PJM presented a draft proposal to delay the next four Base Residual Auctions (BRAs) to the Members Committee during a special meeting on Tuesday.
The alternative schedule would move the 2025/26 auction, currently scheduled for this June, to June 2024; the following three auctions would be held every sixth months thereafter. Auctions would return to their regular timing of being held three years in advance of the 2029/30 BRA, which would be held in May 2026. (See PJM Board of Managers to Seek Capacity Auction Delays.)
The tightened schedule would also continue the current practice of canceling incremental auctions (IAs) when they take place within 10 months of the BRA or would be within the same year as the corresponding delivery year. The first two IAs for the 2025/26 auction and following year’s would be canceled, leaving only the third IA in place. Two IAs would be held in the 2027/28 and 2028/29 delivery years, before going back to the normal three per year.
PJM’s tariff requires that it consult with the MC and Transmission Owners Agreement-Administrative Committee (TOA-AC) at least seven days prior to making a Federal Power Act Section 205 filing with FERC. The TOA-AC, whose meetings are closed to the public, met on Tuesday after the MC.
Pre-auction activities will continue until PJM has received an order from FERC to ensure that the 2025/26 BRA can still be held in June should the commission reject the filing. Should the commission approve the filing, PJM’s Tim Horger said those activities will be rerun leading up to the auction’s new date.
Horger said the filing is based on the premise that FERC will approve the capacity market overhaul that the Board of Managers plans to approve and have filed by Oct. 1 within 60 days. If the commission were to take longer and reach a decision as late as March, Horger presented a potential alternative that would delay the 2025/26 BRA to October 2024 and delay the following four auctions. The schedule would go back to normal with the 2030/31 auction in May 2027.
The draft filing shown to the MC only seeks the capability to change the timing of auctions through the 2028/29 delivery year, necessitating an additional FERC filing for the alternative Horger presented.
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said requiring a filing by Oct. 1 and setting June 2024 in stone for the 2025/26 BRA would limit stakeholders’ ability to extend discussions on capacity market changes through the Critical Issue Fast Path (CIFP) process. He noted that PJM has delayed the release of its report on the December 2022 winter storm to July, which he argued also leaves little time for review and to incorporate findings into proposals. (See PJM Presents More Detail on CIFP Proposal.)
The report will be especially important for state consumer advocates, Poulos said, as they are not market participants and lack the insight into the storm’s impact that those directly affected by it possess. A short timeline for making these decisions could put advocates in the position of voting on proposals to recommend to the board without having all the necessary information, he said.
Poulos also questioned whether there is a plan for how PJM would act if FERC approves the auction delay but ultimately rejects the eventual capacity market proposal.
Horger responded that PJM is aware of that possibility and that the risk will have to be addressed should it manifest.
Vistra’s Erik Heinle asked if PJM will request expedited consideration of the filing to reduce the amount of pre-auction activities that market participants must engage in.
PJM Senior Counsel Chen Lu said the decision to make the filing under Section 205 was intended to reduce the amount of time to receive a determination, but PJM will consider asking for expedition.
Ian Oxenham, legal specialist for the New Jersey Board of Public Utilities, urged PJM to not seek expedited consideration, saying that it could deprive commenters of the time needed to evaluate the filing.
“PJM should be very hesitant to shorten that comment period,” he said.
Millions in new funding and bonus tax credits are heading to new clean energy projects in U.S. “energy communities” — the cities, towns and counties where the closure of coal mines, coal-fired power plants and other fossil fuel projects has meant lost jobs and tax revenue, according to Tuesday’s round of White House announcements,
Rolled out at the meeting of the Interagency Working Group on Coal and Power Plant Communities and Economic Revitalization (Energy Communities IWG), the announcements included:
new guidance from the Treasury Department on the Inflation Reduction Act’s 10% bonus credit for clean energy projects located in energy communities. A new map from Treasury and the IWG shows wide swaths of the country qualifying as energy communities, from Nevada to the Dakotas to Texas and the Mid-Atlantic coal belt in Pennsylvania, Ohio and Virginia;
$16 million in funding from the Infrastructure Investment and Jobs Act for demonstration projects in North Dakota and West Virginia that “will extract and separate rare earth elements and other critical minerals from coal ash, acid mine drainage and other mine waste,” according to a White House fact sheet;
another $450 million from the IIJA for additional clean energy demonstration projects on current and former mine lands. DOE estimates the U.S. has 17,750 mine land sites, covering 1.5 million acres, which could produce up to 90 GW of clean energy; and
an interagency memorandum of understanding that will set up rapid response teams to provide outreach and technical support to energy communities to ensure they can access funding and other opportunities.
