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November 7, 2024

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EPA Doubles IIJA Funding for Electric School Buses

EPA announced last week that it is nearly doubling the funds available from the Infrastructure Investment and Jobs Act for the Clean School Bus Program in 2022 to $965 million.

A first round of $500 million in May drew more than 2,000 applications from across the country. The agency said it “will move swiftly to review applications submitted and expects to issue a robust slate of awards” in the coming weeks.

The IIJA authorized $5 billion for the program over a five-year period, with the money going to provide rebates to school districts buying no- or low-carbon vehicles to replace their diesel buses. Funding for the program in 2023 will be $1 billion, EPA said.

“We’re working across all 50 states to accelerate the transition to a future where clean, zero-emissions school buses are the American standard,” EPA Administrator Michael Regan said. “America’s school districts delivered this message loud and clear: We must replace older, dirty diesel school buses.

“Together, we can reduce climate pollution, improve air quality, and reduce the risk of health impacts like asthma for as many as 25 million children who ride the bus every day,” Regan said, citing figures from the American School Bus Council.

The 2022 program guidelines prioritize applications from school districts in low-income, remote rural and tribal areas, and EPA said that “the vast majority of applicants met the priority definition … resulting in access to more funds for buses and electric vehicle infrastructure for schools in areas that need them the most.”

More than 90% of the applications were for “zero-emission electric buses,” EPA reported. Another 9% were for propane-fueled vehicles, and 1% were for compressed natural gas vehicles.

Districts chosen for awards will have to first order the buses and other infrastructure, and submit the purchase orders, to receive their rebates, EPA said.

According to a report from the World Resources Institute (WRI), 22 models of electric school buses are now available, and their efficiency and technology continue to improve. “Many manufacturers are on their second or third iteration,” all with ranges of more than 100 miles and some more than 200 miles, the report said.

The estimates on how much electric school buses reduce emissions vary. In Virginia, investor-owned utility Dominion Energy has partnered with school districts to begin transitioning their bus fleets, with 50 electric buses on the road in 15 districts. The utility estimates that each diesel bus replaced with an EV cuts emissions by 54,000 pounds per year.

Looking at lifecycle emissions — which take into account the source of electricity used to charge electric bus batteries — WRI found emissions reductions varied depending on location and the generation mix on the grid. Based on the U.S. average, lifecycle emissions for electric buses are about half those of diesel or propane-powered vehicles, but in New England, for example, the emissions for electric buses are about one third of diesel or propane.

Sen. Tom Carper (D-Del.), who chairs the Senate Environment and Public Works Committee, said, “Given the response to the availability of these [IIJA] dollars, it’s clear more funding is needed … to build on this progress so that more communities can realize the clean air and energy saving benefits of these cleaner vehicles.”

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West Coast Leaders Pledge Closer Cooperation on Climate Measures

Leaders from the three West Coast states and the Canadian province of British Columbia signed an agreement Thursday pledging to cooperate on measures to combat climate change.

Meeting in San Francisco, the signatories included British Columbia Premier John Horgan, along with Gavin Newsom, Kate Brown and Jay Inslee — the governors of California, Oregon and Washington.

The non-binding memorandum of understanding outlines broad thrusts but is light on specific details.

Under the MOU, the four governments agree to invest in regional low-carbon transportation measures, including ensuring the installation of conveniently placed electric vehicle charging stations and hydrogen refueling stations along primary and secondary routes throughout their territories. The agreement stresses the ability for zero-emission vehicles (ZEVs) to travel along the Interstate 5 corridor from Canada to California. It also includes provisions for helping public and private institutions electrify their vehicle fleets and for increasing the use of low-carbon fuels. 

The four governments also said they will coordinate how they establish standards for ZEVs and energy efficiency in buildings and work together to help cultivate markets for energy-efficient building materials.

“We know growing our economy and protecting our planet are not mutually exclusive goals,” Brown said.

The four leaders also pledged to improve forest thinning and anti-wildfire measures. “We have watched. We have smelled. We have suffered through the smoke,” Inslee said.

They also agreed to make climate a consideration in land-use planning and measures affecting the Pacific Ocean.

“In California, we punch above our weight when it comes to climate action, but our actions can only do so much without the rest of the world at our side. The Pacific Coast is raising the bar for tackling the climate crisis while also ensuring every community is included in our efforts,” Newsom said.

