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November 8, 2024

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Texas PUC Chair Lake: ‘The Lights Will Stay On’

During a Wednesday morning press conference designed for ERCOT’s and the Texas Public Utility Commission’s leaders to discuss the changes made to avoid a repeat this winter of February’s near-collapse and dayslong outages following a winter storm, PUC Chair Peter Lake boldly proclaimed, “The lights will stay on.”

Lake based his assertion on new weatherization rules for generation and natural gas facilities that went into effect Dec. 1; increased penalties for violations of those rules; and improved coordination between the electric and gas industries to prevent the loss of gas supplies that has been identified as the leading cause of the generation outages during the storm.

“No other power grid has made as many remarkable changes and in such an incredibly short amount of time as we have, and we will continue to improve our grid and the market,” he said.

The remarks echoed those of Texas Gov. Greg Abbott, who has been guaranteeing since November that the ERCOT grid will remain upright this winter. Abbott, who is fighting off several challengers on his Republican side of the aisle, has pointed to the 14 GW of installed capacity the grid operator has added during 2021. All but 1 GW of that capacity are wind, solar or battery storage.

Pressed by a local reporter that a recent ERCOT report — likely November’s seasonal assessment of resource adequacy (SARA) that included risk scenarios — went against his statement, Lake said the SARA “is a scenario analysis that evaluates a wide range of possibilities.” (See Twitter Blows up over ERCOT Communications.)

“It does not incorporate all of the extraordinary measures I’ve outlined today. It’s a scenario analysis; … it’s not a promise of an outcome,” he said. “When we look at all of the efforts we’ve made, the assets we have in ERCOT now … when we look at the realities on the ground in front of us, yes, we can say the lights are going to stay on.”

Interim ERCOT CEO Brad Jones said the grid operator has received attestations of winter readiness, signed by entities’ CEOs, for 97% of the more than 850 registered generation resources by a Dec. 1 deadline. Aided by two vendors, the grid operator’s new Planning and Weatherization Department has begun its inspections of those facilities.

Jones said staff have visited 55 generation units so far and plan to inspect more than 300 before the year is up. Those units accounted for 85% of the lost megawatts during the winter storm.

“We’ve had a good experience so far,” he said. “There’s been a lot of cooperation at each of the generation companies. There’ve been no red flags.”

Some companies have asked for good-cause exceptions. ERCOT will file a report with the PUC on Friday listing those companies.

PUC Docks 8 Generators

Following the press conference, PUC staff said they had filed violation reports against eight generation companies for failing to provide winter readiness reports by the Dec. 1 deadline, recommending $7.68 million in administrative fees.

The Division of Compliance and Enforcement identified 13 separate resources owned by the companies representing 801 MW of capacity. That amounts to less than 1% of Texas’ total installed capacity of 120 GW.

“Our commissioners have been abundantly clear that they expect generation entities to get ready for this winter,” PUC Executive Director Thomas Gleeson said. “The [PUC] cannot tolerate the failure of these companies to even file their readiness reports.”

Addressing the Texas Reliability Entity’s board meeting Wednesday, Commissioner Jimmy Glotfelty said, “Hopefully, this sends the signal that we are dead serious [that generators] have to winterize their facilities so that what happened in February never happens again.”

Shell Oil (NYSE:RDS.A) took the biggest hit. It was assessed $2.375 million for failing to file statements for four generating resources. Enforcement staff also recommended the penalty be increased $50,000 per day for each resource and an additional $25,000 for each day Shell remains in violation of the winter readiness rule after Wednesday.

Bull Creek Wind and OCI Alamo were each fined $1.1 million for not filing forms for two resources, with a recommended increase of $50,000 per resource for each day they remain in violation. The other companies and their recommended fees, which include a potential $50,000/day increase for remaining in violation, are:

The generators have 20 days to respond to the notices and can request a hearing.

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Princeton Study Examines 24/7 CFE Procurement

Corporate and industrial energy users in California and PJM that try to cut carbon emissions by using a 100% annual matching renewable energy strategy could reduce emissions much more by opting instead to procure carbon-free electricity (CFE) to match their hour-by-hour demand, according to a new report by Princeton University.

The study, released Nov. 19, used mathematical modeling methods to look at the impact of procuring CFE to match hourly demand. In California and PJM, 24/7 CFE would enable C&I energy users to cut emissions by considerably more than if they had used an annual matching strategy, according to the study by four researchers at the university’s Andlinger Center for Energy and the Environment.

The report, which describes itself as the “first analysis of the electricity system-level impacts of 24/7 carbon-free energy procurement,” addresses one of the failings of the 100% annual matching strategy that have emerged since its adoption in recent years by some high-profile corporate names seeking to eradicate carbon emissions. The most notable was Google (NASDAQ:GOOGL), which sponsored the study.

