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October 31, 2024

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PJM MRC Briefs: April 26, 2023

Renewable Dispatch

VALLEY FORGE, Pa. —
The PJM Markets and Reliability Committee on Wednesday endorsed a new renewable dispatch structure proposed by the RTO and the Independent Market Monitor.

The endorsement directs staff to return to the committee with revised tariff and manual changes incorporating the market changes. PJM’s Darrell Frogg said the structure would provide better data to allow dispatchers to anticipate the output of renewables and increase transparency on performance and forecast accuracy through regular reviews with stakeholders. (See “PJM, Monitor Present Renewable Dispatch Proposal,” PJM MRC/MC Briefs: March. 22, 2023.)

The construct would replace the use of curtailment flags sent to generators through the Inter-Control Center Communications Protocol (ICCP) with economic basepoints. Generators would be directed to follow those basepoints regardless of curtailments because of the potential for inadvertent curtailments.

Renewable resources would be required to offer into the day-ahead market unless they receive approval for an exception for a physical constraint from PJM and the Monitor. Their offers would be based on forecasts of both weather and equipment availability produced by either the market seller or PJM.

Generators would be required to update their critical parameters in real-time security-constrained economic dispatch (SCED) every five minutes and on an hourly basis for parameters in intermediate-term SCED cases.

The lost opportunity cost structure currently available for wind resources would be extended to solar, making them available for payments when they follow dispatch through SCED basepoints.

Paul Sotkiewicz, president of E-Cubed Policy Associates, said the proposal appears to leave a lot undefined at this point. Frogg agreed, but he added that those details will be filled in as tariff and manual language is developed.

Capacity Performance Penalties

Stakeholders discussed three proposals to change when generators can be assigned Capacity Performance (CP) penalties and how they are calculated. Proponents described the changes as an effort to put market changes in place while stakeholders consider longer-term proposals being drafted through the Critical Issue Fast Path (CIFP) process. (See PJM Presents More Detail on CIFP Proposal.)

All three would shift the charge rate from being based on the net cost of new entry to the Base Residual Auction (BRA) clearing price for that delivery year. If the alternative calculation was applied to the 2023/24 delivery year, it would result in a $394/MWh penalty, versus the status quo of $3,177/MWh.

The proposals differ in both the stop-loss limit (SLL) and the trigger for the performance assessment intervals (PAIs) that define when a generator can be assigned penalties or bonuses based on how they match up against their obligation.

LS Power and the Monitor are proposing a limit set at twice the BRA clearing price, while American Municipal Power used a lower SLL at 1.5 times the clearing price.

For the PAI trigger, LS Power and AMP suggested mirroring the provisions in PJM’s CIFP proposal, which would only allow PAIs when there is a real-time reserve shortage and declaration of emergency procedures more severe than pre-emergency demand response. Stakeholders said that DR should be utilized like any other capacity resource, and its dispatch shouldn’t subject other resources to penalties.

“It puts some discipline around when PAIs are called; it gives you some indication about when we’re getting close to when a PAI may be called,” LS Power’s Tom Hoatson said.

The Monitor’s proposal would predicate the implementation of a PAI on a shortage of primary reserves and a PJM declaration of a regional emergency.

LS Power’s Marji Philips said that FERC’s 2021 order on PJM’s market seller offer cap caused generation owners to lose the ability to adequately represent the risks they take on by participating in the capacity market. By reducing CP penalties, she said the proposal would de-risk the capacity market.

Vitol’s Jason Barker said the purpose of the penalties is to incent behavior, and reducing that wouldn’t lead generators to make the investments lessening the likelihood of events similar to the December 2022 winter storm.

“From our perspective there has to be a meaningful penalty,” he said.

PJM’s Adam Keech said the RTO is comfortable with the proposed changes to the PAI trigger, but it has concerns with reducing penalties without addressing the other side of the ledger: winterization and other mandates that would require capacity resources to improve their ability to perform. He said that the high penalties were a tradeoff to limited hard rules, and the proposals would significantly decrease penalties without introducing other ways of ensuring performance.

The LS Power proposal was introduced to the committee as a quick fix, meaning that the issue charge, problem statement and solution could be voted on during the same meeting. Noting the hourslong discussion it generated on Wednesday, some stakeholders questioned if it met the criteria of an issue that could be addressed with minimal stakeholder input.

Special meetings of the MRC and Members Committee have been scheduled for May 4 and 11, respectively, to further discuss the issue and potentially vote on endorsement.

Stakeholders Endorse Manual 11 Changes

Stakeholders endorsed revisions to Manual 11, which pertains to energy and ancillary services market operations, through the biennial cover-to-cover review of the document. Stakeholders deferred a vote on the changes during last month’s MRC meeting to allow more time to review amendments proposed in an effort to align the language with PJM’s other governing documents. (See “Other Stakeholder Discussions,” PJM MRC/MC Briefs: March. 22, 2023.)

The revisions presented at the second read on March 22 were revised to remove changes to the operating parameter definitions affecting the minimum run time for combined cycle units. The excised language is anticipated to return after being reviewed by the Governing Document Enhancement & Clarification Subcommittee.

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SPP Board/Members Committee Briefs: April 25, 2023

Working Groups Begin Addressing Grid of the Future

KANSAS CITY, Mo. — SPP members and the RTO’s Board of Directors last week embraced an advisory group’s report on a future grid that is fast approaching, directing stakeholder groups to begin addressing the group’s recommendations.

The board on April 25 accepted the Future Grid Strategy Advisory Group’s (FGSAG) report that identified potential gaps between future state projections and current trajectories, and urged increased organizational awareness of the opportunities to shape the future grid.

The directors had charged the group in 2021 to explore how the grid will change over the next 10 to 15 years and to make recommendations that help SPP and its membership prepare for those changes. The report identifies trends and strategic pathways that could be disruptive and game changing and makes 32 recommendations to address them.

SPP says the grid’s future is “vitally important” to its stakeholders and that the FGSAG’s work sets the stage for their discussions and readies staff to meet its members’ needs. Of course, that work will have to be balanced with ongoing initiatives.

“We are often dealing with what’s right in front of us and trying to react to changes that are occurring. … Things can look very complicated when we’re trying to address them,” Advanced Power Alliance’s Steve Gaw, a member of the group, said during the board’s quarterly meeting. “If we only look down in front of our feet at what we are about to step on, we sometimes lose our way because we don’t look up. This is an attempt I think not to say that we should be constantly looking up and forgetting what’s right in front of us, but an attempt to balance what’s going on out ways in front of us so that we don’t lose our way with distraction of what’s the latest urgency.”