“Here on the Pacific Coast of North America, we’ve been on the frontlines of the climate crisis — both experiencing its most devastating impacts and leading the world in developing solutions to reduce carbon pollution,” Horgan said.

“We are going to collaborate with any jurisdiction in the world,” Inslee said.

The four Western leaders recently shared a virtual dais at the Cascadia Innovation Corridor conference, where they advocated for increased interstate and international cooperation on climate policy. (See Western Governors Talk Climate Change.)

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DOE Seeks Public Input on Biden Manufacturing Order

The U.S. Department of Energy is seeking input from the public on how to use the authority that President Biden granted it earlier this year to improve power grid reliability.

In a request for information (RFI) issued Monday, DOE cited the president’s June 6 order invoking the Defense Production Act to “accelerate domestic production of” several “key energy technologies”: solar panel components; transformers and electric grid components; heat pumps; insulation; and electrolyzers, fuel cells and platinum group metals.

In an accompanying press release, DOE said that alongside the White House, it has “engaged with stakeholders on maximizing the impact” of the DPA authorities granted it, and claimed that Biden’s “commitment to growing clean energy that’s made in America” has led to billions of dollars in investments in solar, wind and battery storage facilities, along with electric vehicle factories.

Now DOE says the focus is on the risks to national security and defense, as well as grid reliability, posed by the fact that the production processes for many critical power grid components require materials sourced from overseas. The department cited the ongoing disruptions to global supply chains from the COVID-19 pandemic as evidence of the fragility of foreign supply chains, while the Russo-Ukraine War that has raged since February shows “the dangers of our overreliance on foreign sources for grid components and fossil fuels from adversarial nations.”

These crisis situations have arrived at the same time as the worsening impacts of climate change have led to an increasing incidence of hurricanes and wildfires. As a result, utilities have experienced “wait times [of] upwards of two years for grid transformers” that force stakeholders not only to postpone urgent repairs, but also to delay work on existing projects and getting new construction underway. (See Utilities See Challenges, Opportunities in Supply Chain Issues.)

The RFI covers all of the equipment mentioned in Biden’s June order except for heat pumps. DOE mentioned several possible approaches to improve U.S. supply chains such as direct purchases, purchase commitments and financial assistance. The department’s goal is “to understand further how to increase the manufacturing output and the rate of deployment of key clean energy technologies” by soliciting comment on:

  • technology supply chain challenges and opportunities;
  • domestic manufacturing, including small- and medium-scale enterprises;
  • investment in American manufacturing talent; and
  • energy equity, community access and economic benefit.

“The Defense Production Act provides us with a vital tool to make targeted investments in key technology areas that are essential to ensuring power grid reliability and achieving our clean energy future,” Energy Secretary Jennifer Granholm said in the statement. “DOE is eager to continue hearing ideas from industry, labor, environmental, energy justice, and state, local and tribal stakeholders about how we can best use this powerful new authority to support the clean energy workforce and technologies needed to combat climate change.”

Responses to the RFI must be submitted by 5 p.m. ET on Nov. 30.

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BOEM Report Clears Way for 1st California OSW Auctions

A new finding by the U.S. Bureau of Energy Management (BOEM) means California could see its first offshore wind lease auctions by the end of the year.

The agency on Wednesday issued a finding of no significant impacts (FONSI) on marine and human environments from “offshore wind energy leasing activities” in the Morro Bay Wind Energy Area (WEA), located roughly 20 miles off the coast of San Louis Obispo County, about halfway between Los Angeles and San Francisco.

BOEM’s environmental assessment (EA) of the WEA covers only the potential impact of the initial site “characterization” and “assessment” activities performed by offshore developers that are awarded leases for the three parcels within the area. Such activities could include surveys and extraction of core samples or the placement of meteorological buoys, the agency noted. The EA applies to the three parcels; associated rights of way, rights of use and easements; and the issuance of grants for subsea cable corridors and associated collector/converter platforms.

“The completion of our environmental review is an important step forward to advance clean energy development in a responsible manner while promoting economic vitality and well paying union jobs in Central California,” BOEM Director Amanda Lefton said in a statement. “We will continue to work closely with tribes, state and federal partners, and key stakeholders to ensure any future development avoids or minimizes potential impacts to the ocean and other ocean users in the region.”

