Two Washington state senators introduced a bill Monday to provide farmers and haulers of agricultural products financial relief from the costs arising from the state’s new cap-and-trade program.
Washington’s cap-and trade program went into effect this year, and its first auction on Feb. 28 raised almost $300 million in revenue for state climate and energy programs. The second quarterly auction is scheduled for May 31.
In 2021, the Democrat-controlled Washington legislature passed the nation’s second cap-and-trade law along party lines, with the minority Republicans citing farmers’ higher fuel prices as one reason for their opposition.
Oil and petroleum producers are among the companies that need to collect allowances and reduce their emissions.
Democratic senators Mark Mullet and Joe Nguyen on Monday introduced Senate Bill 5766, which would require the state to set up a remittance program by Jan. 1, 2024, for farm fuel users and freight haulers of agricultural products.
“When we passed the (cap-and-trade law), we made a promise to Washington’s farmers to protect them from additional costs that could potentially be passed on from the bill. We need to keep that promise,” Mullet said in a press release. “We hoped this was going to be addressed in implementation, but we heard clearly in budget hearings that this issue still needs to be addressed. This bill is a small, reasonable step that keeps our promise to our farmers.”
Under the program outlined in the bill, the targeted beneficiaries would submit receipts every quarter showing purchases for fuel used for farming and transporting agricultural goods.
“An approved application for remittance … is eligible for a remittance equal to the auction settlement price in effect for the calendar quarter in which the fuel was purchased multiplied by eight-tenths of one percent and the number of gallons in the remittance application,” the bill states.
At the Feb. 28 auction, carbon allowances representing 1 ton of emissions settled at $48.50, which would translate to a refund of 38.8 cents per gallon for the current quarter.
“Our farmers are critical contributors to our economy, and they are being unfairly targeted by big oil companies. It was always our intention to exempt their fuel from the (cap-and-trade) guidelines,” Nguyen said in a statement.
The bill is now in the Senate’s Ways & Means Committee.
WASHINGTON ― Tracing the lithium and cobalt in an electric vehicle battery is not the same as tracing a strawberry from field to fork, Circulor CEO Douglas Johnson-Poensgen told the audience at the SAFE Summit on Tuesday.
A strawberry will be more or less identifiable as a strawberry at both ends of the process, Johnson-Poensgen said. Minerals are different, and Circulor has developed software that provides a digital identifier that can “actually tell a story of a product that has undergone multiple stages of metamorphosis during its journey,” he said.
“Your supply chain is not linear,” Johnson-Poensgen said. “It’s not a series of one-to-one relationships, and so you have to be able to deal not just with the flow of those materials, through multiple participants where trading relationships between participants in the supply chain change largely based on price and availability. … A time stamp for those transactions is quite important when the time between mine and car can be measured in many, many months.”
A key theme at the SAFE Summit, the transparency and traceability of critical minerals and other battery components will be essential for automakers as they work to meet the domestic content provisions of the Inflation Reduction Act’s electric vehicle tax credits, which the Treasury Department issued Friday. (See Fewer EVs May Get IRA Tax Credit Under New Domestic Content Rules.)
To ensure their customers can qualify for the full $7,500 credit, U.S. and foreign automakers will have to be able to certify that at least 40% of the critical minerals in the batteries of their 2023 EV models were sourced and processed in the U.S. or a country with which the U.S. has a free-trade agreement.
At least 50% of other battery components will have to be similarly sourced, and the guidelines lay out multistep processes automakers must follow to verify their vehicles qualify for the credit. Failing to meet those requirements when the new provisions go into effect on April 18 could mean EVs that currently qualify for the full credit may only receive half — $3,750 — or none at all.
Speaking Thursday at a media briefing on the new guidelines, Treasury Department officials could not say which of the more than 20 models of EVs and plug-in hybrids they currently list as qualifying for the $7,500 credit will be affected when the new guidelines go into effect on April 18. An updated list will be posted by that date, officials said.
FEOCs
The guidelines’ prohibition on the use of any battery components or critical minerals produced by “foreign entities of concern” (FEOCs), scheduled to go into effect in 2024 and 2025, respectively, could be another big hit for U.S. and foreign automakers, and require another level of transparency and traceability.
Treasury has yet to release guidelines on these provisions, in particular on how FEOC will be defined.
At present, industry stakeholders have pointed to the State Department’s definition, which classifies China, Russia, North Korea and Iran as FEOCs.
Future guidelines will likely focus on ensuring no minerals or components used in EVs sold in the U.S. come from countries where child and forced labor have been documented. Citing figures from the International Labor Organization, Thea Lee, deputy undersecretary for international affairs at the Labor Department, told the SAFE Summit that 27 million people are trapped in forced labor worldwide, “many of them … in mines and factories that supply raw materials for the green energy sector.”
Cobalt mined in the Democratic Republic of Congo with child labor is a “key input for many lithium-ion batteries made in China, and so we are now listing Chinese lithium-ion batteries as being produced with material made from child labor,” Lee said.
Artisanal mining — informal, small-scale projects — employs millions in the Congo, so, “responsible sourcing” will require “formalization,” she said. “Formalization will standardize safety, environmental and labor protections for workers. It means integrating worker voice, high labor standards and accountability for labor rights violations into your due diligence process.”
The Labor Department has launched a Global Trace Protocol Project aimed at providing traceability tools that can provide transparency on child and forced labor, Lee said. Circulor is one of several organizations currently working on systems, many of them blockchain-based, to allow tracing of child labor in the Congo’s cobalt mines, according to a May 2022 report on the Global Trace project website.
Johnson-Poensgen foresees new EVs rolling off production lines with “battery passports,” based on a combination of databases and machine learning, which would contain a full record of the vehicle’s supply chain. Some European carmakers are already providing such passports for their vehicles for about $10 per EV, he said.