“I think one of the challenges is how do you balance all of this new work with the existing work,” Director John Cupparo said. “The work groups that are going to be tasked these assignments would come back with some timelines and work plans for how that work will fit in with all the existing [work] so that we can see the balancing of that and understand the tradeoffs.”

The FGSAG gathered assessments last year from surveys, industry experts and organizational expertise to compile a list of recommendations. The Strategic Planning Committee endorsed the work in January and requested the board to direct the appropriate organizational groups to begin considering each recommendation.

The group categorized the results into four areas: consumer trends, policy implications, resource impacts and transmission possibilities. Four sub-teams then drafted white papers that examined each topic’s concerns and defined preliminary recommendations. Because the sub-teams’ recommendations had some overlap and common themes, the full FGSAG reviewed and consolidated them into a final list, grouped into five categories:

      • energy adequacy/modeling/planning;
      • grid services/market design/operations;
      • transmission;
      • demand-side resources; and
      • innovation and collaboration.

The report sets out a three-phase plan to address its recommendations and provide progress reports back to the SPC:

      • educate primary working groups on the relevant recommendation and secondary and advisory working groups for input as needed;
      • draft initiatives that address the recommendations and develop tasks and outcomes to ensure their inclusion in SPP’s comprehensive roadmap; and
      • report quarterly on the initiatives’ progress and update the board on their implementation’s appropriateness, scope and pace.

The effort has been led by Mark Ahlstrom, NextEra Energy Resources’ vice president of renewable energy policy and board chair of Energy Systems Integration Group, a nonprofit engineering, resources and education association.

“Basically, what we’re planning to do is to take the recommendations that apply to each of the organizational groups out to them over the next six months or so, start the process of educating them, helping them understand it, get their feedback, and then engage other secondary and advisory groups,” Ahlstrom said. “It’s going to be an evolving set of things that we have to make sure we’re on top of and we get feedback and we evolve and improve as we go. I think you’re going to be seeing a lot of us as we continue to make sure that we keep ahead of the curve on what has to be done before we get to that 10- to 15-year time frame.”

The Inflation Reduction Act has added a complicating factor. The FGSAG said it attempted to document the legislation’s expected implications but that it will take more time and analysis to fully understand and address all its implications on generation, electrification, loads for green hydrogen production and economic development.

“What is already certain, though, is that the IRA’s impact on the SPP region will be dramatic,” the report said, pointing to tax credits for renewable, nuclear, green hydrogen production and energy storage.

“I can’t emphasize enough this is not going to be a one-and-done,” Ahlstrom said. “This is going to be an ongoing activity, but hopefully about a year from now, we would expect to see some sort of plan about how this will be taken up in methodical way by the various organizational groups and by staff.”

MMU Report: Energy Prices up

SPP’s Market Monitoring Unit gave the board and stakeholders a first peek at its annual report on the SPP market and its outcomes that reflect changing conditions.

According to the report, high natural gas prices resulted in increasing energy prices; the Panhandle Eastern hub’s average gas price of $5.83/MMBtu, up 69% from the year before, led to day-ahead and real-time prices of $48/MWh and $43/MWh, respectively, up 80% and 75% from 2021. Data from February 2021 was excluded to avoid skewing the metrics.

The SPP market also experienced continued higher renewable penetration and increased make-whole payments, congestion and revenue neutrality uplift. Keith Collins, the MMU’s vice president, said he wouldn’t be surprised if wind energy reaches a 40% share of SPP’s generation mix this year.

“SPP is in fact a wind system. At one time it was a coal system, but I think SPP is in fact a wind-dominated system,” he told stakeholders.

The MMU said the market’s challenges — increasing variability and supply uncertainty, out-of-market reliability actions, higher make-whole payments and more negative prices — are not necessarily new developments. It said addressing resource adequacy is “perhaps the most important lesson” from the severe winter storms of the last two years; the key issues include a lack of a seasonal resource adequacy requirement; fuel availability risks; correlated output and outages among similar resources; and an accreditation process that does not reflect actual resource performance.

“The SPP system was lucky to have significant imports from MISO, PJM and others. SPP cannot plan to count on these systems to help SPP in a future event as a wider regional cold snap could limit imports,” the report says.

“It’s important to know that the resources we have in the system can be counted on during these events,” Collins said. “We need incentives to ensure that that capacity is available. … We know we’re moving to winter [resource adequacy] requirements. I think we’ve seen evidence that having requirements in the shoulder periods as well is actually a growing importance.”

The MMU is adding four new recommendations for 2022:

      • consider limitations on virtual trading during emergency conditions;
      • address limitations with the ramp capability introduced last year;
      • improve situational awareness of transmission upgrades and the process to reassign projects; and
      • improve congestion-hedging mechanisms to make them more equitable.

The Monitor said it “has and will continue to engage in the SPP stakeholder processes to help promote improved resource adequacy in the SPP market.”

The final market report is expected to be released in May. The 267-page opus will likely meet with approval from Google’s Betsy Beck, who has a market monitoring background and professes to read market reports “back to back, cover to cover every year.”

“I love these State of the Market reports. There’s always so much great information in the report itself,” she said. “The MMU puts a tremendous amount of work and really good analysis, and you can get a sense of all the different pieces of the market — how things are working well together or not — from reading the report.”

Uri Helps SPP Response to Elliott

SPP staff told the board and members that lessons learned from the 2021 winter storm (also known as Winter Storm Uri), many of which are still being incorporated into daily processes, were “extremely helpful” in the grid operator’s response to the December winter storm (also known as Winter Storm Elliott) when accredited generation fell short of demand at times.

Still, staff identified 11 recommendations during a thorough review of its performance during Elliott that could help the RTO and its stakeholders be better prepared for extreme events in the future. The recommended changes are to internal processes, tools or functions and should not require additional resources or stakeholder prioritization to complete, staff said.

The board approved the latest recommendations as part of its consent agenda.

Mike Ross, senior vice president for external affairs and stakeholder relations, said almost two-thirds of recommendations from Uri are complete. He said the rest should be completed by 2025, depending on FERC and other approvals, and that staff have recommended staying the course on the Uri recommendations.

