NERC and the regional entities continued to see significant cost savings because of the COVID-19 pandemic last year, according to the ERO Enterprise’s yearly budget true-up report filed with FERC last week (RR22-3).
The commission requires NERC to report the ERO’s cost-to-budget comparison every year, along with audited financial statements for itself and each RE, giving the reasons for significant differences between the planned and actual figures. The filing must also include a justification for any use of cash reserves and explanation for why their use constitutes “unforeseen events” and not “a means to fund expected projects outside of the budget approval process.”
According to last week’s filing, NERC and every RE besides the Texas Reliability Entity spent less than they expected in 2021. NERC’s savings were the largest at more than $2.5 million, though its $80.3 million spending (actual) was also much bigger than any RE. Revenue was higher than planned for most entities, though Texas RE, SERC Reliability and the Northeast Power Coordinating Council reported their actual funding was lower than they had projected.
While NERC and the REs had factored some continued cost savings from the pandemic into their 2021 budgets, the ongoing shutdown of almost all business travel and cautious return-to-office policies across the ERO Enterprise meant entities spent even less than expected. (See NERC Aims for Cost Control in 2021 Budget.) NERC’s meetings and travel category, for instance, came in $1.9 million underbudget and personnel expenses were underbudget by $150,000, partly from “lower parking and transportation benefits due to the pandemic.”
Other entities told a similar story: The Midwest Reliability Organization spent just $5,904 of its $963,000 meeting and travel budget in 2021, and ReliabilityFirst similarly saved over 92% of its $980,000 budget for the same line item. Only WECC saw a savings of less than 90%, spending $58,097 of its $378,000 meetings and travel budget in 2021.
Some entities saved money last year by doing work inhouse that they had planned to outsource to consultants or contractors; NPCC, for example, replaced independent compliance auditors with full-time staff. NERC said that “increased experience and expertise gained by entity staffs, and implementation of process efficiencies, has enabled entity staffs to perform and complete work for which consultants or contractors were previously used.”
Despite the overall savings, however, several entities did report overspending in some categories, particularly personnel. For instance, although NERC’s personnel expenses were underbudget overall, the entity said the savings were largely from the capitalization of certain labor costs associated with various projects; without this capitalization, the category would have been $362,000 overbudget.
SERC and NPCC also reported greater-than-expected spending on salaries; in NPCC’s case, this was part because of the use of inhouse staff rather than consultants for compliance audits. SERC said its expenses were from raising compensation for critical staff because of market demand, along with incentives paid out by its Board of Directors for “exceeding corporate strategic initiatives and key performance indicator goals.”
NERC and the REs are currently accepting comments on their draft 2023 business plans and budgets, which they posted last month. (See NERC Plans Big Budget Hike for 2023.) The total ERO Enterprise budget is set to be $248.9 million, about $22.7 million more than the budget for this year. NERC’s budget hike of $12 million represents the lion’s share of the increase, but all REs are planning to raise their spending as well because of the current high inflation rate in the U.S. and the need for investments in cybersecurity. (See ERO Warns Inflation, Cyber Investments to Keep Boosting Budgets.)
The California Air Resources Board’s draft climate change scoping plan — and its proposal for the state to reach carbon neutrality by 2045 — is facing criticism from many directions.
In a letter submitted to CARB last week, a group of 73 environmental organizations said the plan would fail to meet the state’s greenhouse gas reduction requirements by 2030, as well as the 2045 carbon neutrality target.
Instead, the plan “relies on record-breaking levels of unspecified mitigation from the cap-and-trade program in 2030 and entirely unrealistic levels of direct air capture in 2045,” the groups wrote.
“This is not a serious climate plan for California,” they said.
The letter’s signatories include representatives of the Sierra Club, Earthjustice, California Democratic Party Environmental Caucus, and the Center on Race, Poverty and the Environment, among others.
Grid Impacts
On the other side of the debate are individuals who question the scoping plan’s push toward electrification — and the impacts that would have on the electric grid.
“The state of California does not have safe or reliable power,” wrote Dawn Durfee, who said she lost her home in the Paradise wildfire. Requiring all vehicles to be electric would only make matters worse, she said.
“People do need to run refrigerators, washers, dryers, air conditioners or heaters,” Durfee said in a letter to CARB. “People do not need to drive electric cars.”
In addition, Durfee said, worldwide air quality won’t improve until China and Russia cut their emissions.
“California is not the ruler of the universe!” she wrote.
Other letter writers said they couldn’t afford to buy an electric vehicle, or that an EV wouldn’t be able to tow their trailers. Some pointed to the environmental impact of used EV batteries.
“Forcing electric cars on the population is full of disastrous consequences,” Susan Dwyer said in a letter to CARB.
The CARB board will hold a public hearing on the plan on June 23. Written comments are due by June 24.
The scoping plan evaluates four scenarios. Alternatives 1 and 2 would bring the state to carbon neutrality by 2035. In Alternatives 3 and 4, the state would reach the target 10 years later, in 2045.
CARB staff have proposed going with Alternative 3, which would have the least impact on employment and economic growth among the four options, according to the draft.
In contrast, Alternative 1 would have the highest direct costs and slow economic growth the most, the plan said. That alternative would nearly eliminate fossil fuel combustion by 2035 and would have a limited reliance on carbon capture and sequestration.
Some letter writers called the proposed alternative “too little, too late.”