The FTA Loophole
The IRA and Treasury guidelines still contain some significant loopholes, the biggest being the law’s vague definition of “free trade agreement” and the Treasury Department’s efforts to nail down a set of principles for what such an agreement might look like.
The guidelines call for agreements that “reduce or eliminate trade barriers on a preferential basis, commit the parties to refrain from imposing new trade barriers [and] establish high-standard disciplines in key areas affecting trade.”
These and other requirements detailed by Treasury were incorporated into a critical mineral agreement the U.S. signed with Japan on March 28. Similar agreements with the European Union and the United Kingdom could be forthcoming, according to industry analysts ClearView Energy Partners.
Sen. Joe Manchin (D-W. Va.) | SAFE
ClearView sees the guidelines as reflecting an ongoing tension between the desire to accelerate EV adoption (decarbonization) and building out the U.S. supply chain (deglobalization), but definitely leaning more to the decarbonization side.
For example, the guidelines “would treat battery ‘constituent materials’ as ‘critical minerals’ that can be sourced from FTA countries (as opposed to ‘battery components’ that must be manufactured or assembled in North America),” ClearView said in its analysis of the guidelines.
The FTA principles and the critical mineral agreement with Japan drew criticism from top Democrats, such as Senate Finance Chair Ron Wyden (D-Ore.) and House Ways and Means Ranking Member Richard Neal (D-Mass.), who said they contained no environmental or labor safeguards.
“Mining is a challenging business, with ongoing violations of workers’ rights, child labor, forced labor, environmental degradation, and toxic chemical exposure all present in the industry,” Wyden and Neal said in a joint press release. “Even among allies, the United States should only enter into agreements that account for the realities of an industry, learn from past agreements, and raise standards.”
Further, the lawmakers argued that Biden does not have the unilateral authority to enter trade agreements without congressional approval.
Sen. Joe Manchin (D-W. Va.), who authored the domestic content provisions of the IRA, was even more critical, arguing that “the guidance released by the Department of the Treasury completely ignores the intent of the Inflation Reduction Act. It is horrific that the Administration continues to ignore the purpose of the law which is to bring manufacturing back to America and ensure we have reliable and secure supply chains. American tax dollars should not be used to support manufacturing jobs overseas,” Manchin said in a statement released Friday.
Speaking at the SAFE Summit on Thursday, Manchin sent mixed messages, first saying, “I’ve always felt that our allies were part of a secure supply chain.” But like Wyden and Neal, he sees definitions in the Treasury guidelines for free trade agreements and other provisions in the law as giving too much away.
“What I’m most concerned about is how they classify the processing with ‘manufacturing,’” Manchin said. “‘Manufacturing’ is meant to bring manufacturing back to the United States. It’s not basically allowing everyone to put all the parts and build everything you can for the battery somewhere else and then send it here for assembling. That bill does not specifically in any way, shape or form refer to ‘assembling.’ It says ‘manufacturing.’”
Further, he said, the IRA has already galvanized foreign investment in the U.S. “This is the most attraction [we’ve] ever had, and you see so much demand. This could bring $3 trillion pretty well rapidly to our country for manufacturing. …
“I want a solid, safe, dependable supply chain,” he said. At the summit, Manchin threatened to go to court to stop implementation of the guidelines if they do not reflect the intent of the law as he wrote it ― a threat not repeated in his Friday statement.
Taking the Long View
The political battles notwithstanding, the key issue arising from the new guidelines is whether the loss of tax credits will, in the short term, cut into EV sales. The view from the Treasury Department is that any short-term reduction in models eligible for the full tax credit will be offset by the buildout of a domestic supply chain, which over the next decade will make more EVs available and eligible for the credit.
President Biden has set a goal for 50% of all new car sales in the U.S. to be zero-emission vehicles by 2030, and he sees the tax credit as a major incentive for getting more Americans driving electric.
To counter any dampening effect from the new guidelines, the White House has been promoting the wave of new investments in EV battery manufacturing in the U.S. ― also supported by clean energy manufacturing tax credits and other incentives in the IRA ― as well as corporate commitments to electrifying vehicle fleets.
An estimated $90 billion in private investments have poured into new efforts to build out an EV battery supply chain in the U.S. since Biden took office, with half that amount announced since passage of the IRA, according to a senior administration official speaking at Thursday’s media briefing.
The White House also announced new public and private commitments to vehicle electrification as part of Biden’s EV Acceleration Challenge, launched earlier this year.
The federal government has acquired 13,000 ZEVs so far in fiscal 2023, and federal agencies have committed to installing 24,000 charging stations at their facilities across the country by the end of the fiscal year on Sept. 30, according to a White House fact sheet.
In the private sector, First Student, a supplier of school bus services, has committed to transitioning 30,000 fossil fuel-powered school buses to electric by 2035, while battery recycler Cirba Solutions recently announced plans for a major new facility in South Carolina that will recycle enough lithium and other critical minerals to manufacture 500,000 EVs.
Pent-up Demand
Immediate reactions to the guidelines from carmakers and trade groups acknowledged the negative short-term impacts but similarly focused on longer-term market growth.
“The guidance provides the clarity industry needs to invest in more secure and reliable supply chains for critical minerals and battery components with our allies,” said SAFE CEO Robbie Diamond, while also calling for careful work on the definition of FEOCs.
“How we define and enforce these provisions will make or break the national security benefits of the IRA and will require vigilance and rigorous enforcement to ensure that China and other foreign entities of concern don’t re-infiltrate our supply network,” Diamond said. “Ultimately, it’s imperative that we expand the circle of allies and partners who can benefit from and contribute to our supply chains.”
Speaking at the SAFE Summit, Jeffrey Morrison, vice president of global purchasing and supply chains for General Motors, said GM began work on its domestic supply chain more than a year before the IRA was signed into law in August.
“We knew that the capacity we needed wasn’t there. We had to build new capacity, and we wanted to have a more resilient value chain … than what exists today,” he said.