The new recommendations include improving situational awareness of neighboring conditions; adding extreme weather risks to SPP’s transmission planning process; and identifying options to better mitigate and manage congestion during extreme winter events. SPP did not have to shed load during Elliott as it did during Uri, but the balancing authority area came close, and Empire Electric District had to shed about 25 MW of load for 15 minutes. (See “December Storm Raises Same Issues,” SPP MOPC Briefs: Jan. 17-18, 2023.)

“While there was no load shed directed by SPP, we came closer than we would have liked,” Ross said.

The two storms have both presented significant challenges to maintain reliability, staff said. Coal outages and derates were actually worse during Elliott, Ross said, and drove home the point that two “historic” extreme weather events 20 months apart are a harbinger of what the future holds.

“I think we’re going to stop using the term, ‘100-year storm,’” SPP CEO Barbara Sugg said.

Sugg Drops the Mic

Sugg reflected on the year’s first months that included a tornado touching down within a half-mile of the RTO’s headquarters building in Little Rock, Ark., continued market expansion into the Western Interconnection and advancements in clearing the generator interconnection queue’s backlog.

In sharing the organization’s progress against its strategic plan, Sugg pointed to the traditional dinner that follows the Regional State Committee meeting the night before the board meeting as an example of SPP’s stakeholder-driven culture. The casual dinner brings together the board’s directors and the RTO’s staff, members, regulators and other stakeholders.

“It was loud; it was rowdy; and it was fun. It felt like old times, and it was great to see everybody having a good time,” she said. “Just that dinner alone is one of the things that makes SPP extremely unique, because you will not find that in another region. Building relationships … is the cornerstone of SPP and is really what makes SPP great.”

In closing her report to the board, Sugg reiterated a statement she has made before: “There is no place I would rather be than working collaboratively here with all of you and back at the office with all of our amazing staff to achieve our vision of leading our industry to a brighter future while delivering the best energy value. That’s my mic drop moment.”

2022 Annual Report Available

SPP has released its annual report for 2022 and for the third year in a row, it will be in a virtual format.

The report details the grid operator’s performance during the year. The RTO says it provided $3.787 billion in value to its members and expanded the services it is providing stakeholders in the Western Interconnection.

It also summarizes SPP’s response to Elliott, improvements to generation interconnection, development of a consolidated transmission planning process, and staff’s and members’ focus on the future grid.

New Members Committee Reps

The Members Committee welcomed three new representatives who will serve in an interim capacity until they are officially elected during the October membership meeting:

      • Stacey Burbure, legal counsel for American Electric Power, replacing AEP’s Peggy Simmons;
      • Al Tamimi, vice president of transmission planning and policy for Sunflower Electric Power, replacing retired Sunflower CEO Stuart Lowry; and
      • Christy Walsh, director of federal energy markets for Natural Resources Defense Council’s Sustainable FERC Project, replacing Invenergy’s Daniel Hall.

The meeting was also Tom Christensen’s last as an MC member. He is retiring from Basin Electric Power Cooperative in May as senior vice president of transmission, engineering and construction.

Consent Agenda Passes

Members and the board approved a consent agenda that contained one revision request:

      • RR530: identifies consistent criteria for when it is acceptable to implement a transmission reconfiguration, and outlines responsibilities for the reliability coordinator and transmission operator in developing mitigation plans to avoid system operating limit exceedances.

The consent agenda included several other items, including:

      • the Oversight Committee’s recommendation for the 2023 industry expert pool that will review and evaluate proposals for competitive transmission projects. The pool includes 15 holdovers from last year and two new members: independent consultant Frank Lembo, a former chief engineer with Consolidated Edison, and Mark Lawlor, a renewable developer with EDP Renewables and Clean Line Energy Partners.
      • a 26% increase for Basin Electric’s 60-mile, 230-kV sponsored upgrade project in North Dakota near the Canadian border. An additional 5 miles of transmission line bumped the project’s cost from $64.9 million to $81.4 million.
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FERC OKs Duke Energy Rate Changes to Reflect Tax Cuts

FERC on Friday approved Duke Energy’s (NYSE:DUK) settlement with two co-ops to reflect lower corporate tax rates from the Tax Cuts and Jobs Act of 2017 enacted under former president Donald Trump (ER23-1206).

FERC Order 864 required utilities to reflect the cut in the federal corporate income tax from 35% to 21% in their formula rates, specifically their accumulated deferred income tax (ADIT). ADIT is meant to account for the timing differences between filing taxes with the IRS and the method of computing them for regulatory and ratemaking processes.

The lower federal taxes meant that some of utilities’ ADIT collected from consumers was no longer due to the IRS. Order 864 was meant to ensure that ratepayers were made whole for those over-collections and that going forward utilities would have to reflect tax changes in their rates in a transparent manner.

Duke made its initial compliance filings for Duke Energy Carolinas, Duke Energy Progress and Duke Energy Florida in 2020, as required, but FERC sent it back for some additional clarifications. (See FERC Directs More Clarity in Order 864 Filings.)

The utility filed changes, but a limited protest came from two of its wholesale customers: North Carolina Electric Membership and Central Electric Power Cooperative.

The two customers said that Duke proposed changes that were not required by FERC’s initial order. Duke’s filing would have changed how it calculated “average rate assumption method” (ARAM) rates, using the “best available data” instead of calculating them in the fourth quarter of the previous year.

They argued that the changes were ambiguous and would let Duke base its calculation on a period other than the fourth quarter of the previous year, which could lead to a mismatch in how ARAM and ADIT rates are calculated. Neither the customers nor FERC had a chance to fully vet the proposal, they said.

Duke asked FERC to hold the proceeding in abeyance so it could negotiate with the co-ops and came to a deal with them before submitting the compliance filing approved Friday.

The firm is proposing revisions to each utility’s formula rate to clarify that the ARAM rate used for the amortization of excess deferred income tax from the tax cut will be the “ARAM rate based on the last filed final federal corporate income tax return, after all permitted federal extensions” as of the date of posting the annual update.

FERC found that Duke’s proposal complies with Order 864 and addresses the co-ops’ concerns, making their protest moot.

The commission accepted Duke’s proposal to return excessive ADIT to customers — or collect shortfalls from them — effective June 1, 2020.  The commission said the utility had held customers harmless for the new tax rates in its 2018 and 2019 annual updates. FERC agreed that the June 2020 date would not adversely impact customers.