“Choosing the least expensive option, relying on unproven carbon capture technologies, [and] determining job loss without adding in job creation as the energy sector changes is disheartening,” wrote Meredith Rose. “My kids deserve better — and so [do] everyone else’s kids.”
The letter from the 73 environmental groups makes several policy recommendations, including phasing out fossil fuel extraction by 2035 and refining by 2045. Regarding electric power, the groups called for a ban on new gas-fired generation starting immediately and a target of zero GHG emissions by 2035.
“Fundamentally, the draft scoping plan fails to move California beyond oil and gas,” the groups wrote.
‘Puzzling’ Plan
An editorial in the Los Angeles Times on Friday called the scoping plan’s approach “puzzling” in light of California Gov. Gavin Newsom’s directive to CARB to accelerate climate action. The governor famously referred to the “climate damn emergency” when wildfires swept through the state in 2020.
And in July 2021, Newsom asked CARB to look into how carbon neutrality could be achieved by 2035.
The editorial said the plan would use “unproven technology” to remove “huge amounts” of CO2 from the air as well as capture it from cement plants and oil refineries.
Calling the carbon removal approach a “pie in the sky strategy,” the editorial advised using proven approaches.
“In reality, we already have most of the solutions to the climate crisis right in front of us — electrifying everything we can as quickly as possible and fueling it with clean renewable energy,” the editorial said.
Clean Grid Alliance on Monday asked MISO to consider penalty-fee withdraws for advanced-stage interconnection projects that are saddled with expensive network upgrade costs from SPP’s delayed affected system study (AFS) results.
A month after requesting relief for late-stage projects held in limbo until they receive AFS results from SPP, CGA’s Rhonda Peters returned to MISO’s Interconnection Process Working Group (IPWG) to propose a penalty-free withdrawal for projects rendered infeasible by SPP-identified upgrade costs. (See CGA Requests MISO Help for Late-stage Interconnection Projects.)
MISO and SPP have rolled out a new “first ready, first served” interconnection queue priority for generation projects that affect the seams through studies and cost assignments for network upgrades. The new order replaced the grid operators’ previous practice of studying projects that lined up for the queue first. (See FERC OKs New Queue Priority for MISO, SPP Seams Studies.)
In MISO, the new priority bypassed projects that entered the queue in 2018 and 2019. The RTO said those project cycles are destined for generator interconnection agreements (GIA) before the changes take effect.
Peters said some late-stage projects that entered the queue with the 2018 and 2019 cycles still don’t have “complete, accurate or available” network upgrade costs from SPP’s affected system studies.
She said the uncertainty has jeopardized the projects’ financing and power purchase agreements. “The risk factor is too high,” she said.
Peters said MISO should consider allowing penalty-free withdrawals from the queue when late AFS results unexpectedly increase affected system costs. That would allow developers to depart the queue without forfeiting their milestone fees, she said. Peters said MISO could allow projects to interconnect beyond the original seven-year deadlines to reach commercial operation or it could provide nonbinding estimates of likely upgrade costs to aid the developers’ decision making.
Peters said developers of late-stage generation projects have already committed significant capital but might be forced to withdraw when AFS costs “are so high that they could completely change the financial viability of the projects.”
“Advanced stage projects only withdraw if forced to due to circumstances beyond their control, such as unexpected or new network upgrades,” she said. “The financial commitment to reach GIA is significant, even without consideration of milestones. … The interconnection customer wants to reach its commercial operation date. Withdrawals occur only when there is no other course of action.”
MISO’s Ryan Westphal said allowing penalty-free withdrawals could “potentially harm other customers.” The RTO usually keeps milestone fees when interconnection customers leave the queue to minimize the costs of network upgrades on lower-queued projects.
Stakeholders pointed out that AFS results can often double an interconnection customer’s network upgrade costs.
Westphal asked whether other stakeholders would be comfortable with penalty-free exits from the queue.
Invenergy’s Sophia Dossin said while her company has projects in the 2018-19 cycles of the queue, it also has projects that entered in 2020 and later. She said Invenergy is poised to be affected on both sided of the issue and is comfortable with penalty-free exits.
“I would say a lot of customers that are being impacted by the 2018-19 delays will also be impacted by the penalty-free withdrawals. … If there were a Venn diagram, there would be substantial overlap.” Dossin said. “This already is creating a lot of financial issues today.”
Dossin added that no project’s financing partner wants the risk of a “multimillion dollar question mark” on projects waiting on AFS upgrades.
“We’re not in the business of playing games. We’d rather see our projects online,” National Grid Renewables’ Rafik Halim said. He added that he didn’t think developers would view the option as an unconditional “greenlight” to remove generation projects from the queue.
“We shouldn’t be signing a blank check as we sign our GIAs,” Halim argued.
Peters said MISO could institute “rigid” criteria, such as a minimum cost threshold increase for network upgrades.
Westphal said MISO wouldn’t likely move forward with a penalty waiver unless all stakeholders are on board.
“In our opinion … this seems like a mechanism to allow harm and financial impact to other customers,” he said.
Staff also pointed out that interconnection customers should already be estimating a spectrum of AFS costs. They said extending operation deadlines for the 2018-19 project cycles might simply perpetuate uncertainty and affect lower-queued generation projects.
Peters argued that it would “make a huge difference” to financiers if bookends for upgrade cost changes came from MISO instead of the interconnection customers themselves.
MISO is set to again discuss the fate of the 2018-19 interconnection projects during the IPWG’s August meeting.
