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August 23, 2024

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SPP Issues Final Markets+ Proposal

SPP on Wednesday released a final proposal detailing the proposed governance structure, basic market design and other key features for the RTO’s day-ahead market offering in the Western Interconnection.

The RTO will now spend the next few months engaging with parties that have already expressed interest in committing to Markets+, a conceptual bundle of services that centralizes day-ahead and real-time unit commitment and dispatch. SPP says the market and its “hurdle-free transmission service” will help integrate the region’s rapidly growing fleet of renewable generation.

SPP has held several in-person meetings and webinars over the past year to gather input and reach agreement with potential stakeholders on the service offering. CEO Barbara Sugg said in a press release that collaborating with Western stakeholders on the Markets+ design has been a “tremendous effort.” (See Governance, Resource Adequacy Key to SPP’s Markets+.)

“Thanks to the dedication and engagement of these entities over the past year, I’m confident we can design and deliver a market that addresses challenges unique to the region and provides value to western customers,” she said.

SPP Final Markets Service Offereing (SPP) Content.jpgSPP’s final Markets+ service offering | SPP

The service offering anticipates a two-phase process for continued development of Markets+. Potential participants and stakeholders will financially commit to design the market protocols, tariff and governing documents in the first phase. A second phase begins after FERC’s approval of the tariff; SPP will acquire the necessary software and hardware while participating entities fully commit to fund and are integrated into the system.

Parties interested in committing to financing further development of the market must sign a funding agreement by April 1 that will cover SPP staff’s involvement.

Load and/or generation entities that sign the agreement would get a vote on the Markets+ Participants Executive Committee (MPEC) in the first phase, and their representatives would be eligible for appointment to working groups and task forces. Those without load or generation would sign a participation agreement and make a one-time $5,000 payment or obtain a waiver in order to vote on tariff and protocol recommendations.

The MPEC is akin to SPP’s Markets and Operations Policy Committee in the Eastern Interconnection. It will provide a forum for market participants, stakeholders and non-voting stakeholders to discuss issues and to review system or process-improvement proposals recommended by SPP, the Markets+ State Committee and members and stakeholders.

The committee will report to the Markets+ Independent Panel (MIP), the highest level of authority for decisions related to the market, but with the SPP Board of Directors providing independent oversight. SPP said the board will “give significant recognition and deference to the [MIP’s] decision-making role.”

Because the RTO does not expect the MIP to be established during phase one, a three-person subcommittee of the SPP board will perform the decision-making functions until the MIP can be formed.

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‘Conceptual’ Tx Planning Map Troubles MISO Members

CARMEL, Ind. — MISO sparked strong reactions from stakeholders Tuesday when it fired up the second phase of its long-range transmission plan (LRTP) by debuting a theoretical map of projects.

In a presentation to MISO’s Planning Advisory Committee, the RTO’s Senior Director of Transmission Planning Laura Rauch revealed a “conceptual map” of possible projects that may arise from a second attempt at a long-range analysis.

Some members were startled by the potential scope of the RTO’s ambitions.

The possibilities for MISO Midwest include a crisscrossing system of new 345-kV lines, a network of 765-kV lines, a handful of 138-kV lines and even one HVDC line across Lake Michigan and another spanning North Dakota and Minnesota.

MISO’s first $10 billion LRTP portfolio was also confined to MISO Midwest. The RTO doesn’t plan to address MISO South needs until the third leg of its long-range transmission planning. (See MISO Board Approves $10B in Long-range Tx Projects.)

Rauch cautioned that MISO’s conceptual map does not represent what a final portfolio would look like.

MISOs 2nd LRTP portfolio Ideas (MISO) Alt FI.jpgAll line ideas considered under MISO’s 2nd LRTP portfolio | MISO

“This is a starting point, not an ending point,” she said, adding that the line routes are educated guesses because MISO doesn’t yet know how siting will play out.

“I’m sure there are things on this map that we will not want to analyze. I’m sure there are some substations that cannot handle … the magnitude of transmission,” she said.

Rauch said it’s still an open question whether the second LRTP cycle should include 765-kV and dispatchable HVDC lines.

Some stakeholders said they were taken aback by the scale of MISO’s envisioned second LRTP.

“When you throw this slide up, this is very expensive, what’s on here. Much more expensive than tranche one,” said Jim Dauphinais, an attorney for the Coalition of Midwest Transmission Customers.

Rauch said the map could potentially be the “size of the answer,” but added that the resulting portfolio could be smaller.

WEC Energy Group’s Chris Plante called the map “uncharted territory” and said it was premature for MISO to publish the map before it ran analyses. Plante also said that the map doesn’t include some lines utilities deemed necessary. He cautioned against sharing the map with MISO’s Board of Directors next week at its quarterly meeting in Orlando, Fla.

Other stakeholders said MISO’s release of the map might preclude consideration of other necessary transmission solutions that should be included in the second LRTP.

“I understand where you’re coming from. At the end of the day, the analysis will win out,” Rauch said. “This is going to be a long ride based on analysis. … Our intention was not to say we must do everything.”

While acknowledging that the release of the map may have been a “messy” way of broaching the issue, Rauch said it’s necessary to prepare stakeholders for MISO’s future system needs. She added that stakeholder LRTP workshops in 2023 will cover the RTO’s reasoning behind the hypothetical map of lines.

Rauch said MISO is building models to prepare for the second portfolio recommendation in 2023.

“We’re seeing member plans accelerating. We’ll continue to work through the futures and reflect that,” she told stakeholders.

The RTO is updating the data behind its three, 20-year transmission planning futures in time for more long-range transmission planning and work on the 2023 Transmission Expansion Plan (MTEP 23).