GM kept the spin positive in a statement issued following the release of the guidelines. Committed to phasing out new gas-powered models and going full electric by 2035, the company called tax credits “a proven accelerator of electric vehicle adoption.”
GM expects its Cadillac Lyriq electric SUV will qualify for the full $7,500 tax credit, as will two other electric SUVs to be released this year, the Chevrolet Equinox and Blazer. However, Chevy’s popular Bolt and Bolt EUV models may only be eligible for a $3,750 credit, the company said.
Echoing Treasury officials, John Bozzella, CEO of the Alliance for Automotive Innovation, an industry trade group, said the number of EVs qualifying for the full tax credit will go down, but he couldn’t say which models might or might not qualify after April 18.
But, in a blog on the AAI website, Bozzella called the first quarter of 2023 the “highwater mark” for EV tax credit eligibility since passage of the IRA. He also pointed to rising figures for EV sales ― 8.5% of new car sales in the U.S. in the fourth quarter of 2022 ― as a sign of ongoing growth.
Phil Jones, CEO of the Alliance for Transportation Electrification, also foresees a “hiccup” in the EV market as automakers adjust to the new guidelines and focus on domestic supply chains. “There will be some slowdowns for certain vehicles and certain manufacturers, obviously, because consumers are price-sensitive,” Jones said in an interview with NetZero Insider.
“But I don’t think it’s going to be significant,” he said. “There’s so much pent-up demand for these vehicles out there, and the major issues, in my view … it’s chips; it’s semiconductors; it’s components of an automobile other than the battery.”
PJM presented the specifics of its initial proposal to overhaul the capacity market through the critical issue fast path (CIFP) process on Wednesday, addressing looming resource adequacy concerns brought by the Board of Managers.
Some of the core components include shifting to a new reliability requirement metric, a marginal accreditation framework that models risk for every hour of the year, creating a separate winter accreditation structure and a new model for assessing and valuing generator performance.
The presentation was part of the first stage of the CIFP process, in which PJM and stakeholders are introducing their packages. Several stakeholder proposals are also being carried over from the capacity market discussions previously held by the Resource Adequacy Senior Task Force (RASTF), which is being converted to the CIFP process. (See PJM, Stakeholders Present Initial Capacity Market Proposals to RASTF.)
The PJM proposal would switch the reliability requirement metric to be based on expected unserved load (EUE), a measure of how many customers are without power and for how long, from the current loss-of-load expectation (LOLE), a count of the frequency of outages. Taking the scale of outages into account will be increasingly important as the risk of extreme weather grows, PJM’s Patrick Bruno said.
The threshold for an EUE value to meet the reliability requirement would be based on an equivalent to the 1-in-10-year LOLE standard for the RTO and a corresponding equivalent for locational deliverability areas (LDAs), which have a stricter reliability requirement.
Vistra’s Erik Heinle questioned if EUE could include additional parameters beyond a specified number of unserved hours, such as capping the length of a potential outage. Bruno said adding components would increase complexity, but that it’s a conversation worth having.
The proposed risk modeling would exclude imports from PJM’s analysis of the resources needed to meet its reliability metric, which PJM’s Patricio Rocha-Garrido said reflects a belief that surrounding RTOs are likely to be experiencing many of the same reliability challenges.
“There’s a degree of uncertainty around all these inputs for our neighbors … and that’s to a large extent driving our initial proposal on not counting on emergency imports,” he said.
James Wilson, a consultant for state consumer advocates, said excluding imports from other regions reflects a deterministic approach to resource adequacy analysis, inconsistent with PJM’s probabilistic approach.
Susan Bruce, representing the PJM Industrial Customer Coalition, said the capacity benefit margin, which is a value of the ties between regions, has long been a central component in determining resource adequacy. Eliminating its consideration would notably increase the amount of generation required, she said.
New Accreditation Framework
The marginal accreditation framework would model risk for each hour of the year under thousands of conditions and credit individual resources for their contribution to mitigating those risks. Resources’ unforced capacity (UCAP) contribution would be determined by taking their expected performance over the course of a given month multiplied by the risk expected in that period. Those monthly values would be averaged to reach an annual UCAP for the generator.
Walter Graf, PJM | FERC
PJM’s Walter Graf said the new model would allow for an evaluation of the value resources provided compared to a “perfect resource” available all year. PJM is aware that the proposed method of calculating annual UCAP would not reflect the monthly differences in output, Graf said.
“We at no point forget that this resource doesn’t contribute very much during certain months,” he said.
PJM also suggested implementing a stricter winterization standard, which resources would have to reach to avoid a zero accreditation value for those months. The winterization requirements PJM supports would use stricter alternatives the ISO/RTO Council proposed to the NERC minimum requirements.
The proposal would create a two-tiered system for setting assessment periods, with differing nonperformance charges. The first tier would operate similar to status quo performance assessment intervals, being tied to intervals where there is a real-time reserve shortage and emergency conditions beyond the deployment of pre-emergency demand response.
The second tier would be implemented when there are fewer than 360 tier 1 intervals in a delivery year and would add in the tightest real-time operating reserve intervals to reach 360 intervals for the year. The methodology would ensure that there are a minimum number of assessment periods each year to provide sufficient data to evaluate generator performance.
Penalty charges for tier 1 would maintain the current calculation based on net cost of new entry (CONE), while tier 2 would use the weighted average resource clearing price. The annual stop loss would be based on annual capacity revenues rather than net CONE, with the cap at 1.5 times a resource’s annual capacity revenues for tier 1 intervals. Tier 2 would be capped at annual capacity revenues.
The proposal would also seek to base the performance expectations underlying the penalties on generators’ monthly ratings under the marginal framework.
All capacity resources, including intermittents, would be subject to penalties under the proposal, even under weather conditions when wind or solar are not able to produce power. Ken Foladare of Tangibl Group said that provision would likely lead to those resources viewing the capacity market as being too risky to participate in.
Jason Barker of Vitol said he suspects that the tier 2 penalty structure could suppress energy prices and lead to increased uplift payments.