Connecticut’s ongoing investigation into opportunities to integrate medium- and heavy-duty electric vehicles (M-HDEV) on the state grid is at the forefront of rate design in the U.S., Benjamin Mandel, Northeast region senior director at the nonprofit CALSTART, said Tuesday.
“I don’t think there are robust examples of a state that’s taken a statewide approach, particularly that has been fit for purpose on M-HD vehicle electrification, especially with regard to rates,” Mandel told the Connecticut Public Utilities Regulatory Authority (PURA).
While a handful of utilities in the U.S. have taken the initiative to establish charging rates for the large EV segment, Mandel says it’s still “early days” for those programs.
“We don’t have a ton of empirical track record to go on to see how the rates are doing, and how the fleet operators for whom those rates were designed … are adjusting and responding to them,” he said during a technical meeting for PURA’s investigation (Docket 21-09-17).
Mandel spoke to regulators on behalf of the Connecticut Department of Transportation, which CALSTART supports through a Federal Transit Administration grant. PURA launched its investigation last fall and is taking input from state agency representatives and members of the public through a series of technical meetings.
“We have an opportunity to take guidance from some of these [utility rate] examples and pick and choose elements that seem interesting and appropriate for the Connecticut context and work with the [state utilities] to make sure that they’re able to be implemented here,” Mandel said.
The authority’s investigation complements its decision last summer in a separate docket to develop infrastructure incentives and rate design options for light-duty EV charging. (See Connecticut Set to Pull Trigger on EV Charger Program.)
Innovative Approach
In California, Pacific Gas and Electric’s business EV charging rates have a longer track record than others in the U.S. and is considered innovative, according to Mandel.
The utility offers separate charging packages based on business size that include time-of-use consumption rates and reduced demand charges, which Mandel says is a common theme across other utility offerings. PG&E’s design, he said, differs by allowing fleets to “determine for themselves how much demand they want to subscribe to in either 10-kW or 50-kW blocks.”
Customers can subscribe to the demand blocks on a month-by-month basis, but they must pay a fee for going over the block. In that case, a customer can adjust the next month’s block to match the increased demand.
By lowering demand charges and offering flexible monthly subscriptions, PG&E also benefits from some predictability from its larger EV charging customers, Mandel said.
Like PG&E’s business offering, he added, utilities’ M-HDEV charging rates should be cost-driven, balanced, predictable, flexible and forgiving.
Mandel recommended that regulators think of charging rates in terms of different load characteristics instead of being technology-specific, such as light duty vs M-HD.
“The predominant forms of commercial and industrial rate designs in place by utilities nationally … were not developed with these types of load shapes and load factors in mind,” he said. “We have different charging behavior and charging behavior possibilities at play with the policy goals that Connecticut and other states have signed on to.”
WESTMINSTER, Colo. — SPP continued its delicate dance with Western Interconnection entities last week with a charm offensive that included a first-hand look at the RTO’s “sausage-making” process.
Promoted as a development session for Markets+, SPP’s “RTO light” offering, the two-day gathering at Tri-State Generation & Transmission’s headquarters gave the grid operator’s staff and Western stakeholders a chance to share their thoughts on a proposed governance model, transmission operations, congestion management and the benefits of RTO management.
Western utilities have long been wary of transferring control of their transmission facilities to RTOs, but SPP officials said they were pleased with the “healthy dialogue” and exchange of information. They also noted an increase in turnout from an earlier face-to-face session in Phoenix, with more than 100 in-person attendees and more than 80 participating virtually.
Another session will be held in Portland, Ore., in August.
Listening intently during the two days was Kathleen Staks, director of Western Freedom, a coalition representing large industrial customers in technology, oil and gas, mining, renewable energy, agriculture and other sectors. Staks took a guarded approach the discussion.
“We’re sort of tracking and compiling information and comments on behalf of our coalition … trying to kind of make sure that the customer voice is represented and incorporated into these efforts for whatever the end result is,” she told RTO Insider. “It’s about lower rates, it’s about access to clean energy, but it’s primarily an economic conversation in our coalition.”
Brad Hans, director of wholesale electric operations for SPP member Municipal Energy Agency of Nebraska — and also a member of MISO and WECC — was quick to share with others his company’s positive experience with SPP’s stakeholder process. He pointed out that the discussions taking place in Colorado were very similar to those of the RTO’s members during their stakeholder meetings.
“This is a true example of what SPP is all about, and that is members driving us. This whole meeting was about what they’ve done so far, and that is absolutely SPP’s stakeholder concept,” Hans said afterward. “I kind of wonder if they realize they’re in the midst of that right now … those that aren’t as familiar with SPP and, through this development process, in that culture as they develop this.”
AG Policy Solutions’ Alaine Ginocchio — “That’s Pinocchio with a G,” she said — consults with Western Resource Advocates, a public interest organization that was prominent during SPP’s attempt to integrate the Mountain West Transmission Group (See Xcel Leaving Mountain West; SPP Integration at Risk.) While she reluctantly uses the “sausage-making” expression, she appeared to like what she saw.
“We’re used to having sort of a higher level of stakeholder engagement and being engaged on more of an equal footing with everybody else,” she said. “The energy market they’re standing up right now … is structured more to have equal footing. Not as much as CAISO, but it’s a different program. Public interest organizations have more of a voice in voting and processes [in Markets+] … and that sort of flows out of how other regional coordination efforts have worked. That’s what we’re used to, and it has worked.”