But the agency pointed out that the FONSI does not apply to “the siting, construction and operation of any commercial wind power facilities,” which would be subject to a different process.

“If BOEM decides to conduct a lease sale in the Morro Bay WEA, the bureau will develop an environmental impact statement (EIS) before approving the construction of any offshore wind energy facility in the Morro Bay WEA,” the agency said in a press release. “That EIS will analyze the specific environmental consequences associated with the project, in consultation with tribes; appropriate federal, state and local agencies; and stakeholders and the public.”

The agency’s finding on Wednesday means that auctions for the three designated lease parcels within the Morro Bay WEA could proceed by the end of this year, in line with a schedule that BOEM offered in May when it announced a proposed sale notice for five lease areas off California, including two parcels in the Humboldt Bay WEA. (See BOEM Issues Proposed Sale Notice for Calif. Offshore Wind Areas.)

The Morro Bay WEA covers 376 square miles and is expected to accommodate up to 3 GW of wind resources.

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SERC Stresses Advantages of Design Basis Threat Process

Travis Moran (SERC) Content.jpgTravis Moran, SERC | SERC

Travis Moran’s pathway into electric reliability was somewhat unusual, SERC Reliability’s senior reliability and security adviser recalled at the regional entity’s Fall Reliability and Security Seminar on Wednesday.

Unlike many people in the room, Moran began his career not as an engineer but in law enforcement, with stints at Interpol, the U.S. State Department, and the Bureau of Alcohol, Tobacco and Firearms.

His jump into electricity came after the attack on Pacific Gas & Electric’s Metcalf substation in California in 2013, when several gunmen opened fire on the facility, severely damaging 17 transformers. (See Substation Saboteurs ‘No Amateurs’.) Hired as an investigator by Dominion resources in 2014, he and his colleagues rapidly realized how little their years of experience had prepared them for the world they were entering.

“They hired [me], a former homicide detective from a big city, and an assistant chief of police,” Moran said. “We knew a lot about … evidence and security, but we didn’t know anything about electricity. So we found out the hard way: we stumbled into retention ponds; we had substation engineers slap our hands; we touched stuff we shouldn’t touch. … We learned the old-fashioned way, and quite frankly there is no other way to learn this industry.”

But Moran’s previous life in law enforcement proved an asset when the Electricity Information Sharing and Analysis Center tapped him to join the Physical Security Advisory Group, which created the Design Basis Threat (DBT) assessment in 2016. The DBT concept, which originated in the nuclear industry, is a tool to identify the intentions and capabilities of potential adversaries and determine appropriate, cost-effective defensive measures.

In his presentation Wednesday, Moran emphasized the advantages of conducting formalized, documented DBT assessments over the more ad-hoc way that many utilities responded after the Metcalf attacks. While these investments were, for the most part, based on legitimate assessments of security needs, in many cases the entities have not made use of them to the extent they might have hoped.

“Billions of dollars were spent on physical protection systems, and when we go out now, a lot of that stuff hasn’t been maintained, a lot of that stuff was unreasonable, some of that stuff may not have been needed,” Moran said. “Obviously some of it was, but … the reason you go through the DBT process is because … it helps you become knowledgeable about how you’re going to protect [yourself]. Number two, it helps save you money about what you do need to protect, what you don’t need to protect, and how to go about it.”

Threats Continue to Mount

The physical threat to the North American power grid has by no means slackened since the Metcalf attacks. As Moran noted, just this year a group of white supremacists pleaded guilty to plotting to destroy transmission substations in hopes of sparking a race war in the U.S. (See FBI: Conspirators Planned Grid Attack to Start Race War.) In such an environment, utility staff developing awareness of the threat landscape can achieve better results the closer their ties to law enforcement at multiple levels.

“I used to always teach my trainees … the only people that know what’s going on in the community really well are your state and local officers. They know the community, they know the informants, they know who the players are; they’re the people that you need to get in touch with,” Moran said. “So if you’re not talking to your local police department … you need to be talking to them because they can inform you.”