Longer Weather Lookback
The proposal would extend the lookback period for the weather history it incorporates in its reliability modeling to at least 50 years. Several stakeholders questioned whether a longer lookback period could lead to a less accurate forecast of the expected increase in severe weather in future years.
Steve Lieberman of American Municipal Power said a longer lookback period could be helpful with providing more data on how forced outage rates vary with temperature. But he said expanding historical data for evaluating risk could undervalue current trends.
“Is what you’re getting of value? … What you’re saying here, it sounds good, but will the results have any meaning to what is on the system today and tomorrow?” he asked.
Wilson said many utilities have been moving in the opposite direction and shrinking their historical weather history to recognize that recent weather is likely to better resemble future expectations.
Next Steps in CIFP Process
The second phase of the CIFP process, which will run April 19 through May, will have stakeholders taking a more detailed look at all proposals. Stakeholders and PJM will work to finalize packages through stage three in June and July, followed by a final CIFP meeting scheduled for Aug. 23, where the Members Committee will vote on each proposal.
PJM’s Dave Anders stressed that the second and third stage are fluid and proposals can continue to be made or significantly altered throughout both phases. Stakeholders raised concerns that the report PJM plans to release on the December 2022 winter storm will not be available until the end of the process. (See “PJM Gives Update on December Winter Storm Report,” PJM MRC/MC Briefs: March. 22, 2023)
“We’re going to have half of our CIFP meetings, all of stage one and all of stage two, … that will be concluded before we have that report. And I think that report could very well be a significant driver” to the proposals, Lieberman said. “With this piece of the puzzle not available to us, I question whether this schedule really works or if we should reconsider how we get to Oct. 1.”
PJM’s Adam Keech said many of the major findings in the report will be presented during a “lessons learned” presentation being planned for the CIFP meeting on May 17. Anders stated that if additional discussion is needed to incorporate the study’s findings, more meetings can be added.
PJM will pay $140,000 to ReliabilityFirst as part of a settlement for violations of NERC reliability standards at several facilities — including two nuclear plants, FERC ruled on Thursday (NP23-13).
NERC submitted the penalties Feb. 28 in its monthly Spreadsheet Notice of Penalty. The commission said it would not review the settlement further, leaving the penalty intact. It also approved a further notice of penalty for violations of NERC’s Critical Infrastructure Protection (CIP) standards, although details about this settlement including the entities involved and the location were not disclosed in accordance with NERC and FERC’s policy on CIP standard violations (NP23-12).
Nuclear Limits Neglected
PJM’s settlement stems from violations of two standards: NUC-001-3 (Nuclear plant interface coordination) and TOP-001-4 (Transmission operations). The RTO self-reported the first infringement in its capacity as transmission operator (TOP), balancing authority and reliability coordinator, and the second as a TOP alone.
Requirement R4 of NUC-001-3 mandates that TOPs incorporate nuclear plant interface requirements (NPIR) — a set of requirements based on nuclear licensing requirements that are mutually agreed on by the nuclear generator operator and applicable transmission entities — into their operating analyses of the electric grid. The same standard requires a TOP to operate the electric system to meet the NPIRs and inform a nuclear plant operator when it has lost the ability to assess the operation of the electric system.
PJM failed to incorporate the NPIRs into its operating analysis while building its fall 2019 energy management system (EMS) model, when a software flaw corrupted the NPIR voltage drop limit tables for the Dresden and Quad Cities nuclear plants in Illinois. No other nuclear stations in the region were affected.
The RTO implemented the fall model build into the EMS on Sept 24, 2019; the incorrect limits were discovered on Nov. 27, at which point PJM manually adjust the EMS to replace the limits. At this point RF assessed the violation as over.
RF noted that PJM’s post-contingency analysis was still solving for the duration of the noncompliance and the entity voltage drop limits were still valid, apart from the NPIR limits. PJM used historical data to rerun the post-contingency voltage drop analysis after the fact with valid NPIR limits, confirming that there were no limit exceedances throughout the noncompliance.
RF determined the root cause of the violation to be a lack of adequate process or internal control to ensure the NPIR voltage drop limits were correct. The regional entity said the violation posed a moderate risk to grid reliability, observing that a lack of awareness into whether NPIRs are being met can leave operators without adequate transparency into plant stability. On the other hand, RF acknowledged that even with the faulty NPIR information the operating analyses still solved, and providing “some visibility” was better than nothing.
To mitigate the violation, PJM added additional peer checking into the model build process along with “verifying valid NPIR voltage drop limits,” and updated the EMS code to identify corrupt data during the model build process.
FirstEnergy Violation Leads to PJM Infringement
PJM’s violation of TOP-001-4 stems from requirement R18, which requires TOPs to “operate to the most limiting parameter where there is a difference in SOLs [system operating limits].”
The infringement began on Nov. 1, 2019, when maintenance on the Keystone-South Bend line caused flow to be isolated to a single breaker. With only a single terminal breaker in service, the breaker rating “became more limiting than that of the associated line.”
While the transmission owner (TO), FirstEnergy Utilities, had modeled this scenario in its EMS, PJM had not because the TO had not communicated to the RTO that the maintenance had caused the breaker’s “abnormal configuration ratings”— a violation in its own right that RF addressed last year in a separate settlement. (See FirstEnergy to Pay $700K Penalty to ReliabilityFirst.)
While FirstEnergy did call PJM the same day to inform it of the ratings issues, the RTO did not immediately update the breaker rating in EMS. Instead, it spent three days attempting to “assess the discrepancy” with FirstEnergy before finally updating the rating on Nov. 4, ending the violation.
RF said the root cause of the infringement was a lack of adequate process or effective mechanism for changing ratings on breakers. PJM had no ability to manually change the breaker’s rating directly, and staff did not realize that they could address the situation by reducing the rating on the affected line. On the other hand, RF said the violation did not pose a serious or substantial risk to grid reliability because PJM had other means of addressing a potential overload.