Incremental Changes in the West
Those out West will say the Western energy crisis of 2000-01, when Enron’s market manipulation led to rolling blackouts in California, had a chilling effect on regional coordination and energy markets. SPP Director Mark Crisson, who spent nearly 30 years with Tacoma Public Utilities, said in April that “RTO paranoia” still hangs over the balkanized region and its 38 balancing authorities. (See SPP Strategic Planning Committee Briefs: April 13, 2022.)
“There’s a lot of concern about FERC regulation,” Crisson said during an SPP Strategic Planning Committee meeting. “A lot of people remember that exercise.”
Change has been incremental in the West since then. The region’s wide open spaces and political differences can make it difficult to coordinate regionally, but renewable standards, the success of Eastern markets, CAISO’s Western Energy Imbalance Market (WEIM), and legislation in Colorado and Nevada mandating that utilities join RTOs by 2030 have managed to bring the interconnection’s entities closer together.
The Markets+ day-ahead market is another incremental step toward a Western RTO. It provides a “voluntary” opportunity to realize the benefits of centralized day-ahead and real-time unit commitment and dispatch, “hurdle-free” transmission service, and “reliable” integration of renewable generation for utilities that aren’t ready “to pursue full membership in” an RTO.
“We recognize that not everyone is at a point where they’re comfortable moving to an RTO, because they are transferring control of their facilities to the RTO,” SPP Senior Vice President of Operations Bruce Rew told the gathering. “We see Markets+ as a possible long-term solution to meeting some market needs.”
All of this is familiar to Xcel Energy’s Carrie Simpson, director of Western markets for Xcel’s Public Service Company of Colorado. Simpson joined Xcel in 2015 after helping design SPP’s Integrated Marketplace, which will serve as the foundation for Markets+.
“It’s a similar vibe,” she said before appearing on a resource adequacy panel.
Simpson has become something of a rock star in Western power circles for her market expertise. She was not present for the opening introductions, but Joe Taylor, manager of transmission access for Xcel Energy Services, made sure everyone knew she would eventually show up.
“Joe Taylor, Xcel Energy. And don’t worry, Carrie Simpson will be here in a few hours,” he said to laughs.
Governance Model a Key Issue
SPP has said Markets+ will eventually replace the Western Energy Imbalance Service (WEIS) market it currently operates. When three new members join the WEIS next year, it will be regionally balancing 13.5 GW of load generation. Rew said an imbalance market is a great introduction to markets but is only a short-term solution for participants.
“There are some limitations to Markets+,” Rew said. “You don’t have a regional tariff; you don’t have a consolidated balancing authority, so you’re not going to get all the benefits. It will provide a lot of potential outcomes for certain market participants that are uncomfortable moving to an RTO.”
SPP is attempting to ease that discomfort. It has hired two very familiar faces from the West in Steve Johnson, formerly senior vice president of the Colorado River Storage Project for the Western Area Power Administration, and Kara Fornstrom, former Wyoming Public Service Commission chair. Johnson is directing the RTO’s various markets’ administration and operation. As director of state regulatory policy, Fornstrom is leading state regulatory policy efforts in the West where she appears to be on a first-name basis with many participants.
SPP executives also pointed out that two members of its board, Crisson and newly-elected John Cupparo, both have deep ties to the West. A Colorado State graduate, Cupparo was CEO of Berkshire Hathaway Energy’s transmission subsidiaries and also served in leadership roles at PacifiCorp, WECC and Northern Tier Transmission Group.
“Somebody made the comment [earlier], ‘Do I want a board member from Little Rock [Ark.] determining matters for the [Western] markets?’” SPP legal counsel Paul Suskie said. He took pains to note that only one SPP director (Oklahoma law professor Phyllis Bernard) has ever hailed from the footprint, and that she has since moved to Oregon. The other 16 directors since 2004 have come from outside the RTO’s service territory.
“So that gives you a taste of the board,” Suskie said. “They are truly independent.”
That is important, as the West’s most immediate experience with an organized market is that of CAISO, where the board is appointed by California’s governor.
Last week, SPP shared a straw man of its proposed Markets+ governance model, based on input from Western stakeholders and the grid operator’s best practices. The model is also designed to gain FERC approval and to minimize financial consequences for SPP, which will have to carry the debt necessary to stand up the market.
The model has an independent panel, comprised of one SPP director and four Western representatives elected by a forum of Markets+ participants and stakeholders, that would govern market operations and report to the RTO’s board. Suskie was asked why it’s called a panel and not a board. Simply to avoid confusion, he said.
The Markets+ Independent Panel (MIP) would oversee a Markets+ Participants Executive Committee (MPEC), which would be responsible for creating and managing the various stakeholder groups. A Markets+ State Committee would provide input from Western regulatory commissions to both the MIP and MPEC.
Market participants will be classified as either participants or stakeholders, depending on whether they contribute generation or load. They will sign either participant or stakeholder agreements, with stakeholders retaining voting rights in return for an annual $5,000 fee. Non-voting stakeholders could eschew the fee and provide input during stakeholder meetings, but they would not have voting rights.
The design is part of SPP’s key foundation of ensuring everyone can contribute to stakeholder discussions, Rew said.
“We are going to continue to foster engaging discussions on Markets+, making sure that we give voice to diverse perspectives,” he said. “Then, continuing to develop this vision for Markets+ until ultimately Markets+ is your market. It’s not just for the participants, but also the benefit it provides overall to the Western Interconnection.”