Moran noted that for utilities with facilities subject to NERC’s CIP-014-3 reliability standard, which governs physical security, DBT assessments are already a regular part of doing business because requirement R1 of the standard mandates that transmission owners “identify the transmission stations and … substations that if rendered inoperable or damaged could result in instability, uncontrolled separation or cascading.”

He strongly urged that those not covered by the standard make the practice a regular part of their operations anyway. Following a standard procedure will ensure both that utilities are aware of current and emerging threats, and that they have a strong documentation trail to inform all relevant parties in the case of emergency.

“Document, document, document what you did and how you got there,” Moran said. “Don’t be in the position of saying, ‘Well, we checked it, and we didn’t see any threats, or we didn’t see anything that mattered to us.’ Really? Well, when did you do it? What databases did you check? … Process that intelligence, and then you’ve got to produce it and disseminate it.”

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New England’s Gas Industry Frets About Cracks in Electric Side

FOXBOROUGH, Mass. — As New England’s gas and electric providers and regulators prepare for another dicey winter, gas industry representatives threw out solutions ranging from market fixes to upgraded pipeline infrastructure at a day-long gathering last week.

The Northeast Energy and Commerce Association’s Fuels Conference focused heavily on the fuel supply challenges that continue to bedevil the Northeast in winter.

ISO-NE recently said that the Everett LNG facility must be maintained for grid reliability, even past 2024 when its anchor tenant, Mystic Generating Station, is set to retire. (See ISO-NE: Reliability Still Depends on Mass. LNG Import Terminal).

That’s narrow-minded, argued an executive for one of the other LNG import terminals that helps brings gas into New England.

“The solution needs to be a market fix that resolves the mismatch between how LNG is contracted for and how generators are compensated, not another subsidy for a singled-out facility,” said Karen Iampen, vice president at Repsol, which operates the Saint John LNG terminal in New Brunswick, Canada.

She called the previous actions by ISO-NE “Band-Aids” that don’t address the region’s larger issues.

“Removing this obstacle to more long-term contracting is the most economic way to ensure fuel security by bringing in more cargoes that more fully utilize the storage and send-out facilities at the LNG terminals,” Iampen said.

Pipelines Want to Build Out

The other way to get more gas into the region is by land, and pipeline companies think that they’ll have a key role to play in New England even as renewables ramp up.

“Renewable growth requires operational flexibility,” said Jim McCord, account director at Kinder Morgan.

He pointed to California, where natural gas systems have helped back up rapidly growing renewable penetration by increasing or decreasing output when necessary.

“As an industry, natural gas will work hard to play this critical role in ensuring energy reliability,” McCord said.

Nobody is trying to build new pipelines to New England, but the existing ones could use upgrades, said Michael Dirrane, director of marketing for Enbridge.

“I’m advocating for brownfield pipeline projects, where we take out the smaller diameter pipe and replace it with higher diameter pipe, and perhaps add some additional horsepower on the system,” Dirrane said.

Those improvements would have minimal impact on the environment or to landowners, Dirrane said.

“That is the best way to drive down costs in New England.”

Tom Lockett of TransCanada said his company also is eyeing brownfield expansion.

LDCs Worried

Meanwhile, the utilities are increasingly concerned that reliability challenges facing the electric system in New England this winter could threaten the gas side, too.

Elizabeth Arangio 2022-09-29 (RTO Insider LLC) FI.jpgNational Grid Director of Gas Supply Planning Elizabeth Arangio | © RTO Insider LLC

Elizabeth Arangio, director of gas supply planning for National Grid, said that the “dots are connected.”

“We don’t want anything to happen on the electric side,” Arangio said. “Certainly it will impact us.”

“It’s an unfortunate situation. It’s not a good situation,” said John Rudiak, senior director of energy supply for Avangrid (UIL).

He called it a “spillover risk” that in particular could affect low-pressure gas customers.

“There’s a risk that if there were rolling blackouts, when those blackouts are restored, the gas lines could [face] reduced pressure” if not managed correctly, Rudiak said.

Eric Soderman 2022-09-29 (RTO Insider LLC) FI.jpgEversource Director of Gas Supply Eric Soderman | © RTO Insider LLC

Eric Soderman, Eversource’s director of gas supply, echoed that fear.