PJM’s mitigation measures included verifying and validating all flow circuit breakers within FirstEnergy’s territory and reviewing its manual to ensure TO responsibilities for updating flow breakers are clearly outlined. It also conducted training with its own staff and those of associated TOs to ensure they understand the risks of noncompliance.
SACRAMENTO, Calif. — Careful utility rate design could lessen the impact on ratepayers of California’s expensive efforts to reach 100% clean energy and harden the grid against wildfires, panelists said at last week’s RE+ Northern California conference, sponsored by the Solar Energy Industries Association (SEIA) and Smart Electric Power Alliance (SEPA).
The panel addressed the state’s steeply increasing utility bills, which are projected to keep rising in coming years. Much of the increases are to pay for the costs of new generation and distribution and transmission system upgrades, the California Public Utilities Commission said in its 2022 annual report to the governor and legislature on actions to limit rate increases.
“Increasingly, there’s a big chunk of the utility bill that involves costs that are unaffected by usage, unaffected by customer demand,” said Matthew Freedman, staff attorney at ratepayer watchdog The Utility Reform Network (TURN). “When utilities spend a lot of money on wildfire mitigation, whether you reduce your usage or increase your usage in a given area has no effect on the wildfire mitigation costs, on the wildfire liability insurance costs, on a lot of the grid hardening that’s being done — and of course [on] a lot of the public purpose programs and other policy initiatives where costs are included in rates.”
TURN backed last year’s Assembly Bill 205, which included a requirement that the CPUC establish income-graduated fixed charges “so that a low-income ratepayer … would realize a lower average monthly bill without making any changes in usage.” The CPUC has asked parties to file opening testimony in its proceedings to implement the measure by March 7.
“We think it makes sense to do a fixed charge as long as you can differentiate it [by income], and to think about how that fits with other rate design strategies that will allow us to promote electrification in a rational manner,” Freedman said.
Julia Pyper, vice president of public affairs for GoodLeap, a financing company for rooftop solar and other green home improvements, said her firm also supported AB 205’s income-tiered fixed charges but has concerns about how the CPUC will implement them. Lowering electric bills for some customers could dissuade them from investing in energy upgrades, she said.
“Are we talking about 80 bucks a month? Are we talking $10 a month?” Pyper asked. “We’re all kind of in agreement that this was a good direction to go in, but so much will come down … to where that charge lands. Because if you take away all incentives for the customer to take action, then we can’t engage them in decarbonization efforts.”
‘Critical Enabler’
Jeanne Armstrong, senior regulatory counsel with SEIA, said income-tiered fixed charges “could ease the pressure on low-income customers in the short term” but finding ways to reduce utility costs remains vital.
“In the long term, if you don’t actually bring down the costs, you’re going to reach a crisis point again,” Armstrong said.
“I’m going to give an example,” she said. “Back in the early 2000s, when California had an energy crisis and … electricity bills [went] through the roof,” the legislature passed emergency legislation that directed the CPUC to “not raise rates in the first two tiers of what then was a five-tier utility rate structure. So, all the revenue increases went into tiers three through five, and lo and behold, those skyrocketed.”
The CPUC and legislature eventually revamped the rate structure.
“They brought five tiers down to two … and things were good again for a while, and we went on our merry way,” she said. But “because costs weren’t reined in, we’re once again having an affordability crisis. So, I think in the short term, this income-tiered fixed charge can help, but if we don’t do something on the cost in the long term, it won’t.”
Michael Backstrom, vice president of regulatory affairs for Southern California Edison, responded, “I’ll respectfully disagree.”
“I think that it is both a short-term and a long-term benefit to have a fixed-charge structure in electricity bills because of where we want to go from a decarbonization standpoint,” Backstrom said. “Perpetuating the system we have today, where all costs just get loaded into a per-kilowatt-hour charge, does not reflect the idea that in the long run, to achieve our decarbonization goals, we are going to want the customer to be more interested,” in investing in transportation and building decarbonization. “So having a sustainable rate structure [that includes] a fixed charge is going to be a pretty critical enabler.”
Reducing bills by 10 to 20% for low-income customers will “give those same customers the opportunity to adopt electrification technologies that are going to be very helpful to them, and that are better for the local region and reducing air pollution,” he said. “Does it solve the affordability issue? No. But it will be a big, big, big benefit in getting us into the right area.”
Joseph Eto | Lawrence Berkeley National Laboratory
California Gov. Gavin Newsom on Thursday appointed Joseph Eto, a staff scientist at the Lawrence Berkeley National Laboratory, to fill a vacant seat on the CAISO Board of Governors.
Eto is a senior adviser to the Electricity Markets and Policy Department at Lawrence Berkeley, where he has worked since 1982, according to his online biography.
“Joe has authored over 250 publications on electricity reliability, transmission planning and operations, demand response, distributed generation, utility integrated resource planning and demand-side management, and building energy-efficiency technologies,” his biography on the lab’s website says.
“Between 1999 and 2020 Joe led the program office for the Consortium for Electric Reliability Technology Solutions, which was a national laboratory-university-industry R&D consortium founded by Lawrence Berkeley National Laboratory, Oak Ridge National Laboratory, Pacific Northwest National Laboratory, Sandia National Laboratories, the National Science Foundation’s Power System Engineering Research Center, and the Electric Power Group that conducted research and analysis on electricity reliability and transmission technologies,” it says.
He holds a bachelor’s degree in the philosophy of science and a master’s degree in energy and resources from the University of California, Berkeley, and is a registered mechanical engineer.
Eto and CAISO did not respond to requests for comment in time for this story.
Eto fills a vacancy created when CAISO Governor Ashutosh Bhagwat opted not to seek another term after 12 years of service. Bhagwat chaired the Board of Governors last year; his most recent term ended Dec. 31.