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Michigan Petition to Ban Solar Projects on Farms Withdrawn for Now

LANSING, Mich. — Organizers of a petition drive to ban new, large-scale solar projects on Michigan farmland withdrew their proposal for an initiated law after state officials and opponents warned the language was not specific enough and could shut down projects already in development.

But one of the organizers of Michigan Citizens for the Protection of Farmland said the petition’s language would be redrafted and resubmitted to the Michigan Board of State Canvassers.

The group needs at least 356,958 signatures from registered Michigan voters to place the proposed law before the voters in the 2024 election.

Petition organizer Erin Hamilton told the Canvassers at their April 28 meeting it was not the group’s intent to “create a disastrous situation” that would jeopardize current solar projects.

In a Change.org post, Hamilton said her group was responding to a recent decision by the Michigan Department of Agriculture and Rural Development (MDARD) to allow utility-scale solar on agricultural land enrolled in the department’s Farmland and Open Space Preservation Program.

Hamilton said MDARD’s policy “created a situation where communities without enough commercial or industrial-zoned land available for green power production may have to offer up their farmland, and makes them vulnerable to litigation from massive power corporations, something that America’s farmers and rural communities should never have to worry about.

“We believe that this decision undermines the core purpose of the Farmland and Open Space Preservation Program, which was created to protect our state’s valuable agricultural land for future generations,” she said.

Anti-solar sign (Michigan Citizens for the Protection of Farmland) Content.jpgMichigan Citizens for the Protection of Farmland

Although petition sponsors do not need the Canvassers’ approval of their language, most groups seek it to prevent court challenges that claim the language is impermissibly vague or that the petition fails to meet other state requirements. Such challenges have kept some petition proposals from going before the voters.

The proposal is intended to ban any new solar energy projects in Michigan on property zoned for agricultural purposes. It would not affect the ability of a farmer to install a solar project for personal energy usage. Violators would be subject to fines of $10,000 a day.

Under Michigan’s Constitution, petitions for initiated laws need signatures equal to 8% percent of the vote in the most recent gubernatorial election. If a petition gets enough certified signatures, the legislature has 40 days to enact the proposed law. If the legislature enacts the law, it is not subject to a gubernatorial veto. If the legislature does not enact the law, it would go before the voters.

If the initiated act is approved by the voters, it can only be amended or repealed by a three-fourths vote of the legislature. Voters can also repeal it through another initiative.

Hamilton lives in Livingston County, long one of the most conservative counties in Michigan, which has seen disputes over renewable energy projects in a number of townships.

Fights against renewable energy projects are becoming almost endemic in the state and starting to stretch beyond township boundaries. Clinton County, a largely rural area that includes one of Lansing’s fast-growing suburbs, will consider a proposal in May to enact a one-year moratorium on new renewable energy projects. There has been some discussion, though no proposal, for a countywide moratorium in Shiawassee County, east of Lansing.

In November, voters in Montcalm County rejected a plans for a 75-turbine wind park and recalled the local officials who supported the development. (See Wind, Solar Opponents Defeat Four Proposals In Rural Michigan County.)

On April 19, Michigan Senate Democrats introduced SB 277, which would allow farmland owners to contract for solar projects if there is a development agreement for the land and it meets certain standards in terms of pollinator protection and approved plantings. The bill is part of a package introduced to help the state meet its goal of carbon-neutral status by 2050. (See Michigan Dems Seek to End Coal-fired Plants by 2030.)

The anti-solar proposal before the Canvassers was opposed by environmental groups and others worried about the effect it could have on the state’s adoption of renewable energy. Former Michigan Democratic Chair Mark Brewer, representing the Michigan League of Conservation Voters, said the proposal could kill thousands of jobs in the state developing and maintaining renewable energy projects.

Ed Rivet, of the Michigan Conservative Energy Forum, and Brendan Miller, of the Land and Liberty Coalition, said the petition would strip local control from renewable energy projects and put it in the hands of the state.

CMS Energy told NetZero Insider it will take less than 2% of the state’s existing farmland to meet its goal of adding 8,000 MW of utility-scale solar power by 2040.

Katie Carey, director of external relations, said each megawatt of solar takes between five and 10 acres of “flat, open and treeless land with direct access to the sun.”

“Ideal project sites for utility-scale solar power plants are about 500 to 900 acres and are often comprised of multiple, neighboring landowners. We’re considering potential locations such as farm fields — including those less ideal for growing crops — brownfield sites and publicly owned properties,” she said. “Distance to existing transmission infrastructure is also a critical factor for solar developments. The closer, the better. Lack of access or long distances to high-voltage transmission and distribution can increase costs and other siting issues.”

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Vision for U-M EV Center: Building Ecosystem Where Auto Industry was Born

Already internationally renowned for its Center for Automotive Research, the University of Michigan opened a new Electric Vehicle Center last week that will focus on research and development and workforce development. The goal, the university said, is to “cultivate a robust electric vehicle ecosystem in the state where the modern auto industry was born.”

“We need to address areas like the workforce, cost, vehicle range, charging infrastructure and sustainability,” Dean of Engineering Alec D. Gallimore said. “Our center will build on more than a century of U-M leadership in transportation to tackle these and other critical areas.”

The Michigan legislature authorized funding for the center in the state’s 2022-23 budget. The center plans $130 million in spending:

  • $20 million to expand educational offerings for “mobility workers,” with a goal of reaching more than 1,200 students per year;
  • $50 million for research and development of innovative technology through public-private partnerships; and
  • $60 million for campus infrastructure that could include a teaching, training and development facility with an expansion of the university’s Battery Lab.

Alan Taub, an engineering professor at U-M and a former automotive executive, will head the center. Taub, former vice president for global research and development at General Motors (NYSE:GM), also worked for both Ford (NYSE: F) and General Electric (NYSE:GE).

Taub said EVs will require a “redefinition of personal mobility” not seen since the automotive industry began. That redefinition will affect vehicle design and manufacturing, consumer behavior, infrastructure and policy. It will require the efforts of government, academia and the automotive industry to resolve workforce issues, vehicle range, vehicle servicing, charging and other challenges.

For example, Michigan’s current automotive workforce could be largely displaced as EV production develops.   Although there will be increases in employment for EV production, other jobs in supplier companies — such as those who produce parts like oil pumps — will face displacement. Michigan, Indiana and Ohio — all major auto parts supplier states — could lose up to 22% of parts jobs, the university said.