“While the [local distribution companies] have adequately planned to serve their customers for this winter, as they do each winter, we have concerns that a cascading effect in New England could affect lower pressure areas on the pipeline that are extended laterals or don’t have backfeed areas,” Soderman said.

From the LDCs, the dominant feeling is frustration about how the electric side has been handled.

“The bottom line on this one is I feel comfortable about our companies, in terms of our preparation, in terms of our resources and our infrastructure and our capabilities,” Rudiak said. “But I’m really disappointed in [ISO-NE] not having solved the problems of market design and fuel supply reliability after so long.”

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Virginia Gov. Youngkin Releases 2022 Energy Plan

Virginia Gov. Glenn Youngkin (R) on Monday released an energy plan that focuses on developing still-untested carbon-free resources while calling into question the ability of current renewable technology to make up for lost capacity as the state shifts away from fossil fuels.

In a letter announcing the plan, Youngkin wrote that previous plans for the transition to cleaner energy were too rigid and followed an “either/or” mindset, whereas his plan seeks a “both/and” approach of expanding solar and wind while investing in other emerging technologies.

“In fact, the only way to confidently move towards a reliable, affordable and clean energy future in Virginia is to go all-in on innovation in nuclear, carbon capture and new technology like hydrogen generation, along with building on our leadership in offshore wind and solar,” he wrote.

While the plan lacks the power of law, it seeks to provide a framework for future policymaking through an assessment of the current state of the energy environment and a series of recommendations for each of its guiding principles: affordability, reliability, competition, innovation and environmental stewardship.

Some of the plan’s recommendations direct state agencies to complete studies on potential reforms, such as addressing cost overruns in utility infrastructure projects, although most of the proposals would require action from the General Assembly.
Democrats, who control the state Senate, are likely to oppose Youngkin’s efforts to roll back the previous administration’s policies.

The plan takes an especially strong stance on creating a hub of nuclear development in southwest Virginia, drawing on expertise fostered at the Norfolk Naval Base, where the nation’s fleet of nuclear submarines and carriers are maintained. It calls for a collaboration with government, industry and academic partners to work toward the deployment of a commercial small modular nuclear reactor within the next 10 years.

The “all of the above” approach detailed in the plan also promotes investments in developing carbon capture, utilization and storage technologies to lower the emissions of existing fossil fuel generation and industries, while building new industries in battery production and renewable energy, particularly the $9.8 billion Coastal Virginia Offshore Wind project.

Proven Technology

The plan received support from a broad coalition of business associations and energy companies who said it provides for affordable power while working toward a cleaner environment.

“Affordable, reliable, sustainable and secure energy from a diversity of resources is a necessity for Virginia’s economic competitiveness,” Virginia Manufacturers Association CEO Brett Vassey said. “The VMA is thankful that Gov. Youngkin’s energy plan recognizes that affordability and environmental responsibility are not mutually exclusive public priorities.”

The plan takes aim at actions undertaken during the administration of Youngkin’s Democratic predecessor, Ralph Northam, including passage of the Virginia Clean Economy Act (VCEA) of 2020 and the Clean Cars Virginia bill, which ties the state to California’s requirement that only zero-emission vehicles be sold after 2035, as well as participation in the Regional Greenhouse Gas Initiative.

The governor’s plan says that transitioning all new vehicle sales to EVs would eliminate consumer choice and strain the electric grid, particularly if done while the state is transforming the generation environment.

Kim Jemaine, policy director with Advanced Energy Economy, expressed surprise that Youngkin’s plan called for reauthorizing the VCEA every five years, contending that the law shares many of the same goals as his energy plan and a path toward achieving those goals through technological investments while also expanding proven and developable clean energy.

“Gov. Youngkin’s objectives of reliability, affordability, innovation, competition and environmental stewardship are all achievable within the framework of the VCEA. It’s unfortunate that the 2022 Energy Plan spends so much time disparaging the VCEA when that law offers a clear path to achieving the administration’s purported goals,” Jemaine said in a statement.

Requiring the law to be reauthorized regularly would also make it more difficult for businesses to plan for the future, particularly those which have made clean energy pledges, Jemaine said.

By remaining a party to RGGI and holding onto the clean cars standards, Virginia would also provide for an energy sector that is cost-effective, reliable and focused on environmental stewardship in a manner that aligns with Youngkin’s energy goals, she said.