The announcements are part of President Biden’s bigger drive to highlight the successes of his “Investing in America” agenda and the programs and projects funded by the IIJA and IRA. The IWG has “driven more than $14.1 billion in federal investments to energy communities” over the past two years, according to a report also issued Tuesday.
National Climate Adviser Ali Zaidi | Energy Communities IWG
“There’s enormous untapped potential in these communities, from fossil fuel workers whose skills we need to build the industries of the future, to existing facilities that can be retooled and repurposed, to local entrepreneurs and universities … working to attract talent and investment,” White House Senior Adviser John Podesta said at the IWG meeting.
National Climate Adviser Ali Zaidi stressed the importance of creating new jobs that will let residents stay in their coalmining communities. “It’s not just … we say, ‘Hey, we’ve got a job for you in a completely different geography,’” Zaidi said.
“It’s the places that folks have invested in, not just in this generation, but for many a culture, a community, a sense of place and purpose and dignity. That’s all embedded in geographies … places [that] will be the venue where we come up with the ideas that we forge together and implement together,” he said.
‘An Extra Dime’
The 10% bonus tax credit for energy communities could be a major draw for investment in energy communities, adding 10% on top of any other investment or production tax credits the IRA provides for clean energy projects, Treasury Secretary Janet Yellen said.
“Many energy communities have the knowledge, the infrastructure and the resources to take advantage of the clean energy transition, but in many cases these communities could benefit significantly from an initial public investment to jumpstart that process,” she said.
Treasury Secretary Janet Yellen | Energy Communities IWG
The bonus credit “generally means that if you’re a solar farm operator in a coal community, you get an extra dime on the dollar for your investment in a new facility,” Yellen said, adding that developers will also have to pay prevailing wages and have registered apprenticeship programs to take full advantage of the bonus.
The IRA provides a 30% investment tax credit or a 2.75-cent/kWh production tax credit for renewable energy projects. The impact of adding the 10% bonus credit to those incentives “is just going to be incredible,” said Tom Cormons, executive director of Appalachian Voices, a community nonprofit in Virginia. It will provide the boost needed to bring on “scores of projects that otherwise would not have penciled out or gotten over the finish line in places where it can be a little harder than others to get clean energy projects going on the ground,” he said.
The IRA provides a particularly broad definition of energy communities, and the Treasury Department guidance spells out the various ways a community can quality. Any community where a coal mine has closed since 2000, or any county adjacent to that area is identified as an energy community, as are areas where a coal-fired power plant has closed since 2010. So are “brownfield” sites where construction of any new projects or repurposing of existing infrastructure “may be complicated by the presence or potential presence of a hazardous substance, pollutant or contaminant,” the guidelines say.
Communities can also qualify if they have a minimum of .17% employment or 25% of tax revenue directly related to fossil fuel production or use and an unemployment rate higher than the national average.
Echoing Cormons, Hy Martin, chief development officer for D.E. Shaw Renewable Investment, said the IRA’s clean energy tax credits, including the 10% bonus, have “catalyzed several hundred millions of dollars in investment that we have committed to communities, specifically coal communities across the country …
“Without that kind of clear policy signal, those commitments wouldn’t have been made by us and certainly by our peers in the private sector,” Martin said.
‘Irresistible for Investment’
Energy Secretary Jennifer Granholm | Energy Communities IWG
Energy Secretary Jennifer Granholm also talked up the impact of the IRA, saying the law’s tax credits and other incentives are making energy communities “irresistible for investment.”
But Granholm’s main announcements Tuesday came with funding from the IIJA, the $16 million for the North Dakota and West Virginia demonstration projects and the $450 million for clean energy projects on mine lands.