Maury Galbraith, executive director of the Western Interstate Energy Board, called the governance model “acceptable,” and alluded to a race between SPP and CAISO to establish a Western RTO.
“You get a lot of people saying that ‘This is not a race.’ People say, ‘No, it is a race. It is a competition; we need to move forward,’” Galbraith said. “I understand that time is important here. The governance proposal is something that is probably acceptable to a large number of states. I think the word ‘acceptable’ is right. I don’t see any showstoppers in there. I’m not aware of any state that is, sort of at the point where they’re ready to go to FERC and oppose anything.
“I think it’s a workable solution. But in terms of the overall competition and really striking a bold governance structure, I don’t see the proposal being a bold proposal. I think we could have gone farther in terms of really trying to win the governance battle, if that’s what it is. I think there’s some additional steps that could have been taken to really, really come up with a best-practice governance structure, and I’d be happy to have that conversation.”
Next Steps for Markets+
Galbraith’s comments were among several, some more pointed than others, from a panel during a breakout session on the proposed governance model. Suskie thanked those offering feedback. What they had just experienced, he said, was a best practice at the RTO.
“We like to call this an example of how SPP does things,” he said before drawing on his experience as an officer in the Army reserves during a stint in Afghanistan. “We put out a straw proposal, we put on our body armor, and we get shot at. We have our ideas, we take feedback, and then we can figure out how to adjust it. Part of the balance that we have is SPP has a lot of responsibilities. It’ll be SPP’s tariff and it will be SPP who will be operating this market and facilitating that.”
Suskie and Fornstrom took the comments and returned the next day with a revised timeline. An updated governance proposal will be shared during a June 24 webinar, with written comments due July 15. SPP will summarize the written comments in another webinar before the Portland workshop.
While governance took much of the spotlight, attendees also heard updates from the transmission availability and the market products/price formation design teams. Western stakeholders briefed the room on greenhouse gas tracking and a panel of market monitors — SPP Market Monitoring Unit Vice President Keith Collins; Libertas Market Analysis’ Jeff McDonald, formerly ISO-NE’s Monitor; and Potomac Economics’ David Patton (virtually) — shared their thoughts on internal, external and hybrid monitoring structures.
Western Power Pool (WPP) CEO Sarah Edmonds, just months into her new position, appeared virtually to describe the potential relationship between Markets+ and the pool’s Western Resource Adequacy Program (WRAP), which SPP already administers in partnership with WPP. Assuming FERC’s approval of WPP’s tariff, the WRAP is scheduled to go live early next year, with members demonstrating they have procured the required quantity of credited capacity from physical resources. In return, they get priority access to WRAP’s supply.
“We have a lot of success in the region brokering consensus on a workable package around governance. A lot of the elements that have been addressed in governance for Markets+ are common to WRAP or even originated from WRAP … trying to solve some of the hardest problems in the West based around governance,” Edmonds said.
“This is still an incremental program that’s singularly focused on resource adequacy and not a market. It is not an RTO but it is a workable framework and one that we’ve always said from the very beginning would be compatible with a market … and here we are in a conversation with the West with a couple of options on the table,” she said. “[Resource adequacy] is a very important foundation for healthy well-functioning markets, and I think WRAP can serve that purpose for Markets+.”
SPP plans to have draft service offerings available for comment by the end of September. Participants will be able to agree to financially binding commitments in the first quarter of 2023, at which point they can develop the market protocols and tariff language.
Attempting to blunt the impact of the Commerce Department’s solar import investigation, President Joe Biden on Monday invoked a 1930 law to declare a two-year tariff waiver on imports of solar cells and panels from Cambodia, Malaysia, Thailand and Vietnam.
Citing a section of the Tariff Act of 1930, the president declared an emergency threat to the America’s supply of solar panels and electric reliability, which will allow panels from the four Asian countries to be imported into the U.S. duty free for two years.
“This comes as a surprise because this isn’t something that was on our radar or a lot of people’s radar as a way to deal with” supply delays and cancellations caused by the investigation, said Christian Roselund, senior policy analyst for Clean Energy Associates. “But the Biden administration said they were going to do something, and they appear to have found a legal avenue to do so.”
“Two years of imports not being subject to duties is huge,” Roselund said.
However, Monday’s announcement does not derail the investigation into claims by Auxin Solar Inc., a California-based solar manufacturer, that panels imported from Cambodia, Malaysia, Thailand and Vietnam contain Chinese components subject to tariffs imposed by the Trump administration and continued by Biden. (See Biden Extends Tariffs on Imported Solar Panels.)
Depending on the investigation results, new tariffs could still be imposed on solar imports from the four countries, but not until the end of the two-year waiver in 2024.
The solar industry conducted an intensive lobbying campaign urging Biden to provide relief from the tariff investigation. Because more than 75% of panels used in utility-scale projects in the U.S. come from Cambodia, Malaysia, Thailand and Vietnam, the investigation, begun in March, has had a chilling effect on solar projects. A recent survey by the Solar Energy Industries Association (SEIA) found hundreds of developers across the country reporting supply delays or cancellations.
ClearView Energy Partners said the Commerce Department is expected to issue its preliminary findings in the investigation in August, with a final ruling in January 2023. No tariffs resulting from the investigation would be retroactive.
