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November 5, 2024

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WEC Energy Group’s Earnings Droop on Mild Winter

WEC Energy Group’s (NYSE: WEC) first-quarter earnings dipped year-over-year after one of the mildest winters in its service territory in more than a century.

The utility reported net income of $507.5 million ($1.61/share) for the first quarter of 2023, a drop from the $565.9 million ($1.79/share) it brought in during last year’s first quarter.

WEC Executive Chair Gale Klappa said the weather was a “major factor” in the earnings results.

“We saw one of the mildest winters in the history of the Upper Midwest,” Klappa said during a conference call with financial analysts Monday. “For example, it was the second-warmest first quarter in Milwaukee since 1891. However, we’re confident in our plan for the remainder of the year.”

WEC serves nearly 4.7 million customers in Wisconsin, Illinois, Michigan and Minnesota.

Assuming normal weather for the rest of 2023, WEC will be able to achieve its annual earnings guidance of $4.58 to $4.62/share, Klappa said.

“We continue to focus on the fundamentals of our business: financial discipline, operating efficiency and customer satisfaction,” he said in a statement. “And we’re confident that we can deliver another year of strong results, in line with our original guidance for 2023.”

WEC’s consolidated revenues totaled $2.9 billion, down $20 million from the first quarter a year ago.

The utility said residential electricity use dropped by 5.8% compared to last year’s first quarter. Small industrial and commercial customer electricity consumption fell by 3.4%, and large commercial and industrial customer electricity use declined 3.9%.

Klappa said WEC continues to make progress on its $20.1-billion, five-year environmental, social and governance plan. He said it’s the largest five-year investment plan in the history of the company and should drive compound earnings growth of 6.5% to 7% annually from 2023 through 2027.

“As we look to the future, it’s clear that the mega-trend of decarbonization and the need for even greater reliability will drive investment plans that are long and strong,” he told analysts.  

WEC CEO Scott Lauber said that since last December, the Wisconsin Public Service Commission has granted approval for two solar battery parks and WEC’s purchase of a portion of the solar and natural-gas output from Alliant Energy’s West Riverside Energy Center.

Lauber said work continues on Badger Hollow II Solar Farm and the Paris Solar Battery Park, in which WEC shares ownership interest with other utilities. He said the projects’ remaining solar panels are clearing customs in Chicago, and WEC hopes to place the solar parks into service late this year or early next year.

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PJM Stakeholders Refine CIFP Capacity Market Proposals

VALLEY FORGE, Pa. — Stakeholders last week continued to refine proposals to overhaul PJM’s capacity market through the second phase of the RTO’s Critical Issue Fast Path (CIFP) process.

The first stage two meeting on April 19 featured presentations from American Municipal Power (AMP), the Independent Market Monitor and a joint proposal from the East Kentucky Power Cooperative and Daymark Energy Advisors.

A second meeting on April 26 included presentations from MN8 Energy and the Capacity Coalition, a group of five generation companies collaborating to create a combined package. Vistra and Autumn Lane Energy were also scheduled to present on the that day but had to postpone until May 17 because of time constraints.

The proposals aim to address several issues highlighted by the PJM Board of Managers when it initiated the CIFP process in February, including evaluating whether the Capacity Performance (CP) construct is adequately incentivizing resources to meet their obligations and creating stronger winter or seasonal requirements for accreditation and fuel security standards.

The second phase of the process involves forming proposals, which will be finalized in the third stage and voted on by the Members Committee in August. PJM’s Dave Anders reiterated that there is not a hard line between the second and third phase, and proposals can continue to be created and modified at any point.

EKPC and Daymark Propose Two Types of Capacity

The proposal from EKPC and Daymark would create base and emergency capacity variants, with the latter being designed to address extreme weather conditions. Emergency capacity would also be required to have firm fuel or the technical equivalent to it, be available to commit within two hours’ notice and demonstrate the ability to financially withstand any non-performance penalties should it not operate.

“Should they fail to perform and thus not be paid as a consequence of that nonperformance and it could have a substantial impact, the next step should not be that they leave the market because that would be problematic,” Daymark’s Marc Montalvo said.