The center will seek to fill industry gaps by identifying where to expand undergraduate and master’s degree programs, as well as continuing education courses and credentials, the university said. It also will participate in the Michigan EV Jobs Academy for education at the pre-apprentice, apprentice and associate degree level.

Mich. Departments Call for Public Input on EV Charging

In related news, the Michigan Department of Environment, Great Lakes and Energy and the Department of Transportation are seeking public input on EV charging as the state considers whether to seek funding under the U.S. Department of Transportation’s Charging and Fueling Infrastructure Discretionary Grant (CFI) program.

The program will provide funding for the build-out of direct current (DC) fast chargers along designated alternative fuel corridors and “community” Level 2 or DC fast chargers along any public road. States, regional planning organizations, local governments, tribes and public transportation authorities are eligible to apply.

“We are hoping to learn more about what organizations are applying to the CFI program and what organizations have project plans/ideas but will not/cannot apply to the CFI program,” the departments said in a joint release. “This information will be used to inform the State of Michigan’s approach to this funding opportunity.”

EGLE and MDOT ask interested organizations to fill out a questionnaire outlining their interest by May 8.

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CARB Approves Clean Locomotives Regulation

The California Air Resources Board approved a groundbreaking regulation Thursday to replace the worst-polluting diesel locomotives with cleaner engines by 2030 and to transition to 100% zero-emission (ZE) locomotives over the next three decades.

Diesel-powered locomotives run through many California cities, emitting greenhouse gases, nitrogen oxides (NOx) and fine particulate matter. Their emissions are expected to eclipse big-rig pollution as CARB’s clean-truck regulations take effect. (See Groundbreaking California Clean Truck Rules Win EPA Waiver.)

“It is imperative that locomotives moving freight as well as people transition to zero-emission, especially as additional new railyards are being built in the state and passenger rail services are expected to expand,” CARB Chair Liane Randolph said at Thursday’s board meeting.

“Communities near facilities where locomotives operate bear a disproportionate health burden due to their proximity to toxic emissions from diesel-powered locomotives,” Randolph said. “These communities tend to be low-income communities and communities of color.”

CARB’s “in-use locomotive” regulation requires locomotive operators to begin funding their own trust accounts based on emissions starting in 2024.

“The dirtier the locomotive, the more funds must be set aside,” CARB’s website says.

The funds can be used to buy or rent the cleanest types of diesel locomotives through 2030. They could also be used to purchase or lease ZE locomotives, to fund ZE locomotive pilot and demonstration projects, and to pay for ZE locomotive infrastructure.

Under the proposed regulation, locomotives older than 23 years are prohibited from operating in-state starting in 2030.

Switchers — short-haul locomotives used to move train cars — and passenger locomotives with original build dates of 2030 and beyond would be required to “operate in a ZE configuration,” CARB says. More powerful “line-haul” locomotives will have to be ZE if built after 2034.

Locomotives also will be prohibited from idling for more than 30 minutes, an effort to reduce emissions near homes.

CARB Executive Officer Steven Cliff said the board has been working with EPA to “coordinate on reducing emissions from locomotives … not only in California but throughout the United States.”

EPA responded to a 2017 CARB petition on locomotives in November, acknowledging the need for changes, and has proposed revising regulatory language to accommodate California’s stricter train emissions rules, Cliff said.

‘No Clear Path’

Dozens of community activists and representatives of environmental groups addressed CARB prior to board members’ unanimous vote Thursday. They urged the commission to do more to protect residents, including children.

“Today you have the power to change the course of history for Californians who have suffered from locomotive pollution for far too long,” Yasmine Agelidis, a Los Angeles-based attorney for environmental law organization Earthjustice told board members.

“I urge you to please adopt this locomotive rule today and save more than 3,500 lives, 63 tons per day of NOx emissions and $32 billion in health costs,” she said, citing CARB’s own estimates of the new rule’s impact.

Freight rail operators have not been so enthusiastic, fighting the regulation and threatening litigation, board members said.

Adrian Guerrero, assistant vice president of Western public affairs for Union Pacific Railroad, said the “rail industry has demonstrated a strong and productive commitment to reducing its environmental footprint and continues to search for ways to reduce air emissions” even without the regulation.

Union Pacific’s actions since 1998 “resulted in significant gains for clean air from line-haul and yard operations in California well ahead of the rest of the United States,” Guerrero said. “Today UP and the California railroads are exploring and testing technologies such as battery-electric and hydrogen fuel-cell locomotives in addition to modernizing our current locomotive fleets to be more efficient.”

The railroad has committed to net-zero operations by 2050, but “currently there is no clear path to zero-emission locomotives,” he said.

In contrast, CARB staff cited examples of a number of projects in the works, including:

  • a collaboration by BNSF Railway and Caterpillar’s Progress Rail Services to produce battery-electric locomotives, the first of which are expected to be delivered in 2024 to operate in railyards and on freight routes in Southern California;
  • an agreement by BNSF and Progress with Chevron to develop hydrogen-powered locomotives;
  • the California Department of Transportation’s order last year of four hydrogen-powered passenger locomotives from Swiss train maker Stadler Rail; and
  • a California Energy Commission award of $4 million to Sierra Northern Railway to develop a hydrogen fuel-cell switcher locomotive for use in West Sacramento.

Currently, however, the only hydrogen-powered freight locomotive operating in North America is Canadian Pacific Railway’s experimental model, which it tested successfully in 2022. The railroad says it is hoping to have two more — one for hauling freight and another for switching cars — in operation by the end of this year.

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MISO Releases JTIQ Portfolio Cost-allocation Details

CARMEL, Ind.— MISO last week released details about how it will allocate costs for its portion of the $1 billion Joint Targeted Interconnection Queue (JTIQ) portfolio of 345-kV projects with SPP.

The grid operator plans to recover a 90-10 split from incoming generation and load, respectively, for their cost share of the JTIQ portfolio through a monthly charge. MISO said it and SPP’s generation developers will make fixed payments that reduce the select transmission pricing zones’ revenue requirements over 20 years.

During a Planning Advisory Committee (PAC) meeting Wednesday, MISO counsel Chris Supino said the RTOs will use a subscription model for JTIQ planning cycles. When 125% of the portfolio’s megawatts are spoken for, it will be considered fully funded.