“I remain committed to upholding our trade laws and ensuring American workers have a chance to compete on a level playing field,” Commerce Secretary Gina Raimondo said in a statement released after the president’s announcement. “The president’s emergency declaration ensures America’s families have access to reliable and clean electricity while also ensuring we have the ability to hold our trading partners accountable to their commitments.”
Response from solar and clean energy organizations was swift and positive.
Advanced Energy Economy CEO Nat Kreamer called the tariff exemptions “a needed stay in a more than decade-long tariff war that has been a loser for all parties. Tariffs only raise costs for consumers and don’t create domestic demand for clean energy.”
SEIA CEO Abigail Ross Hopper praised Biden’s “thoughtful approach to addressing the current crisis of the paralyzed solar supply chain. The president is providing improved business certainty today while harnessing the power of the Defense Production Act for tomorrow.”
But Auxin CEO Mamun Rashid issued a statement criticizing Biden for “significantly interfering in Commerce’s quasi-judicial process. By taking this unprecedented — and potentially illegal — action, he has opened the door wide for Chinese-funded special interests to defeat the fair application of U.S. trade law.”
Legal action challenging the waiver is possible, according to ClearView.
DPA and Federal Procurement
The waiver is the centerpiece of a three-part initiative that, ClearView says, reflects Biden’s ongoing efforts “to resolve tensions between domestic politics and [his] transition policy goals. … Fuel prices appear to have pinned the White House between voter backlash against inflation and campaign promises to accelerate [the energy] transition and end federal fossil energy leasing.”
Biden also authorized the Department of Energy to use the Defense Production Act to help expand domestic manufacture of solar panel components, as well as building insulation, electric heat pumps, grid equipment such as transformers, and electrolyzers used to produce green hydrogen.
Federal procurement will also be enlisted to boost domestic demand and manufacturing via special contracts, called master supply agreements, and “super preferences” for made-in-America solar systems. By making it easier for U.S. companies to sell to the government, these measures could increase demand for domestically produced solar panels by 1 GW in the near term and 10 GW over the next decade, according to a White House fact sheet.
The trio of initiatives is aimed at tripling current domestic solar panel manufacturing capacity from 7.5 GW to 22.5 GW by 2025, while also alleviating the negative impacts of the Commerce investigation.
Statements from administration officials pointed to the economic and national security impacts of Biden’s actions.
“In conflict, fossil fuel supply lines are especially vulnerable,” Deputy Secretary of Defense Kathleen Hicks said. The initiatives announced Monday “will help strengthen our supply chains and ensure that the United States is a leader in producing the energy technologies that are essential to our future success. They will also help accelerate DoD’s transition toward clean energy technologies that can help strengthen military capability while creating good jobs for American workers.”
Echoing Hicks, Energy Secretary Jennifer Granholm said the DPA will “help strengthen domestic solar, heat pump and grid manufacturing industries while fortifying America’s economic security and creating good-paying jobs, and lowering utility costs along the way.”
Solar supply chains were a secondary concern for Jim Matheson, CEO of the National Rural Electric Cooperative Association (NRECA), who instead zeroed in on the DPA’s potential impact on the transformer supply chain and electric system reliability.
“Shortages of transformers pose a risk to normal electric grid operations as well as recovery efforts for systems disrupted by a natural disaster,” Matheson said. “The Biden administration’s use of the Defense Production Act to shorten lead times for supplies of electric transformers is a much needed step to support reliability and resilience, and NRECA urges inclusion of all stakeholders in the implementation process.”
‘Get Stuff Built’
A major point of uncertainty for solar industry advocates and analysts is whether the president’s actions will provide the momentum needed to quickly re-open overseas supply chains and accelerate the buildout of a domestic supply chain.
Noting that American demand for solar panels hit 20 GW in 2021, Roselund said, “There’s this huge imbalance between what U.S. factories can supply, even running at full capacity, and what the market demands.”
The waivers will provide a short-term solution for developers, said Mike Kruger, CEO of the Colorado Solar and Storage Association. Two years may not be “sufficient time to get domestic manufacturing pumping out panels,” he said. “But it certainly gives folks a pretty clear signal that they’ve got some runway to get stuff built.”
Kruger and other solar advocates see solar and manufacturing tax credits and other incentives tied up in Congress as critical for the long term. In her statement, Hopper called for passage of the Solar Energy Manufacturing for America Act, which would provide incentives for a range of domestically manufactured solar components, including panels, trackers and inverters.
Roselund also sees the DPA as a short-term solution to a structural challenge for U.S. solar manufacturing ― its higher production costs compared to overseas competitors.
“If the goal is to make everything domestically then you need some way to compensate for the fact that it’s more expensive to manufacture in the United States,” he said. “The most direct way to do that is subsidies.”
Should tariffs cut off imports from the Southeast Asian countries as well as China, he said, manufacturing will go “somewhere else that is less expensive. The likely outcome if we don’t pass some sort of incentives to compensate for the cost difference is that more of utility-scale product gets supplied from places like India and Turkey.”
FERC expanded its series of orders directing refunds for premiums earned in the Western heat wave of August 2020 by telling ConocoPhillips (NYSE:COP) and Direct Energy on Friday to return excess money they made on sales in scarcity conditions.
In Direct Energy’s case, FERC said the Houston-based energy retailer had failed to justify 25 MW in sales to Macquarie Energy for $1,500 MW/h, higher than the average index price of $1,333 MW/h at the Mead Hub in southern Nevada on Aug. 18, 2020 (ER21-64).