The base capacity would be focused on addressing systemic conditions and wouldn’t include winterization requirements above those already mandated by NERC. However, the PJM proposal would require all capacity resources to winterize to a higher standard or not receive any revenues for those months.

Adrien Ford of Old Dominion Electric Cooperative said multiple connections to gas pipelines may not be useful as a firm fuel qualification, given that in some locations a single pipeline connection can be more reliable than multiple pipelines in another location.

AMP Seeks Subannual Accreditation

AMP presented a proposal that would create sub-annual accreditation and replace capacity performance, which penalizes and rewards generators depending on whether they meet their obligations during emergencies. Under the concept, all capacity resources would be required to participate in sub-annual auctions, which would clear after the annual Base Residual Auctions (BRAs). Auctions would also be held closer to the delivery year, a shorter time frame than the current three-year advance schedule, reflecting market participants’ experience with auction delays leading to compressed timelines.

“The idea would be that we don’t do away with annual [accreditation] outright. … We firmly believe that the majority of the capacity that clears should be annual, but recognize that monthly or seasonal has value,” AMP’s Steve Lieberman said. The specifics of how granular sub-annual could go would depend on stakeholder feedback in the coming months, he said.

The proposal would replace CP with a regular testing requirement consisting of a penalty and reward structure based on testing performance. The incentives would be based on capacity market revenues and operate on a “pay as you go” basis.

Independent Market Monitor Adds Detail to Proposal

Monitor Joe Bowring provided additional detail on the proposal he unveiled during the first-phase CIFP meetings. The proposal would seek to identify the energy needs for each hour of a delivery year and provide capacity revenues that cover the avoidable costs for generators meeting that need. Capacity would be paid based on annual auction clearing, hourly supply and demand and an annual avoidable-cost rate (ACR).

The Monitor’s plan would base accreditation on a unit’s installed capacity (ICAP) multiplied by its modified availability factor (MAF), an attribute which aims to provide a methodology to capture the availability of all resource types by incorporating forced outage rates, maintenance outages and intermittent resource availability. Bowring said availability would be a stronger measure than PJM’s current effective load-carrying capability (ELCC) measure.

All resources holding capacity interconnection rights (CIRs) would be subject to a must-offer requirement for that capacity and weekly generator testing. Capacity resources would also be required to possess firm fuel or the technical equivalent. For intermittent resources, that would mean being obliged to perform at their full possible output when called upon. Winter Storm Elliott last December showed, however, that firm fuel is not a guarantee of the ability to perform when called upon.

Weekly testing may be considered an “extreme position” for many stakeholders, Bowring said, but he argued that regular testing throughout the year, not just during the summer, recognizes that resources need to be able to perform any time of year.

“If there had been adequate testing, we would not have had either the polar vortex or Winter Storm Elliott” challenges, he said.

Casey Roberts, with the Sierra Club, questioned whether the Monitor’s proposal would consider gas generators to be available if they did not nominate for fuel ahead of potential emergency conditions. Bowring responded the proposal doesn’t currently address that, but it is something all proposals will have to weigh.

Capacity Coalition Presents Short- and Long-term Proposals

Emma Nix of Leeward Renewable Energy and John Horstmann of AES presented a Capacity Coalition proposal that aims to introduce short-term changes to the capacity market through the CIFP process, while putting long-term changes on the table.

The short-term changes include retaining the status quo of exempting renewable resources from the capacity market must-offer requirement, developing transparent and coherent triggers for a Performance Assessment Intervals (PAI), increasing market seller’s flexibility in reflecting their risk in their market seller offer caps (MSOCs), and changing how thermal resources are accredited to reflect expectations of how they would operate through weather and historical performance.

The proposal says that, in the short term, the status quo must-offer exemptions for intermittent and limited-duration resources should remain in place given that capacity is an annual product that commits those resources around-the-clock at times they may not reasonably be expected to be provide capacity. Renewable and storage resources need the exemption so they can adjust their capacity offers based on their individual risk tolerance for Capacity Performance penalties should a PAI be called when the resource is not online, Nix said. Implementation of the seasonal proposal in the long-term would negate the need to maintain the must-offer exception in the short term.