In a 100% annual matching strategy, the user buys clean energy equal to its entire annual energy use. But despite the name, the strategy mostly does not yield zero carbon emissions because the user invariably turns to fossil fuel-generated power to meet their needs in those times clean energy sources are not functioning, such as when the wind isn’t blowing or the sun shining. The use of fossil-generated electricity reduces the user’s clean energy consumption and increases carbon.

“So, while you might buy enough megawatt-hours of clean energy to match your total consumption, there’s a mismatch between when those megawatt-hours are produced,” said Jesse Jenkins, an assistant professor of mechanical and aerospace engineering and one of the four researchers that produced the study.

In a 24/7 CFE strategy, the user purchases electricity to match its energy use profile hour by hour, sourcing energy from carbon-free sources such as nuclear or thermal energy when there is no solar or wind energy available.

“Clean firm technologies are technologies that are available any time of the year, for as long as you need them,” Jenkins said at a Nov. 19 webinar on the report. As a result, he said, they have “the potential to enable much deeper reductions in CO2 emissions from electricity consumption.”

Emissions Reduction, Cost Increases

The Princeton report estimates that an annual matching strategy in California would result in CFE making up only 75% of electricity consumed; in PJM, it would only be 62%.

In contrast, a 24/7 CFE procurement strategy enables C&I users to “completely eliminate emissions,” the report said. The elimination is because of a “better alignment between electricity consumption and generation, which reduces periods of reliance on emitting grid-supplied electricity,” the study concludes.

However, the 24/7 strategy pushes up costs for energy users, the report adds. C&I energy users in California would pay 64% more in energy costs than with an annual strategy, the report said, while PJM consumers would pay 139% more.

The added cost of using 24/7 CFE would shrink in the future if some of the current technologies under development, such as geothermal and hydrogen-fueled generators, become viable, according to the report. And costs would also drop if the user was willing to accept something less than zero-emission energy; for example, 98% clean energy, the report said.

Corporate Zero-emissions Efforts

The 24/7 CFE strategy has emerged as more C&I energy users have started buying renewable energy to match their annual load. One early adopter, Google, has purchased renewable energy equal to its total consumption every year since 2017. But the company acknowledges that it is still a long way from its 2030 goal of using CFE in all locations and all hours, and the impact of the annual matching strategy was limited.

“When we surveyed our operations and our footprint, what we saw is that while we had put a lot of new renewable energy on the grid, we hadn’t taken off a lot of the dirty energy that was there,” Caroline Golin, global head of energy and climate policy at Google, told the Princeton webinar.

Google is among the more than 40 signatories to the 24/7 Carbon-free Energy Compact launched in September, one of several Energy Compacts coordinated in part by the U.N. Others include Orsted; AES; the city of Des Moines, Iowa; the city of Ithica, N.Y.; the government of Iceland; and the Nuclear Energy Institute. Microsoft and the U.S. government also are working on 24/7 CFE strategies, according to the Princeton report.

Under 24/7 CFE procurement, non-fossil sources of fuel are purchased within the same grid region, according to the report. The alternative energy sources cited by the report include conventional and advanced geothermal facilities, which tap into the heat deep below Earth’s surface, and nuclear energy. Others cited in the study include natural gas power plants that use carbon capture and storage technology and gas plants that use zero-carbon fuels. (See How Geothermal Can Support 24-7 Carbon-free Targets.)

Google and other corporate buyers say that greater use of storage will also be key to providing energy in those periods when wind and solar energy can’t. (See Storage the ‘Linchpin’ to 24/7 Carbon-free Power, Corporate Buyers Say.)

The Princeton study argues that a wide, speedy embrace of 24/7 CFE procurement would help advance development of storage technology and accelerate its uptake. A similar effect helped advance wind and solar technology as corporations embraced 100% annual renewable procurement, the report argues.

Retiring Fossil Fuel Plants

The amount that emissions can be reduced through the use of 24/7 CFE depends on two factors, according to the report. One is the volume of clean energy procured, because higher volumes of procurement drive producers to generate more clean energy. The other is timing, or the amount that non-wind and solar clean energy generators adjust the periods in which they produce energy to match those periods when solar and wind production is at its lowest, the report says.

A key reason that the 24/7 CFE strategy is less effective in PJM is that California has a larger share of existing CFE (64%) than PJM, which has just 22%, the report says. The 24/7 CFE strategy also has the effect of hastening the retirement of natural gas plants at a greater pace than would happen under the annual matching strategy as energy users turn to more sustainable methods, according to the report.