Should the grid operators come up short on new megawatts before all JTIQ projects are in-service, load will temporarily pay for the unclaimed megawatts. Generation projects that queue up will repay load later.

MISO staff said they are still outlining the process of what happens when a JTIQ portfolio doesn’t have enough willing takers of transmission capacity through new generation in the queue. However, Supino said it’s unlikely that the portfolios won’t be fully subscribed and funded, as they’re planned to support the evolving resource mix.

Supino said MISO is considering adding a new JTIQ participation agreement to its generator interconnection agreements that would bind parties to the cost schedules’ terms.

Potential federal funding might complicate the process. The Department of Energy in early March said the RTOs and two member entities can apply for full funding under its Grid Resilience and Innovation Partnerships (GRIP) program. (See DOE Clears JTIQ Projects to Proceed with Funding App.)

Clean Grid Alliance’s Beth Soholt asked how payments might be modified should the DOE award funding to the portfolio.

“That’s a great question, but we can’t assume we’ll have a pot of money until we actually get that money,” Supino said.

Supino said staff plans to mention the DOE application when memorializing the JTIQ study and payment process in its joint operating agreement with SPP. The RTOs plan to file with FERC as early as July.

Supino said he doesn’t yet know how DOE funding will affect repayments or reimbursements.

JTIQ portfolio map with costs (MISO and SPP) Content.jpgJTIQ portfolio map with costs and adjusted production cost benefits | MISO and SPP

During a Tuesday cost-allocation working group meeting, Mississippi PSC consultant Bill Booth asked MISO to provide more details around the payments’ “timing and flow.” He said he wanted to know whether cost assignments to load will be capped and how they would be tracked in the case of temporary overpayment.

Sustainable FERC Project’s Natalie McIntire said that analyses indicate load will receive 20% on the JTIQ projects’ benefits, but only shoulder 10% of the cost.

Stakeholders asked during the PAC meeting whether staff will begin a JTIQ portfolio for the MISO-PJM seam.

Dave Johnston, an Indiana Utility Regulatory Commission staffer, said he thought it was premature to ponder a MISO-PJM JTIQ portfolio when the MISO-SPP’s process is untested and cannot be deemed a success yet.

MISO’s Andy Witmeier said in March that it’s more cost-effective for comprehensive seams planning to replace the RTO’s “back-and-forth, across the fence” affected system study process with SPP that identities expensive network upgrades.

“A lot of time those solutions are too costly for those set of projects to take on,” Witmeier said. He said it’s appropriate that most JTIQ projects’ costs be allocated to generation because they are designed to facilitate new resources.

“They’re not being built to fix market-to-market congestion or increase transfer capability, he said. “There might be tertiary benefits.”

“This is all new and novel, and if we want this to work, we’re going to have to accept some level of risk,” SPP’s David Kelley said. “I truly believe this is going to be successful and our new way of planning.”

That risk could be reduced considerably if the JTIQ portfolio wins up to a 50% share of funding through the GRIP program.

The Minnesota Department of Commerce is leading the DOE application, due May 17, with help from the Great Plains Institute. The Institute’s Matt Prorok said during April’s Organization of MISO States board meeting that the parties have a “compelling case.”

If the federal dollars are approved, the awards will be granted to RTOs and transmission developers. Prorok said parties must negotiate any awarded grant.

Prorok said the DOE application shouldn’t interfere with the RTOs’ cost-allocation discussions with their stakeholders.

“If the DOE can help us out with funding, I think those [cost-allocation] discussions will go very smoothly,” Kansas Corporation Commissioner Andrew French said during the Gulf Coast Power Association’s MISO-SPP conference in March.

“I hope JTIQ can move forward, and we can use it as proof of concept,” he said.

Aubrey Johnson, MISO’s vice president of system planning, has said DOE funding would provide certainty to members and make interconnections more attractive for developers.

During MISO’s Board Week in March, Johnson said more needs to be done to figure out how DOE funds will intermingle with cost allocation. He joked that the process won’t be as simple as the DOE “cutting a $500 million check, as much as I ask them to.”

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ACORE: MISO Should Retool Market for Resources’ Transition

[EDITOR’S NOTE: A previous version of this article misspelled Michael Goggin’s last name on first reference and incorrectly labeled him as ACORE’s “grid strategies vice president.”]

A new American Council on Renewable Energy (ACORE) report recommends MISO make multiple changes to its markets to take advantage of a shifting resource mix.

Michael Goggin, vice president at Grid Strategies and the report’s author, said during an April 25 webinar that he would like see markets with new design elements maximize optimal dispatch and minimize control room operators’ out-of-market commitments.

Goggin said MISO should improve the accuracy of its market participants’ minimum generation levels and filed ramp rates by tightening their rules. He said the grid operator should ensure submitted generator bid parameters reflect the units’ true flexibility, including ramp rates and start-up times or minimum output limits that aren’t physical but economic in nature. He said bid parameters that underplay a unit’s actual flexibility result in excess payments to slow-moving generation.

“I think a common theme across our recommendations here is to use markets,” he said. “Markets are extremely effective and efficient for aggregating a lot of information, which is what the power system has. In many of these RTOs, you have thousands of generators, millions of customers. … Markets are extremely good for aggregating that information and sending the right price signal to the generator to do what is needed to maintain reliability.”

Goggin said incoming battery storage, which is nearly “perfectly flexible,” has a lot of reliability potential. However, he said MISO’s market is “shortsighted” in that it currently prohibits dispatchable renewable energy from furnishing a range of operational reserves.

“We think this is harming customers because wind and solar resources have extremely flexible capabilities to provide a range of operating reserves,” he said.

Much of MISO’s existing generation is inflexible and can’t be dispatched up and down quickly, Goggin said. He said MISO should make a point to “price inflexibility” and remove uplift and out-of-market payments from inflexible resources, saying a failure to so can harm the resource transition.

“Traditionally, we got used to operating the power system that way, but now that we have new resources that are highly flexible, and you can actually add things like batteries to your existing plant, we think that a lot of the market design that made sense decades ago no longer make sense,” he said.

Goggin said controllable wind and solar resources are “underappreciated.” They’re underused for flexibility services, he said, and left navigating market rules that weren’t designed for them.