“We find that Direct Energy has not provided adequate justification for the amount charged above the index price, and, therefore, we direct Direct Energy to refund amounts charged above the average index price for the sale at issue within 30 days of the date of this order,” FERC wrote.
In ConocoPhillips’ case, the company had justified its August 2020 sales at its “cost of energy purchased, but it has not justified the amounts charged above [that cost],” FERC said (ER21-40).
ConocoPhillips contended two sales to Arizona’s Salt River Project on Aug. 17-18 were sleeve transactions it facilitated between a third-party seller and the utility. ConocoPhillips charged far more than it paid for the energy, which it said reflected operational costs and the heightened risks from record heat, wildfires, transmission outages and the potential for nonperformance by the parties at the time.
SRP argued the sales were not sleeve transactions under FERC’s definition, in which “an entity acts as an intermediary counterparty to accomplish a sale between two other counterparties who may not be set up to transact with each other using common enabling agreements (such as the Western Systems Power Pool (WSPP) or Edison Electric Institute agreements) or who may not meet credit requirements.”
The utility said the parties were members of WSPP that could use its common enabling agreement, and it pointed out that it had a credit rating of AA+ from S&P Global Ratings when the transactions occurred.
Even if the sales were sleeve transactions, the fees ConocoPhillips charged were far more than the “nominal” add-ons allowed by FERC in such cases, SRP said.
“According to Salt River, ConocoPhillips cannot credibly report to the commission that these transactions were sleeve transactions with nominal fees, nor attest reasonably to the commission that the amount it charged above cost, which is vastly higher than a nominal fee, should apply to its transactions during August of 2020 due to heightened risks,” FERC wrote.
The commission agreed.
“While the record in this proceeding indicates that ConocoPhillips acted as an intermediary in obtaining energy Salt River sought to purchase and then selling that energy to Salt River, [our previous guidance on sleeve transactions] was specific in its description of the circumstances in which a transaction involving an intermediary qualifies as a sleeve transaction, and ConocoPhillips has not demonstrated that those circumstances are present here,” FERC said.
“Specifically, ConocoPhillips has not demonstrated that it collected only a nominal fee in acting as an intermediary counterparty to accomplish a sale between two other counterparties,” it said.
So far, the commission has decided 10 of the cases, ordering refunds in all. It also has denied motions by some of the parties to raise WECC’s soft price cap to $2,000/MWh, the same as CAISO’s, saying the matter was beyond the scope of the proceedings.
Commissioner James Danly has dissented in each case, saying FERC lacks the legal authority to interfere in contracts between willing buyers and sellers that do not harm the public interest.
Parties to the United Nations Framework Convention on Climate Change began their annual subsidiary bodies conference in Bonn, Germany, Monday to prepare for the 27th Conference of the Parties (COP27) in Egypt this fall.
UN Climate Change Executive Secretary Patricia Espinosa | United Nations
“These are meetings where we can already start seeing the best way to address some of the contentious issues that will be coming up,” UN Climate Change Executive Secretary Patricia Espinosa said. The meeting has “special meaning” in the context of a world that is “nothing like what we saw [at COP26] in Glasgow … and is being impacted by significant progress on climate change, including the disruption of global energy markets and clean energy investments,” she said during an opening day press conference.
UNFCC subsidiary bodies, in charge of implementation and scientific and technological advice, will hold meetings through June 16, focusing on advancing the issues that will be before the full conference in Sharm El-Sheikh, Egypt. Top among the bodies’ concerns will be mitigation, adaptation, finance, and loss and damage.
The Bonn conference is the first time parties have met since COP26, where they agreed on the operational details of the 2015 Paris Agreement and the work necessary to mitigate, adapt to and compensate for climate change.
“This conference marks the start of a new phase in our intergovernmental climate change process; a phase of implementation,” Espinosa said. “We have a blueprint, and we have the rules to ensure that it is transpiring, so it’s time to get on with the job.”
Mitigation
Mitigating greenhouse gas emissions through national climate action plans is a cornerstone of the Paris Agreement, but Espinosa said parties in Glasgow agreed that the existing five-year cycle for updating those plans is not sufficient.
Parties need to make climate plan reviews a “permanent process” so they can watch for opportunities to reduce emissions and further the agreement’s goal of keeping global temperature rise below 1.5 degrees Celsius, she said.
“So far, we have received only a few updated [plans], and we need to get more,” she said.
The UNFCCC Secretariat is helping support more national plan updates by encouraging parties to report progress on implementation or potential future mitigation opportunities without walking through the entire plan development process, according to Espinosa.
Regular updates, she added, will help the Secretariat develop “the most credible picture” on mitigation and long-term climate strategies from countries.
“This is a big area where we know the world will be watching and will want to know exactly where we are,” she said.
During the Bonn conference, parties will also discuss preparations for the regular global stocktake required by the Paris Agreement to assess the collective progress on achieving the goals of the agreement.
“The technical dialogue [in Bonn] will allow parties to start identifying where the existing gaps are and hopefully how to address them,” Espinosa said.
Adaptation and Loss
Adapting to climate change was a main concern raised by vulnerable, developing countries during COP26, and Espinosa said that those countries were “eager” to see the issue on the Bonn conference agenda.
In Glasgow, “there was a decision to start the process of defining a new global goal on adaptation, and we start that conversation here in Bonn,” she said.