The Princeton researchers calculated that if 10% of the C&I energy users in California adopted 24/7 CFE, the shift would reduce gas generating capacity by more than 1.9 GW. That is more than four times as much as would be retired if the users adopted an annual strategy, the report says.

Likewise, the adoption of a 24/7 strategy by 10% of C&I users in PJM would retire more than 6.2 GW, 1.5 times as much as would be retired under annual matching, the report says.

Armond Cohen, executive director of advocacy group Clean Air Task Force, said the study raises an important question for corporations, because the “corporate 100% renewable goal was being interpreted as the complete solution set and a model” by some companies.

Speaking during the Princeton webinar outlining the report, Cohen said it is “important to kind of push the conversation a little farther, and align the corporate demonstration goals with the analysis suggesting that you need a full suite of technologies to address decarbonizing the grid because of the seasonal variation in wind and solar.”

The higher cost of 24/7 CFE “reflect reality,” he said.

“Commodity wind and solar is cheap. It gets you a certain part of the way. But we also have to recognize that full decarbonization is going to require some of these higher capex dispatchable technologies,” he said.

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Wash. Policy Makers Move to Address Expected Drought

In its upcoming session, Washington’s legislature will likely set up millions in funding to deal with a probable drought in 2022.

Two similar bills are in the works to accomplish this, the Washington Joint Legislative Committee on Water Supply During Drought learned last week. 

Gov. Jay Inslee’s office is working on one such a bill that would set aside $3 million to deal with any 2022 drought problems, a committee staff member said. Meanwhile, committee chair Sen. Judy Warnick (R) is putting together a bill that would provide $5 million. Warnick speculated that the two efforts would end up cooperating.

In July, Inslee declared emergency drought conditions for roughly two-thirds of the state, which triggered government actions to deal with the lack of water. The measures include moving water withdrawal allowances from one area to another for the duration of a declared drought, finding other emergency water supplies and dealing with situations when water has become scarce enough to hamper the passage of salmon up and down streams.

“When we left the session in April, who knew we were going to have a drought?” Warnick said. 

Inslee blames the drought on climate change. The joint committee only meets during years in which a drought is declared by the state government. State officials believe a 2022 drought is inevitable.

The two bills being written will address how to take drought countermeasures more quickly. “To move quickly is of the utmost importance,” committee member Rep. Tom Dent (R) said.

The bills will also try to prevent emergency withdrawals from exceeding existing water rights. And Warnick said funding sources need to be identified for expanded drought-related relief.

“We need to increase certainty around funding,” said Jeff Marti, the drought coordinator for the Washington Department of Ecology.

Other potential planks include authorizing the Ecology Department to allocate emergency funds as soon as the governor declares a drought and routinely setting aside money per budget biennium to deal with future droughts.  

A major reason that state officials expect a drought to reemerge in 2022 is that this year’s drought was so severe that Washington would require 150% of its regular rainfall through next spring just to recover the lost water in the agricultural breadbasket of the Columbia River Basin.

“That’s not likely to happen,” state climatologist Nick Bond said.

At a Sept. 29 committee meeting, the legislators were briefed on how the drought has cut back on Washington’s agricultural output. (See Crops, Wildlife Suffering Under Wash. Drought.)

“This was a horrible year for wheat,” said Michelle Hennings, executive director of the Washington Association of Wheat Growers. “The harvest this year was 46% of 2020’s wheat harvest, and that was the state’s lowest wheat harvest since 1964. “

“We had everything from complete crop failures to low [numbers of] bushels [per acre],” Hennings said.

The state’s cherry harvest dropped 20% from 2020. Cherries are a major Washington export to Pacific Rim nations.

The drought’s impacts on potatoes differed throughout the state. There was no impact in the Columbia River Basin south of Grand Coulee Dam. However, southeast of Grand Coulee, the aquifer faces future shortfall. 

Potatoes are heat sensitive, said Chris Voigt, executive director of the Washington State Potato Commission. Potatoes grow best in 75 to 80 degrees F, but they stop growing in the 90-95 degree range. That’s when they become misshapen and more susceptible to diseases and insects. All this translates to smaller yields and possibly more sugar in the potatoes, which produces more browning in French fries than restaurants want. 

Meanwhile, the northwestern corner of Washington produces 85% of the nation’s red raspberries. This year’s heat cut the harvest by 30% below normal.

“Is this a once-in-a-century event or a sign of what’s to come? We don’t know that,” said Henry Bierlink, executive director of the Washington Red Raspberry Commission.

“If we lose them, the country will wonder that Washington did to lose the raspberry growers,” Rep. Mike Chapman (D) said.

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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.