until 2023 or later.