“We hear a lot from RTOs fretting about losing so-called flexible resources and talking about the need to directly compensate for flexibility. And that may be true, but I feel like there’s often less thought put into how to get rid of these market features that reward inflexibility,” Sierra Club senior attorney Casey Roberts said.

Roberts said she thinks resources owners understating flexibility in their bid parameters is a pervasive problem and that RTOs should take steps to hold them accountable. She said observing how many thermal resource owners alter their startup times compared to what was on the books before MISO introduced its new availability-based capacity accreditation was “interesting.”

“Several generation owners suddenly discovered they were a lot more flexible than they had previously thought and asked for waivers from those rules so their ‘true’ greater flexibility could be reflected in their capacity accreditation,” she said.

Roberts also said MISO is making an unfortunate choice by disqualifying its wind and solar resources from providing ramping capability. (See MISO Plans to Bar Intermittent Resources from Ramp Capability.)

“This is not based on the technical capabilities of these resources, but rather an inability of MISO’s own software systems to discern whether any resource’s ramp-up capability would actually be deliverable or whether they appear to be available to deliver ramp-up because they’re curtailed due to transmission constraints,” Roberts said. “That results in a situation where MISO has to manually confirm each resource’s availability to deliver ramp up, which it’s willing to do for thermal resources but not for renewable energy simply because there are so many of them it would be an untenable problem.”

That issue illustrates that MISO needs software and transmission upgrades in market updates, she said.

Leeward Renewable Energy’s Emma Nix agreed that RTOs need transmission buildout to support interconnecting inverter-based resources. She said that MISO is entering capacity markets’ next phase considering the daily times that capacity is most needed.

Goggin urged MISO to use a sloped demand curve in its capacity auction and account for simultaneous unavailable capacity caused by widespread generation outages. He said it’s common for much of the generation portfolio to trip offline at the same time during weather events. (See MISO Charts Course on Capacity Auction’s Sloped Demand Curve.)

MISO should add probabilistic forecasting to commit resources and shrink the time it takes to commit resources as close to real-time as possible, he said. MISO can reduce forecasting errors by shortening the time that passes from commitment to output, Goggin said.

He praised real-time, five-minute markets as the most effective means of incenting flexibility. He said energy price caps can sometimes interfere with the market because they can mask the operating day’s riskier periods and can trigger units to prematurely release all available output. He added that higher wholesale market price caps will have “very little” rate impact because most customers will never pay a real-time price.

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FirstEnergy Pressured to Acquire W.Va. Coal Plant

Pressure to purchase and run a West Virginia coal-fired power plant poses financial and political complications for Ohio-based FirstEnergy (NYSE:FE).

Analysts participating in the FirstEnergy’s first-quarter earnings conference call Friday questioned whether the company’s regulated West Virginia subsidiary Monongahela Power would purchase the Pleasants Power Station, a deregulated plant the company previously owned that is now struggling to compete in the PJM market and slated for shutdown on May 31.

The Public Service Commission of West Virginia in December asked FirstEnergy to consider approving Mon Power’s purchase of the 44-year-old, 1,300-MW coal plant, located on the West Virginia side of the Ohio River.

FirstEnergy briefly owned Pleasants after buying the Pennsylvania-based utility Allegheny Energy in 2011. But in 2017 it tried to move ownership and operation of the plant from what had become unregulated Allegheny Energy Supply to regulated Mon Power. FERC blocked the move. (See FirstEnergy Shutting Down Unsold Coal Plant.)

The plant is now owned by Maryland-based Energy Transition and Environmental Management, a company that demolishes old power plants and repurposes the sites. ETEM is leasing the plant to its previous owner, Energy Harbor, which will handle shutdown at the end of this month.

Energy Harbor is the company that emerged from the bankruptcy of FirstEnergy’s power plant subsidy FirstEnergy Solutions.

FirstEnergy agreed to review the request from the PSC, but earlier this spring it asked for a subsidy of $3 million/month to cover operating Pleasants for a year while it continues to evaluate whether to purchase and operate it as a regulated facility. Consumer groups and the state’s consumer advocate are opposing the idea.

FirstEnergy CFO Jon Taylor explained the West Virginia situation to analysts during a review of the company’s rate increase plans pending or planned before utility regulators across its 10 electric distribution companies.

“Mon Power proposed an option to enter into an interim arrangement with Pleasants’ current owner that would keep the plant operational beyond its May 31 deactivation date. This would allow the needed time to do a thorough analysis and evaluation as requested by the West Virginia PSC,” he said.

Taylor said the PSC approved the company’s request for the subsidy earlier in the week.

“We will begin negotiations with the plant’s current owner. If we reach an interim agreement that we believe is in the interest of customers and FirstEnergy, we will submit it to the commission. And if approved, this would allow recovery of associated costs through a surcharge. If we can’t reach an agreement that is in the interest of our customers, we will file an update with the commission,” he said.

A complication is that Mon Power and a second regulated FirstEnergy subsidiary, Potomac Edison, already own two other large coal-fired power plants in the state.

If FirstEnergy approves Mon Power buying Pleasants, the company will likely close one of the other plants, said Taylor. “We don’t see it as a viable option for Mon Power to operate three coal-fired power plants in West Virginia,” he said.

FirstEnergy “is moving forward with efforts to support the energy transition across our footprint,” Taylor told the analysts. “And we remain committed to our climate strategy and our goal to achieve carbon neutrality … by 2050.”

The company is planning to build five solar farms in the state with a total output of 50 MW, he said.

An analyst with KeyBanc asked whether the company will face an “impossible situation” and will “pay a political price” in the state if it does not purchase the Pleasants power plant.

Interim CEO John Somerhalder responded that the company is committed to working closely with the state. Noting that the Pleasants plant is newer and equipped with enhanced environmental controls, the request from the PSC is “a good question that needs to be evaluated,” he said.

Somerhalder’s review of the company’s overall financial performance in the first quarter was equally upbeat.

“Despite record-high temperatures across our footprint this winter, we’re off to a good start in 2023 as we continue positioning FirstEnergy for greater resiliency and growth by strengthening our financial position, enhancing our operations and optimizing the customer experience,” he said.

The company reported first quarter earnings of $292 million ($0.51/share) on revenue of $3.2 billion. That compares with earnings of $288 million a year ($0.51/share) on revenue of $3 billion.

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CARB Adopts Clean Fleets Rule Despite Broad Skepticism

California regulators approved a rule that will ban the sale of diesel trucks in the state starting in 2036, requiring all new medium- and heavy-duty trucks sold to be zero-emission.