The proposal would also only allow generators to be penalized when there has been advance notice of a PAI, when PJM is not exporting to non-firm load commitments in other regions and when the RTO does not have adequate system reserves. It would limit the bonuses derived from the penalties to only be payable to resources that participate in the capacity market. They are currently paid to any generator that performs above expectations.

PJM’s Becky Carroll said the RTO’s proposal to eliminate the pre-emergency demand response as a PAI trigger could effectively allow DR deployments to serve as advance notice for the potential for generators to be subject to penalties, though she added that there could be PAIs that don’t follow a pre-emergency DR call.

Horstmann said there’s an open question as to what obligations a capacity resource committed in PJM might have to serve load in other regions during an emergency. The coalition proposal seeks to define that as being an obligation to serve PJM’s load.

The proposal also calls for the creation of Capacity Performance quantified risk (CPQR) values for resource classes, to reduce the administrative burden in the unit-specific MSOC process while still allowing companies to reflect their risk across their portfolio.

The long-term side of the proposal calls for a transition from a single annual price to a seasonal capacity model consisting of 12 monthly intervals and four daily intervals by 2030.

The seasonal proposal would align accreditation and offers with how resources are capable of performing during specific times of day. Most important, the RPM auction would set the price for each interval allowing market forces to appropriately establish prices based on PJM system supply and demand needs to incentivize new capacity entry, particularly during times of system need. The coalition includes Leeward, AES, Pine Gate Renewables, Ørsted and Cypress Creek Renewables.

MN8 Energy Suggests ‘Pay as You Go’ Model

A proposal from MN8 Energy aims to build on PJM’s proposed accreditation and risk modeling — namely, capturing a larger breadth of factors affecting generator operation, such as temperature impacts and lead time — while proposing a “pay as you go” model for performance assessment, a seasonal capacity market and additional inputs to CPQR.

MN8’s presentation said PJM’s two-tiered PAI system risks including hours that are not relevant to maintaining reliability and could incentivize some resources in a discriminatory fashion. The PJM proposal would have a minimum of 30 assessment hours for each delivery year, with generators’ performance being assessed in the tightest hours if there are not 30 emergency hours in a delivery year.

The proposal would instead use a pay-as-you-go design for performance assessment where a performance factor would be determined for each generator at the end of a delivery year to calculate compensation. Those resources that underperform would collect a portion of revenues cleared in the BRA, while overperformers would receive all their cleared revenues plus a portion of uncollected revenues as a bonus.

Should the capacity market continue to carry a significant risk of penalties, the MN8 proposal suggests that CPQR should consider opportunity costs, expectations of penalties and bonuses, and the costs to manage risk.

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P3 Challenges FERC Ruling on PJM Changes to 2024/25 BRA at 3rd Circuit

The PJM Power Providers (P3) last week asked the 3rd U.S. Circuit Court of Appeals to overrule a FERC order allowing PJM to recalculate the reliability requirement parameter for Base Residual Auctions (BRAs) after bids have been submitted but before the auction closes.

The commission’s February order was centered on the 2024/25 auction, which would have seen capacity prices increase fourfold for the DPL South locational deliverability area. (See FERC OKs PJM Proposal to Revise Capacity Auction Rules.)

PJM attributed the increase to the reliability requirement calculation including resources that didn’t ultimately bid into the capacity auction. It explained that certain resources, such as disproportionately large generators or intermittent resources, can cause an increase in the reliability requirement to account for the imports needed when they are unavailable.

The RTO “ran an auction consistent with the rules; they didn’t like the outcomes of that auction, and they changed the rules,” P3 President Glen Thomas told RTO Insider.

He said that changing auction rules after companies have entered bids in part informed by those rules amounts to retroactive ratemaking and undermines confidence in the markets.

“If that’s going to be the new normal, that’s going to be something everyone participating in the PJM markets is going to have to consider,” he said.

P3 in its filing pointed to Commissioner James Danly’s dissent from FERC’s order in which he predicted it would be struck down by the courts for violating the filed-rate doctrine. He compared changing auction parameters after bids have been submitted to a game of blackjack in which the house changes the rules after the cards have been revealed.