“It has been a truly fantastic 12-year run, like nothing else I’ve had in my life,” Bhagwat said during the board’s last meeting of the year on Dec 15. “I’ve enjoyed it thoroughly.”
The state Senate must confirm Eto, who will earn $40,000 per year as a member of the Board of Governors in addition to per diem meeting preparation and attendance costs. His term will end Dec. 31, 2025, according to CAISO’s board roster.
Grid-enhancing technologies (GETs) can help open space on the electric grid to interconnect additional renewables more quickly than building new transmission, industry experts said during a webinar Monday.
The American Council on Renewable Energy and the WATT Coalition hosted the webinar, which was moderated by RTO Insider Editor-in-Chief Rich Heidorn, Jr.
Dynamic line ratings, advanced power controls and topology optimization software can all help wring the maximum performance of transmission lines, reducing both congestion and renewable curtailments, said WATT Coalition Executive Director Julia Selker.
Transmission capacity is currently based on a line’s static rating, which assumes a hot day with low wind speed. But dynamic line ratings (DLRs) take into consideration actual conditions, which results in higher line capacity about 85% of the time. In winter, dynamic line ratings add from 9% to 33% more capacity, while summer capacities can increase by 26% to 36%.
DLRs can also inform operators when a line is overstressed and they should reduce power below its static rating, Selker said.
FERC Order 881, issued in 2021, requires grid operators to adopt use of ambient adjusted line ratings, which factor in temperatures and time of day.
“But, really, windspeed and other factors are a big deal,” Selker said. “And one study of DLR versus ambient adjusted ratings in Texas showed that DLR had twice the value for climate and cost savings.”
Advanced power flow technologies are added to substations and give operators the ability to send power over specific transmission lines, thus minimizing congestion and curtailments, she added.
Topology optimization is software that examines where generation and load are on the grid at each moment and develops the best solution to minimize congestion, said Selker.
Transmission congestion costs reached $13 billion in 2021, based on reports from the nation’s grid operators.
“We think grid-enhancing technologies can reduce that congestion impact significantly, maybe 30% or so,” Selker said.
High costs for required transmission upgrades often force generation developers to withdraw their proposal altogether as they become uneconomic, said Arash Ghodsian, Invenergy vice president of transmission and policy.
“The queue sizes are significantly growing and, you know, there’s the optics of having speculative projects in the queue,” he said. “While that may be true, we’ve also seen many areas in the queue processes across the country where overloads could have been addressed by implementing grid-enhancing technology applications to reduce congestion and improve reliability.”
Invenergy has seen instances when generation projects lead to a 3% overload of a transmission line, requiring developers to pay as much as $50 million to build out new lines, while DLRs or other GETs would have fixed the issue entirely at a fraction of the cost, said Ghodsian.
While centrally planned lines can take years to build, GETs can be added in the meantime so that renewable development does not need to come to a halt waiting for new transmission to be built, he said.
Cheap, Quick
GETs can help ensure development of the kind of strong grid needed to decarbonize the power industry affordably and reliably, Minnesota Public Utilities Commissioner Matt Schuerger said.
“Planning is underway for new transmission, but clearly development, permitting, and construction takes time,” Schuerger said.
Ratepayers have paid for transmission lines, which should be used to their fullest extent even though significant new transmission must be built, he added.
EDF Renewables Senior Director of Transmission Policy Temujin Roach said the main thing that GETs do is to cut congestion, and while no grid will ever be gold-plated enough to eliminate congestion, reducing it provides major benefits for customers.
MISO has experienced significant congestion, which is expected to continue to grow. High natural gas prices have contributed to the recent rise in congestion, but even if those costs drop, GETs would still benefit consumers, Roach said. But proposals to use the new technologies have met with skepticism from utility employees who want to operate their systems more conservatively.
“We get a lot of pushback from transmission owners that don’t understand it and see it as a deconstruction of the system and get uncomfortable and concerned about that,” Roach said.
While GETs represent promising technologies that have been discussed for years, they have only seen limited use in this country, which varies significantly by region.
“The WATT Coalition sees an incentive misalignment as one of the primary issues,” said Selker. “Transmission owners today — their business model is about return on equity. It’s about building big transmission projects and getting a return on those large expenditures, and GETS just don’t really fit in that model. They’re cheap, they’re quick, they don’t make a substantial difference on that balance sheet.”
FERC Approves Public Service Colorado’s WEIS Market Participation
FERC on Friday approved Public Service Company of Colorado’s (PSCo) request to participate in SPP’s Western Energy Imbalance Service (WEIS) market and revisions to its market-based rate tariff (ER23-949).
The commission accepted PSCo’s change in status to join the WEIS market and found that it meets its requirements for both horizontal and vertical market power. Last April, FERC accepted PSCo’s Western joint dispatch agreement with SPP that establishes the legal relationship between SPP and its market participants.
FERC’s March 31 order directed the utility to file in 15 months a market-based rate change in status filing that includes an ex post analysis with 12 months of price separation data to help determine whether the PSCo balancing authority area has become a submarket of the WEIS market.
It also directed the utility to include a price separation analysis between the WEIS market and the PSCo BA in its future Northwest region triennial filings.
“PSCo’s participation in the WEIS market raises concerns of whether the PSCo balancing authority area could become a submarket of the WEIS market,” the commission wrote.
FERC’s approval was effective April 1. PSCo, a subsidiary of Xcel Energy (NASDAQ:XEL), is the WEIS market’s 10th participant. The Western Area Power Administration participates in three of its five regions.
SPP began administering the market on a contract basis in 2021. WEIS centrally dispatches energy from participating resources throughout the region every five minutes.
SPP, MISO Staff Honored for Collaboration
The Energy Systems Integration Group (ESIG) has recognized SPP and MISO staffers as recipients of its 2023 Excellence Awards for their work on the RTOs’ Joint Targeted Interconnection Queue (JTIQ) study.