The regulation, called Advanced Clean Fleets (ACF), also requires truck fleet operators to start transitioning to zero-emission vehicles beginning on Jan. 1, 2024.

The California Air Resources Board (CARB) voted unanimously on Friday to adopt the regulation.

“This is an absolutely transformative rule to clean our air and mitigate climate change,” CARB Chair Liane Randolph said just before the board’s vote.

But Randolph acknowledged there are challenges in the transition to zero-emission trucks. Some board members, while supporting the regulation, expressed doubts that sufficient infrastructure would be available to support the ZEVs.

“Those challenges aren’t going to be tackled unless we move forward,” Randolph said. “No one is going to build infrastructure in the abstract. So, we need to adopt this rule, move forward, get it going, and work through all of these implementation challenges.”

The agency initially had proposed banning the sale of diesel trucks starting in 2040. But during a hearing on the proposed regulation in October, the board asked to move up the ban to 2036. CARB called the 2036 ban on diesel trucks “a first-in-the-world requirement.”

Timeline Questioned

Critics called the timeline unreasonable.

American Trucking Associations CEO Chris Spear said fleet operators are just getting acquainted with zero-emission trucks. He said they are finding that the vehicles are more expensive than internal-combustion vehicles and that charging and refueling infrastructure is “nonexistent.”

“California is setting unrealistic targets and unachievable timelines that will undoubtedly lead to higher prices for the goods and services delivered to the state and fewer options for consumers,” Spear said in a statement following Friday’s vote.

In response to feedback during the October board meeting, CARB staff revised the regulation to give fleet operators more flexibility in complying with ACF. (See CARB Examining Obstacles on Road to ZEV Fleet Adoption.) The changes were released in March for 15 days of public comment.

But many local governments across the state still objected to the regulation.

The Nevada County Board of Supervisors said in a letter to CARB that ACF doesn’t consider local agency budget constraints. The regulation also doesn’t factor in the time needed to build the infrastructure needed to support the ZEVs, the letter said.

“Electrifying service yards to support an electrified fleet is a much greater undertaking than a simple electricity panel upgrade or some quick trenching in the parking lot,” said the letter, signed by Board of Supervisors Chair Ed Scofield.

CARB member Bill Quirk, who was appointed to the board in January, asked agency staff on Friday about the availability of zero-emission drayage trucks with a range of at least 400 miles. That’s an issue that some speakers raised during public testimony on Thursday.

Heather Arias, CARB’s transportation and toxics division chief, said some hydrogen fuel cell trucks with that range are now available. As for fueling, Arias said, there are two hydrogen stations at San Pedro ports and two more are expected near the Port of Oakland. In addition, the California Energy Commission is considering funding several hydrogen fueling stations throughout the Central Valley.

“Within a year, we anticipate that drayage fleets would be able to buy hydrogen fuel-cell trucks with upwards of a 500-mile range and be able to fuel anywhere from the Port of Oakland all the way down to San Pedro and several spots in between,” Arias said.

Quirk, who owns a hydrogen fuel cell vehicle, noted the difficulties of fueling near his home in the Bay Area. He said the CEC “cannot be depended upon to do this.”

“I’m just not optimistic that the infrastructure’s there, and I think we need to put pressure on the Energy Commission to make sure it is there,” said Quirk, a former state Assemblyman. “And not only that the stations are there, but the hydrogen is there. Because again, these stations run out of hydrogen all the time.”

Board member John Balmes said providing infrastructure to support the ZEVs would be “a huge lift.”

“I’m personally skeptical that we can pull it off,” he said.

Other board members focused on the anticipated benefits of ACF.

Board member Diane Takvorian noted that ACF is expected to generate $26 billion in health savings, as cleaner air leads to fewer premature deaths, emergency room visits, hospitalizations and lost workdays.

“It’s resulting in an amazing number of health benefits,” Takvorian said.

ACF is also expected to reduce cumulative GHG emissions in California by 327 million metric tons from 2024 to 2050, making it a key step toward the state’s goal of reaching carbon neutrality by 2045.

Fleets Covered by ACF

The ACF regulations apply to three categories of fleets: drayage fleets; state and local government fleets; and federal and high-priority fleets. Fleets are considered high-priority if they have 50 or more vehicles or more than $50 million in annual revenue.

The requirements are the most stringent for drayage trucks, the heavy-duty vehicles at ports and railyards that transport cargo. The idea was to prioritize air quality improvements in disadvantaged communities near ports and warehouse districts.

All new trucks added to drayage fleets must be zero-emission starting in 2024, and all drayage trucks must be ZEVs by 2035.

And while operators of other types of fleets have the flexibility to add ZEVs or near-ZEVs, such as plug-in hybrid trucks, to comply with ACF through 2035, the near-ZEV option isn’t available for drayage fleets.

For high-priority fleets, all new trucks must be ZEVs or near-zero-emission starting in 2024.

For state and local fleets, half of new trucks must be ZEVs or near-zero-emission from 2024 to 2026, and all must be ZEVs or near-zero-emission beginning in 2027.

Fleet operators may also request more time to comply under a range of circumstances, such as a delay in ZEV infrastructure construction that’s outside their control. An extension of up to five years may be available if the utility needs more time to bring power to the site.

Fleet operators may also be allowed to buy an internal combustion vehicle if they’re looking to replace a specialty truck for which there’s no ZEV equivalent.

And ACF offers an alternative compliance option in which fleet operators can still buy internal combustion trucks but commit to increasing the percentage of ZEVs in their fleets over time. For light-duty package delivery vehicles, for example, half of the fleet would need to be ZEVs by 2031, followed by a full ZEV requirement in 2035. The alternative compliance option isn’t available to drayage fleets.

Advanced Clean Fleets is a complement to the Advanced Clean Trucks regulation that CARB adopted in 2020. That regulation requires manufacturers of medium- and heavy-duty trucks to sell an increasing percentage of zero-emission vehicles starting in 2024.

Even with Advanced Clean Trucks and Advanced Clean Fleets, an estimated 480,000 heavy-duty combustion-powered trucks will still be on California roads in 2037, CARB said last year in its State Implementation Plan submitted to the EPA. The agency expects to start work on an additional zero-emission truck measure to address remaining diesel trucks, with a target of board adoption in 2028.