The $16 million will be evenly split between North Dakota and West Virginia and used for “front-end engineering and design studies to determine how to extract critical minerals from coal mine waste streams, of which there are an abundant amount across the country,” Granholm said.
“Those efforts are going to help us stand up a first-of-its-kind facility that produces essential materials for solar panels, for EVs, for wind turbines … while at the same time cleaning up polluted land and water,” she said.
Sen. Joe Manchin (D-W.Va.) also welcomed the funding, saying that by reclaiming water from mining waste, “we will ensure that we are producing these materials in the cleanest way possible while addressing environmental liabilities.”
The $450 million will target projects using a “range of technologies — geothermal, energy storage, power plants [with] carbon capture,” Granholm said. “They’re going to show us how we can reactivate or repurpose existing infrastructure, like transmission lines and substations, while creating new opportunities for economic development.”
Granholm stressed that applicants chosen for this funding will also have to submit community benefit plans to ensure that projects are “designed in a way that uplifts the whole community.” Community benefits will constitute 20% of the scoring for the awards.
“We don’t think these projects are going to be successful unless they have meaningful community and worker engagement,” she said.
Concept papers for the $450 million opportunity are due May 11, with full applications to follow on Aug. 31, according to DOE.
Independent power producer Nautilus Power asked FERC to dismiss PJM’s penalties against three of its generators that failed to operate during the December 2022 winter storm, saying two of the units were not needed to address capacity shortages and that the RTO failed to implement processes to address natural gas supply constraints.
In a complaint filed March 30, the company argues that the generators had not been properly notified that they would be required to go online and that the penalties would not incentivize any behavior that could avoid future charges.
The company wholly owns Essential Power, which owns a 383-MW natural gas generator in Lakewood, New Jersey, and Essential Power Rock Springs, which owns a 773-MW gas-fired generator in Rising Sun, Maryland. It has majority ownership of Lakewood Cogeneration, which owns a 237-MW generator with dual fuel capability. All three plants were hit with penalties related to Winter Storm Elliott on Dec. 23 and 24 (EL23-53).
“Under these circumstances, where the adverse impact to PJM was minimal, where the Nautilus Entities were not needed by PJM during many intervals of both [performance assessment intervals], where PJM itself failed to follow its own emergency procedures and therefore prejudiced the Nautilus Entities’ ability to respond to PJM directives, and where the imposition of nonperformance charges on the Nautilus Entities will impose a significant economic burden on the Nautilus Entities, the nonperformance charges that PJM intends to impose on the Nautilus entities are unjust and unreasonable,” the complaint states.
PJM has stated that it expects at least $1 billion in capacity performance penalties to be assigned to generators following a peak of 46,000 MW of outages during Winter Storm Elliott, with the single largest cause being gas-fired generators being unable to procure fuel. PJM and stakeholders have raised concern that the scale of the penalties could lead to widespread defaults, leading PJM to ask FERC to permit a longer payment period of up to nine months. (See PJM Weighs Options for Winter Storm Elliott Follow-up.)
All three generators listed in the complaint had not cleared in the day-ahead market and were not listed as being required in the reliability assessment and commitment (RAC) period and were unable to obtain fuel when they were called on by PJM to operate during the storm. Though the Lakewood generator possesses dual fuel capability, it was not able to procure the natural gas it needs for startup.
The complaint requests that FERC prevent PJM from assessing nonperformance charges to Essential Power and Rock Springs after 12 p.m. on Dec. 24, arguing that they were not needed during those periods. It also requests that Rock Springs not be subject to charges on Dec. 23 and for the first two hours of the Dec. 24 performance assessment interval (PAI), during which it states that it was not scheduled to operate.
As an alternative remedy, the complaint asks that all three generators be relieved of penalties for settlement intervals in which they were not running during both the Dec. 23 and 24 PAIs.
The argument that Essential Power and Rock Springs were not needed for reliability stems from LMPs falling around noon on the 24th, with prices being half what they were earlier in the day by 1 p.m. The complaint argues this shows that shortage conditions had alleviated and the maximum generation emergency and corresponding PAIs should have been lifted. However they remained in place until 10 p.m.