“RGGI is helping Virginia transition towards a clean grid while strengthening our flood resilience and cutting Virginians’ electric bills with energy efficiency. The Clean Cars standards help ensure Virginia is a leading state in transportation electrification, encouraging innovation, cutting tailpipe emissions, and reducing our reliance on costly, imported oil,” she said.

Jemaine told RTO Insider that she sees some bright spots in the plan, including an emphasis on expanded offshore wind, increased competitive bidding by independent power producers and investments in future technology innovation — though she said that cannot come at the cost of also investing in proven clean energy today.

“What the energy plan does is it really emphasizes emerging technology like nuclear and hydrogen, and that’s fine, because those technologies may have a space in the future … in the meantime we have to invest in technologies that we already know to ensure that the grid is more stable, reliable and cost effective,” she said.

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Duke Energy Estimates Net-zero Push at $145B in Next Decade

Duke Energy this week estimated the cost of its clean energy transition plans at $145 billion over the next decade, $10 billion more than its previous 10-year plan.

The majority of this investment in its seven regulated utilities — $75 billion — is projected to be for grid modernization. The rest would go to battery storage and zero-carbon power generation from solar, wind, hydro, nuclear and small modular nuclear ($40 billion); new natural gas generation and maintenance ($10 billion); natural gas distribution ($10 billion); and other expenses including coal maintenance, coal ash and corporate activities ($10 billion).

Hydrogen-enabled natural gas technology is included in the total, along with smart technology to detect potential problems and self-healing technology that limits the frequency and duration of power outages.

Walton Solar Power Plant (Duke Energy) Alt FI.jpgDuke Energy Kentucky’s Walton Solar Power Plants 1 and 2 in Kentucky came online in 2018. | Duke Energy

 

Duke said the 2023-2032 roadmap will support its efforts to reach more than 50% carbon reduction by 2030, 30 GW of regulated renewable energy by 2035 and net-zero carbon emissions by 2050. Its interim targets are 50% reductions in Scope 2 and Scope 3 upstream/downstream emissions by 2035 and an 80% reduction in Scope 1 emissions by 2040.

Specific 2050 targets include 28 GW of installed energy storage and 40% renewable power generation.

“These critical energy infrastructure investments will also provide substantial economic benefits, including job creation and tax revenue for essential governmental services in our regions,” Duke CEO Lynn Good said in a statement accompanying the economic and climate reports released Tuesday.

The economic report by consulting firm EY placed the direct and indirect benefit of Duke’s plans at 20,000-plus jobs created and $250 billion in output during the 10-year period.

To limit the impact of all this spending on its 8.2 million electric and 1.6 million gas customers, Duke said it is investing to lower the cost and volatility of fuel; leveraging clean energy tax credits; transitioning to renewables that generate without fuel costs; and making changes to cut the cost of storm restoration. The recently passed Inflation Reduction Act will further reduce customer costs, it said.

Factors that will control the pace of investment include scalable supply chains; grid planning; and federal, state and local approvals.

Duette Solar Power Plant (Duke Energy) Alt FI.jpgDuke Energy Florida’s Duette Solar Power Plant came online in 2021. | Duke Energy

 

Potential problem points include shortages of skilled labor or materials; slow evolution of numerous technologies that do not currently exist in scalable form; an insufficient or overly expensive supply of renewable natural gas; and site acquisition. For example, Duke’s proposed Carolinas Carbon Plan calls for 12 GW of new solar installed in the next 13 years, which by a conservative estimate of at least 8 acres/MW would entail a 96,000-acre footprint.

Finally, state regulators must allow Duke to recover the costs of its investments from ratepayers, the company said.

Through 2021, Duke had reduced the carbon emissions of its generating fleet 44% from 2005 levels, in part through what it said is the largest planned coal fleet retirement in the industry. Duke expects coal to account for only 5% of its generation mix by 2030 and be eliminated altogether by 2035.

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Western Markets Exploratory Group Shares Views

TEMPE, Ariz. — The Western Markets Exploratory Group made a rare public presentation of its work assessing the pros and cons of organized markets in the West, including an RTO, at the Sept. 29 meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body (CREPC-WIRAB).

The group’s members include a loose coalition of some of the West’s largest utilities, but its work has taken place largely in private since it began meeting in summer 2021.