“The house saves a bit of money on one hand, but no one ever plays blackjack at the Federal Energy Regulatory Casino again. That is this case. The only difference is that the capacity market is not a game but rather the mechanism by which we ensure sufficient generation resources are built and maintained to keep the lights on,” Danly wrote.

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Brattle Report Sees Benefits for SC RTO Membership

Participating in an RTO could provide South Carolina with benefits of up to $362 million per year, according to a report Brattle Group presented to a special joint legislative committee on Monday.

Annual Benefits vs Status Quo (Brattle Group) Content.jpgBrattle Group estimates South Carolina ratepayers can save $25 million to $120 million in the near term and $150 million to $370 million in the long-term if the state transitions to full or partial use of competitive generation supplies. | Brattle Group

The report to the Electricity Market Reform Committee found that joining PJM would lead to the most benefits (up to $362 million per year), followed by South Carolina — and possibly some of its neighbors — forming a new organized market in the Southeast (up to $187 million). The report also covers a system like CAISO’s Western Energy Imbalance Market (as much as $25 million in net benefits) or setting up a joint dispatch agreement (JDA) between that state’s utilities that would save up to $11 million annually.

Duke’s two South Carolina utilities operate under a JDA, which could be expanded to include Dominion, Santee Cooper (a state-owned public utility) and others that serve the state.

South Carolina could also integrate with an existing RTO, but under a new governance model that would be similar to the Western EIM, with the addition of a day-ahead market and resource adequacy pooling.

Brattle said its savings projections were in line with other benefits studies around the country, which show 4 to 8% operational savings from RTO membership. When Louisiana joined MISO, it was able to cut its reserve margin from 18% to 12%, which is consistent with the savings projected in South Carolina.

Benefit Cost Analysis (Brattle Group) Content.jpgBrattle Group estimated South Carolina customers can save up to $360 million per year if the state participates in a regional wholesale market. | Brattle Group

All the scenarios include operational benefits because they let power flow more freely over a wider region, but joining or creating an RTO comes with additional investment cost savings from coordinating resource adequacy over a broader region, which enables lower reserves for the state.

No Loss of Reliability

At Monday’s hearing, Brattle principal and report co-author John Tsoukalis said that the lower reserve margin would still provide the same level of reliability.

“Everybody in the market can achieve the same level of reliability with a slightly reduced reserve margin,” he added.

The main reason joining PJM leads to more benefits than setting up a new Southeast RTO is that South Carolina’s immediate neighbors have similar supplies, so trading power would not bring the state’s utilities as much income as linking up to the more expensive market serving the Mid-Atlantic and Midwest, Tsoukalis said.

Committee members at the hearing asked questions about Brattle’s conclusions, and legislators will use the report to inform their decision on any changes to the state’s regulatory structure. Committee co-chair Sen. Tom Davis (R) said at the hearing that the committee must make recommendations to the full legislature by January.

Setting up a joint JDA, an EIM or a new RTO are all lengthy processes that would include coordinating with entities outside of South Carolina’s control.

Joining PJM is the most expeditious path to full RTO membership, with PJM in the past having taken on new members in as little as 18 months.

“Under this model, South Carolina would operate within all existing RTO market and governance structures, including the option to retain its vertically integrated and state-jurisdictional utility structure,” Brattle said in the report.

Brattle found the biggest benefits came to South Carolina when it worked with its neighbors on its decision, advising the legislature to especially reach out to North Carolina. Dominion Energy North Carolina is in PJM already, but the rest of the state is not in any market.

South Carolina is also considering retail market reforms, but Tsoukalis said that moving on wholesale reforms first would make the most sense as they will inform potential changes to its retail regulations.

The committee posted a document of comments on the study, and while the state’s utilities largely focused on technical findings, AARP South Carolina opposes joining an RTO, saying it bases its views on “the realities of RTOs after 25 years in states that have them.”

“Our members in Texas and California have suffered from power interruptions and higher electricity prices caused by the complicated new RTO-induced structures where no one is clearly in charge of keeping the lights (and air conditioning and heating) on,” AARP said.

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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.