“Imposing substantial nonperformance charges on OPP and Rock Springs for nonperformance during intervals when they were not needed by PJM is highly unreasonable and arbitrary,” the complaint states.
The complaint also states that Rock Springs was not contacted for dispatch for two hours after the maximum generation emergency was initiated at 4:25 a.m. on Dec. 24, which it argued was an intentional decision by PJM dispatchers due to the likelihood that the generator coming online would have exacerbated a constraint and could have led to an outage. It noted that PJM has previously rejected self-schedule requests for that reason.
Nautilus argued that PJM failed to provide enough notice for generators to procure fuel by not declaring a winter weather alert giving generators 24 hours’ notice that they would be expected to be available. Instead it said the RTO “abruptly” jumped into emergency conditions and left gas generators to compete for limited pipeline capacity with elevated fuel costs. It argued the justification for high nonperformance penalties when the construct was proposed in 2015 was that generators would be given sufficient ability to prepare for emergencies and the risk would incentivize behaviors to avoid being charged.
“In its initial filing of the nonperformance charge proposal, PJM itself cited this progression of incremental steps as a justification for the severity of the proposal … However, in the course of the two days at issue in this complaint, PJM skipped right over these interim steps, going from a preliminary notice that a cold weather alert might be needed (that is, the cold weather advisory) straight to an emergency action,” the complaint argues.
It also said that due to firm day-ahead fuel service being sold in a package over weekends and the timing of the holiday weekend, generators would have had to purchase four days’ worth of fuel or vie for scarce single-day packages that might not be filled by pipeline operators giving preference to residential and commercial customers. Since both the PJM dispatch and the forecast the RTO relies upon, as well as pipeline operator practices, are outside of the control of generation owners, the complaint argues that the charges don’t incentivize any behavior other than potentially exiting the capacity market.
“The existing rules allow burdensome nonperformance charges to be imposed on natural gas-fired generators in circumstances where those generators have no reasonable opportunity to avoid those charges,” the complaint says.
SPP said Tuesday that 31 utilities, public interest groups and other entities have officially joined the grid operator’s effort to develop and launch its Markets+ offering in the Western Interconnection.
The parties met an April 1 deadline to execute agreements allowing their participation in the first phase of the market’s development. That effort began last month after funding reached critical mass a month ahead of schedule. (See SPP Moving Quickly on Markets+’s Development.)
The funding agreements also give the participants voting rights in the first developmental phase.
“We’re encouraged to see such a varied group of entities taking an active role in the development of Markets+,” Antoine Lucas, SPP’s vice president of markets, said in a statement. “From utilities looking to improve reliability and reduce energy costs, to public interest organizations advocating for natural resources and policy outcomes, these diverse perspectives are a benefit to the value, effectiveness and efficiency of our products and services. There’s room for all those voices to have a say in the design and implementation of our market.”
SPP said that in exploring the potential benefits of regional day-ahead and real-time markets in the West, it has worked to ensure its market design would reflect all stakeholders’ perspectives. It recently rolled out the Markets+ independent governance structure that “gives meaningful say to several key audiences.” (See SPP Unveils Markets+ Governance Structure.)
Those audiences include:
utilities that serve load or own generation and will have assets participating in Markets+;
organizations representing public interests, and other groups that won’t participate in the market but will be affected by its design and operation; and
Western states and regulatory bodies, which can nominate representatives to a state committee.
Markets+ participant and stakeholder representatives will collaborate in committees and working groups to develop market protocols and governing documents that SPP will eventually file with FERC for approval.
“SPP’s independent governance, past experience accommodating participation of federal power marketing administrations and commitment to engage with stakeholders to ensure a balanced market between buyers and sellers are all encouraging aspects of Markets+ going into this next phase of development,” Public Power Council CEO Scott Simms said. “PPC looks forward to working with SPP and other stakeholders to further develop Markets+ and to build on the promising service offering developed last year.”
New Jersey last week announced it allocated $70 million in Regional Greenhouse Gas Initiative (RGGI) funds to purchase 156 electric school buses, garbage trucks, shuttles and other heavy-duty vehicles, and began an outreach campaign to solicit public input on how to spend future funds.