Arizona Corporation Commission Chair Lea Marquez Peterson introduced and moderated the WMEG panel, consisting of Arizona Public Service (NYSE:PNW) CEO Jeff Guldner, NV Energy (NYSE:BRK.A) CEO Doug Cannon and Bonneville Power Administration CEO John Hairston.

“There are many options for pursuing greater collaboration among utilities in the West” to promote reliability and economic benefits, Marquez Peterson said. “One option that’s been highly discussed is the creation of an RTO. I believe the regulators in this room would like to see an RTO, and certainly a great number of stakeholders would like to see that also.”

Questions remain, however, about whether an RTO “will really provide more benefits than less expensive options,” she said. In the meantime, “we should continue to investigate all opportunities for furthering collaboration between utilities and for strengthening our relationships with regulators in other states, like the approach with the Western Markets Exploratory Group.”

WMEG is weighing options that include: CAISO’s proposed extended day-ahead market (EDAM) for its real-time Western Energy Imbalance Market (WEIM); the potential for CAISO to expand beyond California and become an RTO; SPP’s Markets+ program, a bundle of services that stops short of a full RTO; SPP’s plans for an RTO West, an offshoot of its Eastern Interconnection RTO; and the Western Power Pool’s Western Resource Adequacy Program (WRAP), a West-wide effort to ensure utilities have sufficient capacity to meet peak demand. (See CREPC-WIRAB Weighs Western Transmission, Markets.)

Guldner said WMEG members are interested in greater market efficiencies such as through CAISO’s EDAM. Large Colorado and Nevada utilities are under legislative mandates to join an RTO by 2030, he noted. And WMEG has talked with CAISO about the possibility of an RTO, but CAISO’s one-state governance remains a sticking point, he said.

“We began talking with the California Independent System Operator about … if we go to one large market, then we really need to address governance, because everybody was concerned about a California-dominated governance in a West-wide market,” Guldner said.

“There are other options, and I just want to make one point really clear. None of the options would involve the rest of the West not trading with California,” he said. “The question is just how that trading will occur. California has a massive load sink [that’s vital] for our generation to be optimized. It’s just whether that would be done directly as part of the California market or whether it would be done through seams agreements between two RTOs.”

SPP’s planned RTO West is another possibility, Guldner said.

WMEG was established to develop a “roadmap” for the West “up to and including a full RTO formation,” with cost-benefit analyses for various options, he said. It now involves 25 entities, including Idaho Power, the Los Angeles Department of Water and Power, Public Service Company of New Mexico and the Western Area Power Administration. (See Western Utilities to Explore Market Options.)

BPA Viewpoint

BPA joined WMEG this year to get a broader understanding of “what’s happening in [Western] markets,” Hairston said. “We come to this discussion with about three-quarters of the high-voltage transmission in the Northwest, so quite honestly, any discussion about an RTO [or other organized markets in the West] has to involve Bonneville Power.

“We understand that, and we accept that responsibility,” he said. “The thing is that when I come to these conversations, I’m bringing 140 some-odd customers with me, and so if you can imagine trying to pull all those different perspectives together and get us on one path, that’s also challenging.”

BPA began participating in the WEIM earlier this year and is seeing positive results from its first foray into an organized market, he said.

Now it is paying close attention to what’s happening with the WRAP as it gets closer to starting operations, Hairston said. The program has signed up 26 participants, representing much of the Western Interconnection, notably absent CAISO. (See Western Power Pool Board Approves WRAP Tariff.)

“The next step for us really is looking at how we develop a resource adequacy program for the West,” Hairston said. “And I think what’s happening in the Western Power Pool [with WRAP] is exactly what we need. We’re seeing the development of an independent governance structure, which I think could be the template for any other types of governance structures that we need as we entertain other markets. So, I’m really encouraged about what I’m seeing.

“Where else have you seen all of these utilities across the Northwest come together in this transparent nature to set up a program that’s going to benefit all of us?” he said. “I think that in itself is an important step. I’m really glad to see that collaboration, and I think it is going to yield some positive results.”

BPA next will join a day-ahead market, whether it is CAISO’s EDAM or SPP’s Markets+, and that could determine its eventual RTO membership, he said.