Espinosa also hopes parties will make progress in Bonn on developing the Santiago Network for countries that need advice on issues related to loss and damage from climate change. Last year, the parties outlined the functions of the network, which was formalized originally in 2019.
The network, Espinosa said, “needs to become fully operational.”
She also wants to see the parties advance a dialogue on how to finance loss and damage that started in Glasgow.
Retiring
Espinosa officially announced her retirement from the role of Executive Secretary during her opening speech at the conference.
“My time serving the process from the Secretariat is at an end, but this process will go on, and I will do all I can to contribute, as a private citizen, to improving our understanding, galvanizing action and, ultimately, improve our chances of success on climate,” she said.
Espinosa took over the role in 2016, having served previously as the Mexican Minister of Foreign Affairs and the President of COP16 in 2010.
Reflecting on her six-year tenure, Espinosa said: “If we all do what we can and we work together, we can get through any challenge. The key is to support each other.”
SACRAMENTO — Legislative leaders in California proposed a budget plan Wednesday that differs from Gov. Gavin Newsom’s proposal on how to spend $21 billion on climate and energy initiatives.
The legislature proposed appropriating $21 billion for climate and energy efforts to the state’s general fund, with spending details to be worked out later.
In contrast, the governor’s revised budget, released in May, proposed spending $32 billion on climate and energy — up $9.5 billion from his $22.5 billion January proposal — with almost all of it allocated to specific programs. (See Calif. Governor Proposes $5B ‘Reliability Reserve’.) The legislature’s full budget includes about $10 billion of that, including a $9.1 billion transportation infrastructure package, but allocates it separately from the climate and energy initiatives.
According to a summary of the legislature’s proposal, the $21 billion could fund projects related to drought and wildfire resilience, extreme heat and zero-emission vehicles, among other matters. But without specific allocations in place, each category’s funding level is uncertain.
California expects to have a record $97.5 billion revenue surplus in fiscal year 2022/23, and lawmakers want to return part of those funds to residents, including $8 billion to offset the rising costs of gas and consumer goods.
“The legislature has come together on a budget agreement that will truly put California’s wealth to work for all,” said State Sen. Nancy Skinner, chair of the Senate Budget and Fiscal Review Committee. Skinner is noted for her work on energy and climate change.
A 2010 state constitutional amendment requires lawmakers to pass a budget plan by June 15 or have their pay docked. That has resulted in placeholder budgets with contentious issues left for further negotiation between the governor and legislature.
Programs that would be put on hold for now under the legislative plan include the governor’s proposal to spend $250 million to support strategic clean energy projects such as building new transmission lines to connect CAISO’s grid to geothermal resources near the Salton Sea.
The legislature would also defer allocating $6.1 billion to accelerate the adoption of ZEVs, $5.2 billion for a 5-GW strategic reliability reserve and $1.2 billion for wildfire and forest resilience. (See Calif. Governor Proposes Spending $10B on EVs.)
Smaller items, such as $45 million to promote offshore wind, would also be postponed pending additional negotiations, which both sides hope to conclude before the start of the fiscal year on July 1.
ISO-NE is considering reusing its Winter Reliability Program or Inventoried Energy Program (IEP) to address uncertainty about the reliability of New England’s grid this winter.
Familiar fuel constraints, massive uncertainty from the war in Ukraine and the possibility of extreme weather have led to early and grim warnings from the grid operator about supply and reliability for the upcoming winter. (See Fears Already Mounting About Next Winter in New England.)
In a note sent to stakeholders Friday, Allison DiGrande, ISO-NE director of participants relations and services, said the RTO is working with a consultant to “refresh its analysis” and look at the costs and value of previously approved winter solutions, specifically naming both programs.
The Winter Reliability Program, in place between 2015 and 2018, incentivized generators that run on oil and gas to secure fuel before winter, by compensating them for a “portion of the costs related to any fuel inventory that is unused at the end of each winter.”
ISO-NE CEO Gordon van Welie, however, recently threw cold water on the prospect of revisiting that solution.
“Do we want to pay oil units more money to do what they have a massive incentive to do anyway?” he said at a recent conference. “What’s the likelihood of success of us trying to stand up a program like that, get it through the system and have it implemented in time?”
The IEP is a voluntary program in place for the 2023-2025 period that will compensate resources for the inventoried energy they hold on winter days that hit a certain low-temperature threshold.
It too would face uncertainty if ISO-NE decides to reuse it: It was approved by FERC in 2020, under a Republican majority; Commissioner Richard Glick, now chairing a Democratic majority, said in a dissent that the program was “an ill-conceived giveaway that acts as if throwing money at a problem is always just and reasonable.” (See ISO-NE Stopgap Fuel Security Program Gets OK.)
DiGrande said that by early July, ISO-NE will make a recommendation about whether it plans to “stay the course” with its current market structures or propose tariff changes for this winter. If the RTO does recommend changes, DiGrande wrote, “we would plan to meet the stakeholder process requirements with two Markets Committee meetings in July and the final vote at the Participants Committee on Aug. 4.” That schedule would allow for an August filing at FERC and a September order.
ISO-NE has also been requesting information from asset owners about their plans to meet operating requirements, and from some fuel providers about their inventories and delivery capabilities.
“When completed, these inquiries will allow the ISO to compile data on the anticipated fuel stock that will be available to suppliers to meet the demand for electricity this winter,” DiGrande said.