The Board of Public Utilities (BPU), Department of Environmental Protection (DEP) and Economic Development Authority (EDA) on Tuesday held the first of four hearings in which agency officials laid out broad spending objectives and gave stakeholders an opportunity to voice concerns and offer ideas for future spending priorities.
The first hearing, an 80-minute online session with about a dozen speakers, was focused on clean transportation, which the latest figures from the state show accounts for 37% of its greenhouse gas emissions.
“Transportation was a major topic and our first strategic funding plan,” Helaine Barr, chief of the DEP’s Bureau of Climate Change and Clean Energy, told the meeting. “And I think that the state would like to carry that through into the next one as well.”
Future meetings will cover the broad range of clean energy topics (April 11); buildings, grid and refrigerants (April 13); and carbon sequestration (April 18).
Questions raised at the hearing included how school districts could access RGGI funding; whether the state had considered projects to reduce the reliance on private vehicles (not so far, but the suggestion could be considered, a state official said); and whether there were plans to use RGGI funds to help drivers in disadvantaged communities repair personal vehicles that failed the state’s emissions test.
Peg Hanna, assistant director of air quality monitoring and mobile sources at the DEP, said the state has not considered a project such as the last one.
“I suppose we could consider it. I’m not sure we’re going to get a big return on investment,” she said. “Our greenhouse gas-reduction goals are so ambitious that focusing on decarbonization or electrification is really our first priority.”
Touting Transportation Initiatives
The state’s announced transportation investment comes as it seeks to jumpstart the embrace of electric vehicles of all types, and the installation of vehicle charging stations statewide, through a growing portfolio of programs.
The strategies include offering incentives for EV purchases, incentives for charger installation, and vouchers for the purchase of light- and heavy-duty trucks, among the largest sources of emissions. The state legislature last year approved the creation of a $45 million program that would create a pilot project to test electric school buses in 18 school districts. That’s expected to be launched in the next couple of months, Hanna told the hearing.
The $70 million will fund the purchase of 114 school buses, eight garbage and dump trucks, 26 shuttle and transit buses, and four forklifts. The vehicles will be put to work in 20 overburdened communities across the state.
Some of the funds also will also go to four projects to bring electric ride-sharing programs to “communities that lack access to reliable transportation,” according to the state. The project will be executed with Via Transportation and Blink Mobility, both of which operate ridesharing apps; Envoy America, which schedules transportation for senior citizens; and Zipcar, the car-sharing company.
Those spending decisions were made in the first phase of RGGI expenditures, which began in 2020. But the broad principles are the same, now and into the future, said Bob Kettig, assistant director of climate change, clean energy and sustainability element for the DEP. (See NJ RGGI Spending Focuses on Transportation.)
“A key tenant of what we are stakeholdering today, and [the] mandate to be good stewards of the investment of these proceeds, is that these investments have to show this reduction in energy consumption, this reduction in greenhouse gas emissions relative to the cost of the project or program,” he said.
Shaping Future Spending
Gov. Phil Murphy (D) directed the state to return to RGGI in January 2018, after his predecessor, Chris Christie (R), pulled it out in 2012.
Since returning, the state has received about $372 million in auction funds and spent more than $240 million, leaving about $100 million not allocated, according to state officials.
The 153 projects funded include the incentivization of the purchase of 497 EVs, the planting of 17,000 trees and the restoration of 56 acres of forest, Kettig said. The money also will fund the restoration of 155 acres of wetlands. Combined the projects have avoided the emission of about 208,000 tons of carbon dioxide, he said.
The state’s RGGI scoping document released Tuesday sets out three broad funding priorities for potential initiatives from 2023 to 2025:
providing meaningful benefits to communities most affected by pollution and climate change;
sparking the electrification of different modes of transportation; and
launching the beneficial electrification and decarbonization of the residential and commercial buildings sector.
Kettig said the state is “teeing up” five broad initiatives in the next phase of RGGI fund investment. They include one to “advance healthy homes and incentivize a stronger electric grid” and another to “catalyze clean and equitable transportation.” A third seeks to strengthen the state’s forests, and a fourth promotes “blue carbon”: the capture of carbon in the ocean and coastal ecosystems by restoring marshes and other projects. The fifth initiative is to reduce the use of “highly warming refrigerants,” he said.