“Once you get into that extended day-ahead and you make those additional investments and that structure is developed, it’s going to be really challenging to move after that,” Hairston said. “And so, we have to get this next step right because that next step, I think, is really the foundational piece for an RTO.”

“I think at the end of this thing there will be a Western RTO, [but] how [that looks] still remains to be seen,” he said. “Is it one? Is it two? Those things have to be worked out, and that’s going to have a lot to do with the qualitative piece: governance structures; how comfortable entities are in the development, whether it’s through CAISO or SPP. You have to be comfortable with the governance structure you have and how you participate.”

The other piece is quantitative, he said.

“There’s a lot of discussion about the efficiencies gained under one Western RTO as opposed to maybe having several different [organized markets], but from my perspective, we really have to think about what is gained through some incremental efficiencies if the governance structure isn’t what you want,” Hairston said.

“So those are the types of questions we’re trying to tackle, and I think WMEG allows us to work with a number of important utilities, understanding their perspective on the issues and making sure that we’re factoring in all of the considerations as we make decisions and work transparently with our customers in making that decision,” he said.

NV Energy Comments

Nevada’s largest utility, NV Energy, was an early participant in the Western Energy Imbalance Market and has had a positive experience, CEO Cannon said.

The market has produced more than $2 billion in benefits for its participants since it started in 2014.

“Now, as we step forward into what’s next in the state of Nevada … our thinking on market development [is motivated by] … what option we believe is going to be best for Nevada,” Cannon said.

The state has plenty of solar power, like its neighbor California, as well as similar summer peaks, he said. Partnering with California won’t be enough to deliver the diversity of resources — including hydropower from the Pacific Northwest and wind from Wyoming and Idaho — that Nevada needs to decarbonize its energy supply by 2050, as state law requires, he said.

Keeping ratepayer costs down while building infrastructure is another important consideration and will require market efficiencies to drive down energy prices, he said — a point also made by APS’ Guldner. And NV Energy is working under a state mandate to join an RTO by 2030, he said. All are factors the company has to consider when deciding what markets to be part of going forward, he said.

“That’s really what prompted us to look at an organization like WMEG,” Cannon said. “Now we’re up to 25 participants. We have 95 GW of peak load represented in that organization. We have geographic diversity. We have resource diversity. We have time diversity, so it starts to check a lot of those boxes that I talked about before,” he said. “And so, I think it is a very useful organization to help us do some assessment … to understand what is ultimately the best outcome for investors.”

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MISO, PJM Down to 2 Possible TMEPs

MISO and PJM halved their shortlist of potential smaller interregional transmission projects down to two but warned that even those project benefits might be too small to proceed.

The RTOs staffs presented the two contenders Monday during MISO-PJM Interregional Planning Stakeholder Advisory Committee (IPSAC). The potential targeted market efficiency projects (TMEPs) are line work on the Powerton-Towerline 138-kV flowgate in central Illinois and a potential fix for the congested Chicago-Praxair 138-kV flowgate near the Chicago area. (See MISO, PJM Consider 4 Small Interregional Projects.)

The grid operators studied 23 flowgates accounting for $328 million of congestion costs during 2020-21 in this year’s TMEP process.

PJM’s Nick Dumitriu said analysis is still underway and said the two remaining projects won’t necessarily be eliminated. He said the RTOs are still comparing anticipated project costs against the first four years of estimated project benefits.

“It’s premature to say there won’t be a TMEP,” he said, predicting that “at least” one project could still be recommended to the RTOs’ respective boards of directors by the end of the year.

Stakeholders have asked the grid operators to consider raising the $20 million TMEP cost threshold given continued inflation and supply chain issues.

TMEP projects must cost less than $20 million, completely cover installed capital cost within four years of service, and be in service by the third summer peak after their approval. The projects are assessed using a shorter time horizon than interregional market efficiency projects.

MISO and PJM have approved three small TMEP portfolios since 2017 and one larger interregional market efficiency project in 2020.

This summer, WEC Energy Group’s Chris Plante asked the grid operators to consider creating a joint targeted interconnection queue study similar to that undertaken by MISO and SPP. That work has resulted in identifying about $1 billion of projects on their seams. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects.)

“We are very encouraged by the progress with SPP and would like to see a similar initiative with PJM,” Plante said.