SPP’s Antoine Lucas, Clint Savoy, David Kelley and Kelsey Allen
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SPP
The grid operators’ staffs were honored for “identifying significant transmission limitations near the SPP-MISO seam” during the study. Their work resulted in five projects that could help reduce congestion and allow additional resources, primarily wind farms, to interconnect with their systems.
Antoine Lucas, SPP’s vice president of engineering, was recognized along with David Kelley, Kelsey Allen and Clint Savoy.
MISO’s honorees were Aubrey Johnson, vice president of system planning, and Andy Witmeier, Sumit Brar and Jeremy Nash.
SPP and MISO are collaborating with the Minnesota Department of Commerce and the Great Plains Institute to seek funding from a Department of Energy program to help cover up to half of the JTIQ portfolio’s $1.06 billion estimated cost. (See DOE Clears JTIQ Projects to Proceed with Funding App.)
The awards recognize global energy professionals for their contributions and accomplishments toward the planning and operation of energy systems in ways that are reliable, economic and sustainable. They were presented during the ESIG’s annual Spring Technical Workshop March 29 in Tucson, Arizona.
Other recipients included Grid United CEO Michael Skelly for his “pioneering efforts to build transmission infrastructure to unlock the nation’s wind energy resources.”
Tri-State Generation & Transmission Association’s Mary Ann Zehr and WAPA’s Lloyd Linke received awards for their service to the ESIG’s Board of Directors and its Advisory Council, respectively.
Little Rock HQ Undamaged in Storms
SPP’s headquarters in Little Rock, Arkansas, escaped damage during a tornado that touched down “just blocks away” Friday as a deadly outbreak of storms ravaged the South and Midwest.
More than 50 confirmed twisters touched down in the region, killing at least 32 people. Another round of storms is expected in the same region Tuesday.
“SPP is saddened by the devastation to our community caused by yesterday’s storms,” SPP tweeted Saturday. “We look forward to joining in restoration efforts and doing our part to serve.”
PORTSMOUTH, N.H. — The first meeting of a new era for ISO-NE’s Consumer Liaison Group featured few fireworks but plenty of substantive discussion of the challenges facing New England’s energy transition.
The CLG, a forum for connecting the RTO with the public, met Thursday, its first gathering since a December vote in which six climate activists were elected to its coordinating committee. (See Climate Activists Take Over Small Piece of ISO-NE.)
“Like the Red Sox, the Consumer Liaison Group is experiencing a reset,” said Donald Kreis, a coordinating committee member and the state of New Hampshire’s Consumer Advocate. “Our record is no wins and no losses. It’s a new day at the CLG, and there’s reason to be optimistic about making consumers have a stronger and better liaison to our grid operator.”
Dan Dolan, president of the New England Power Generators Association, laid out what he sees as the stakes for decarbonization in the region.
“The responsibility we have in New England … is to create a demonstration to other parts of the country and the world that you can move forward on a decarbonized future in a way that promotes economic prosperity, [that it] can be done in a resilient, reliable fashion and maintains affordability for the consumers,” Dolan said.
A running theme of the meeting was identifying areas of agreement between ISO-NE, which has been criticized for moving too slowly on greening the region’s energy mix, and those outside who have been pushing it for years.
“The ISO recognizes that climate change is happening right now, and that we need to reduce carbon emissions to solve this problem,” said Susan Muller, a senior energy analyst at the Union of Concerned Scientists, who spoke on a panel during the meeting.
“It’s really important common ground, and I know there’s a struggle right now to find common ground,” she said.
But where Muller argued the grid operator has not caught up to public sentiment is on the time constraints of climate change, which she said call for rapid action.
“We’re concerned that without the time constraints being factored in, we’ll perpetuate the situation, and we don’t have a lot of time,” she said.
Anne George, ISO-NE’s vice president of external affairs, represented the organization at the meeting, as she’s done many times before. She gave a rundown of key issues facing the RTO, including its recently completed Forward Capacity Auction and two capacity deficiency events from the past winter that have raised questions about New England’s grid in cold weather.
Bob Ethier, a vice president for system planning at ISO-NE, also presented during the event.
“The big thing that I want to convey today is what we are doing to facilitate the transition to clean energy,” he said.
Among those efforts: “a heck of a lot of studies,” as well as providing technical expertise, working on transmission development and supporting interconnection, Ethier said.
Several speakers pointed to siting as another major challenge for the clean energy transition.
New Hampshire State Rep. Michael Harrington, a Republican and self-described “climate realist,” said that New Englanders have shown they’ll fight tooth and nail to prevent projects from being built in their backyards, pointing to the slow progress of the Northern Pass transmission line as one example.
“What’s the message that New England’s sending to the rest of the business world out there? Don’t come here and build anything because we don’t want anything built,” he said.
New Hampshire itself is in a unique position in the region, as multiple panelists noted. Its progress on renewable energy has been slower than in surrounding states, even as the price of that energy has plummeted.
“While right now we might be sort of free riding off the policies of the states around us, pretty soon it means we’re going to be missing the boat,” said Sam Evans-Brown, executive director of Clean Energy New Hampshire.
Michael Giberson, R Street Institute | R Street Institute
By Michael Giberson
FERC must look beyond reliability standards to boost electric industry winter readiness.
Winter Storm Elliott smashed into the Southeastern U.S. last year at just the wrong time, right before Christmas, disrupting both long-planned travel and last-minute holiday shopping. It was a bad time for the affected region’s electric utilities too, as power generators struggled under freezing temperatures while customer demand rose to winter records.
Duke Energy in North Carolina and the Tennessee Valley Authority (TVA) had to cut power to some consumers to help keep the grid from failing. For both power companies, it was the first time they had to employ these extreme reliability measures.
A few days later, FERC, NERC and NERC regional entities announced they would investigate operations of the bulk-power system during the storm. A report will emerge in a few months with useful details on which components failed and which reliability standards were not well enforced. But one may wonder what we can learn from the fifth such joint investigation that was not obvious from the previous four winter storm investigations.