While transportation is the largest source of carbon emissions, electric generation accounts for 21% of state GHG emissions, and residential, commercial and industrial buildings together account for 34%.
Doug O’Malley, director for Environment New Jersey, questioned whether the state tracks how other states spend their money and whether New Jersey is “borrowing some of their best ideas.”
Officials said the state closely watches what other states do and has set up work groups to evaluate their strategies and projects.
Kettig said that although the 12 states that participate in RGGI have common policy goals, including greenhouse gas reduction, they each have their own regulatory framework that guides their investments.
“The individual funding decisions are totally within the purview of the individual states under their own policy and their own their own legal processes,” he said.
FERC last week accepted three unexecuted network upgrade agreements for wind farms in the Dakotas and Minnesota, filed by MISO interconnection customers in protest over the commission’s order reinstating transmission owners’ rights to self-fund the upgrades.
MISO restored TOs’ rights to self-fund in 2019 at FERC’s direction. The commission originally issued an order in 2015 preventing TOs from providing initial funding for network upgrades, but that decision was remanded by the D.C. Circuit Court of Appeals.
The court ruled in November that FERC did not adequately explain why it reinstated TOs’ option to finance network upgrades before the interconnection customers owning generation projects were given the chance. (See FERC Must Clarify MISO Tx Funding Decision, DC Circuit Finds.)
The financing change has been generally unpopular with some MISO generation developers. They say it could lay the foundation for TOs to discriminate against some interconnection customers and increase the cost of new generation. (See MISO TOs’ Self-funding Option Tested Again.)
FERC accepted two unexecuted facilities service agreements (FSAs) between the Oliver Wind IV and Northern Divide Wind facilities, transmission owner Otter Tail Power and MISO (ER23-998, ER23-999). It also accepted an unexecuted multiparty facilities construction agreement between the same four parties and Palmer’s Creek Wind Farm, Prairie Hills Wind, Campbell County Wind Farm 2, North Bend Wind Project and Union Electric Company (ER23-997).
The Oliver Wind IV and Northern Divide Wind farms said they refused to execute their FSAs to reserve the right to terminate them and be made financially whole should FERC revert to its initial findings on TO self-funding.
Oliver Wind IV also asked FERC to order an amendment to the agreement that states the changes “will be undone if the legal premise for [transmission owner initial funding] is later eliminated.”
Otter Tail disagreed with the request. “Unless and until the commission not only acts upon remand, but also reverses its prior position, the unexecuted FSA continues to reflect the state of the law today and should be accepted for filing,” it said.
FERC agreed with Otter Tail. The commission said it will not allow MISO interconnection customers to “retroactively annul and reverse” TO funding elections if it later decides to reverse the self-funding order.
The agreements “appropriately reflect the state of the law as of the date the agreements become effective,” FERC said. It said its response to the court’s remand remains pending, and it will address any request to annul funding elections “if and when” a Section 205 or 206 filing is made under the Federal Power Act.
“Neither a request for rehearing nor a petition for review stays the effectiveness or enforceability of a commission order,” the commission said.
Commissioner Mark Christie wrote identical concurrences to the orders to underscore his philosophy on who should pay for and profit from network upgrades. He said generation developers should bear the full “but-for” costs of their interconnection.
“Consumers (i.e., load) should not pay one nickel. They are not the ones seeking to profit from the interconnection,” Christie wrote. “New generation in RTOs is supposed to be driven by the market, not by integrated resource planning, as in non-RTOs. This is the compelling principle underlying participant funding of interconnection in RTOs.”
MISO interconnection customers are responsible for 100% of network upgrade costs, with a possible 10% reimbursement from load for network upgrades that are rated 345 kV and above.
Christie said that when generation developers pay the full interconnection costs, TOs should not be allowed to profit from the investment, “as the developer incurs a cost of capital, not the transmission owner.”
“Allowing the transmission owner to profit on someone else’s capital investment (i.e., through a return on equity) results in an unearned windfall,” Christie said. He added that he looked forward to addressing his points in the remand proceeding.
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.
Greg Poulos, Consumer Advocates of the PJM States (CAPS) | © RTO Insider LLC