The fourth FERC-NERC winter storm report, examining February 2021’s Winter Storm Uri, summarized the main finding of the earlier three. What have we learned? Small equipment failures — the freezing up of a gauge or a sensing line — can sideline a generating unit; gas supply interruptions were an issue; generation owners sometimes failed to prepare adequately; operators lacked training for extreme winter weather conditions; and utilities need to improve emergency communication practices. All four reports observe these kinds of failures and make similar recommendations.
Coincidentally, in February FERC approved winter reliability standards that address about half of the recommendations from the fourth FERC-NERC winter storm report. The standards are a step forward, said FERC Commissioner Mark Christie, “but the much bigger issue to me is market design.” Does it still support reliability?
The interaction of reliability and markets has always been a concern within restructured regions. Revenue from energy, ancillary service and capacity markets is intended to incentivize enough investment that supply can reliably meet customer demand under a wide range of conditions. Emergency operations help maintain service in extreme cases. At least those are market design goals.
But as has been discovered over and over, emergency operations can undermine market incentives supporting resource adequacy. For example, an RTO might call on demand response resources to help maintain a safe level of operating reserves. If the RTO market interpreted reduction in load as falling consumer demand, then prices fall at a time when resources are exceptionally scarce. The price suppressing potential of demand response programs was uncovered in RTOs a decade ago, but similar problems continue to emerge.
This sort of fine-grained market design work is essential to refining RTO systems. However, the sheer scale of some winter storms suggests attention to the bigger picture is needed too. Texas, the biggest state of the lower 48, was smaller than the winter storms that struck it in February 2011 and February 2021. Even PJM and MISO, the two largest of the RTOs in terms of generating capacity, are too small to handle the biggest winter storms alone. Winter storm readiness requires more extensive and effective interregional ties between RTOs and their neighbors.
Interregional Interties
This feature of the winter challenge leads to the first of two recommendations for winter readiness that go beyond the scope of FERC-NERC investigations: FERC should make interregional transmission projects a high priority. In the just released draft National Transmission Needs Study, the U.S. Department of Energy (DOE) identified over 50 recent transmission needs studies conducted by a wide range of organizations. The draft report concludes that significant system resilience, reliability and economic benefits can be expected from expanded interregional transfer capacity.
Particularly significant, as indicated by the DOE’s report, are expanded interties between the Western and Eastern interconnection in the Plains states and interties between ERCOT to both the west and east. A study by Grid Strategies and the American Council on Renewable Energy concluded “modest investments in interregional transmission capacity would have yielded nearly $100 million in benefits during the five-day event, while most areas could have saved tens of millions of dollars.” A transmission line connecting ERCOT to utilities in the Southeast could have saved lives in Texas during Winter Storm Uri and saved consumers at least $1 billion in energy bills.
Winter Storm Elliott makes clear the need for better interregional coordination beyond RTOs, both for interregional transmission planning and for everyday operations. Utilities in the Southeast region launched a trading platform in 2022 — the Southeast Energy Exchange Market (SEEM) — to help them share excess supplies. When the storm came, however, buying opportunities on SEEM disappeared. PJM and MISO both sent power into the southeast during the storm that helped limit the use of rolling outages in the area.
The Western Energy Imbalance Market (WEIM), operated by CAISO, has not yet been hit by winter storms comparable to Elliott. However, during the August 2020 heat wave, resources participating in WEIM were able to sell into CAISO and helped limit involuntary load shedding in California. The contrasting performance of markets in non-RTO regions may be reason for FERC to take another look at SEEM’s market design. In all regions, RTO or non-RTO, reliability advantages of interregional transmission will remain untapped without a functional regulatory framework that lets private capital flow.
Load Responsiveness
A second general recommendation calls for a renewed emphasis on demand-side engagement in power markets. The new reliability rules approved by FERC in February will require utilities to separate out protected circuits — hospitals, police and fire stations, and circuits providing other reliability protections — from other customers. The move will help ensure the high cost of involuntary load shedding is spread more evenly. However, technology now allows widespread participation in voluntary economic and emergency demand response programs.
PJM deployed cuts of up to 7,000 MW through voluntary load management programs during Elliott. These programs were one reason PJM could avoid involuntary load shedding when demand came in above forecast and generating units were failing at unexpectedly high rates. In addition to RTO programs, companies like Tesla, Sunnova, OhmConnect and Octopus Energy are implementing voluntary consumer response programs that can aid RTOs during periods of grid stress. It is much better for a few thousand customers to reduce use by 1 or 2% than have a few customers unwillingly cut off 100%.
FERC policy endorses active load-side participation in RTO markets, but the limited reach of existing programs, the high cost of involuntary load shedding and promise suggested by new programs mean now is a good time for more focus on customer engagement. Load shedding for bulk system reliability can be reduced by innovative, voluntary retail customer programs. As such efforts span wholesale and retail sectors, state and FERC commissioners should establish a joint effort to reduce involuntary load shedding by better enabling voluntary customer response programs.
Conclusion
Commissioner Christie was on to something when he raised questions about institutional design in the context of winter weather failures, which is outside the scope of FERC-NERC reliability investigations. Reliability assessments are missing some of the biggest aspects of prudent reliability policy. Notably, robust interregional transmission, active demand-side participation and healthy regional market design play key roles in meeting customer needs during extreme winter weather.
Some of the necessary work is simply ensuring emergency operations do not inadvertently undermine incentives to invest in winter readiness. Better mobilizing voluntary consumer responses can substantially reduce the need for involuntary cutoffs. Another part is ensuring effective mobilization of resources on a scale large enough to match winter threats. For example, FERC or Congress could establish interregional planning requirements and remove regulatory barriers to merchant developers to kickstart a woefully underdeveloped system. Competitive, interconnected markets are a reliability imperative.
Michael Giberson is a senior fellow with R Street Institute’s Energy & Environmental Policy Team.