Changes will include revised state and member decarbonization goals, resource retirements, resource additions based on its interconnection queue, accredited capacity amounts, and capital, operating and fuel costs. MISO did not alter the 20-year load forecast behind the three planning futures.

So far, MISO has only shared preliminary information on its moderate, second future. The RTO said it foresees 270 GW of new resources and has 115 GW of resource retirements. It also anticipates a 90% reduction in emissions by 2042, faster than it previously projected.

The grid operator plans to share estimates from its conservative Future 1 and aggressive Future 3 next spring.

The second planning future will serve as the “focal point” for the lines MISO will plan under the second LRTP, Rauch said.

Zeroing in on Cost Allocation

A day before stakeholders got a glimpse of MISO’s controversial planning map, they heard how MISO continues to assess how to develop a more targeted cost sharing methodology for LRTP projects.

Milica Geissler 2022-11-28 (RTO Insider LLC) FI.jpgMilica Geissler, MISO | © RTO Insider LLC

Speaking at a stakeholder meeting on Nov. 28, cost allocation specialist Milica Geissler said the RTO will analyze whether it can allocate transmission costs by relying on more granular measures of identifying who benefits — and what the benefits are.

Geissler said MISO will examine the subregional benefits of preventing load shed, meeting NERC criteria, weathering extreme events, furthering state decarbonization goals and increasing transfer capability.

At the local zonal level, the RTO will test the benefits of avoided transmission investment, congestion and fuel savings, improved operating reserves and savings associated with resource adequacy. It will not test for any benefits on a footprint-wide basis because of its Midwest-South transfer constraint.

Some stakeholders argued that there’s too much overlap among the factors being considered to identify standalone benefits.

Plante said projecting some of the benefits into the future is akin “to throwing a dart in a blackened room” because benefits change over time and MISO lacks insight into future resource siting and expansion.

Clean Grid Alliance’s Natalie McIntire said MISO shouldn’t assume that the Midwest and South regions are unable to help each other during extreme events. The RTO’s Director of Cost Allocation and Competitive Transmission Jeremiah Doner said that while such benefits aren’t “zero,” they’re not enough to measure on a footprint-wide basis.

Mississippi Public Service Commission attorney David Carr encouraged MISO to consider that including decarbonization benefits might make it more difficult for some projects to get approval from certain utility commissions.

Geissler said MISO is at this point only pondering the benefits and hasn’t determined which ones will make the final cut. She added that the RTO isn’t willing to apply any proposed changes to projects already in progress, saying it “finds a lot of value” in current allocations.

MISO is using a 100% postage stamp to load rate for the first two cycles of projects coming out of its LRTP studies, with those costs confined to MISO Midwest. (See FERC OKs MISO’s Bifurcated Cost-allocation Tx Design.) But a new cost allocation approach that considers more beneficiaries could be applied to upcoming planning for the South region.

Carr said MISO should re-examine the assumption that load bear the “entirety” of long-range transmission costs. He made the argument in light of Montana-Dakota Utilities’ suggestion that new intermittent generation, in addition to load, should bear a portion of LRTP costs. (See MISO Gathering Stakeholder Input on LRTP Cost Allocation.)

“Transmission costs are a much larger share of customers’ bills. This situation is untenable,” Carr said.

Carr also pointed out that years ago, MISO South didn’t have any input in the postage stamp cost allocation.

Some stakeholders have voiced concerns about disparate treatment between LRTP portfolios, saying a different cost allocation for projects concerning MISO South will violate FERC’s requirement that the same class of projects should not be subject to different allocations.

In October, Geissler said planners were wrestling with how to assign an evolving cost allocation when beneficiaries of a line change over time. Some stakeholders have requested that MISO find a way to identify and mete out costs to new beneficiaries over time.

“I’m very thankful for the 2011 portfolio of projects,” Geissler said, referring to MISO’s Multi-Value Projects approved a decade ago. She said those projects show how benefit-to-cost ratios either increased or decreased over time depending on the transmission pricing zone.

“They change in a pattern that isn’t necessarily obvious,” Geissler said of benefits. She said those fluctuations mean that future beneficiaries might be difficult to predict over time.

However, stakeholders said the zones that over time realized the most benefits from the 2011 portfolio contained the most wind generation.

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Sunflower’s New CEO Hillman Looks Back on MISO Tenure

Todd Hillman, currently MISO’s senior vice president and chief customer officer, is ending his nearly 20-year stretch with the grid operator and will become Sunflower Electric Power Corp.’s new CEO next year.

Sunflower’s board of directors on Nov. 21 named Hillman as its new CEO following a nationwide search. Hillman will succeed departing CEO Stuart Lowry.

Steve Epperson, CEO of Pioneer Electric Cooperative and Southern Pioneer Electric Co., two of Sunflower’s seven distribution member-owners, said Hillman is a “best fit” for Sunflower.

“I see great teamwork, collaboration and courageous decisions in our future and am confident that Mr. Hillman will deliver,” Epperson said in a press release.

At MISO, Hillman was responsible for customer relations, including member and regulatory relationships, and managing training, facilities and the RTO’s call center.

Hillman said it will be “bittersweet” leaving the organization. He joined MISO in 2004 as it prepared to launch its energy markets in April 2005.

“Imagine 100 employees, give or take. It was all-hands-on deck,” Hillman said in an interview with RTO Insider. “I just remember so much happening, and it was going so fast, and everyone was working on everything.”

MISO currently has about 950 employees.

Hillman said his first title with the grid operator was the generic “executive director.”

“We weren’t quite sure what the role meant yet,” he said.

Hillman joined the RTO after a stint at Reliant Energy’s offices in the Netherlands, where he managed various electricity, natural gas and transmission contracts. While there, he also established a European satellite office in Frankfurt, Germany. After Reliant’s sale of its Dutch operations, he returned stateside for Reliant before landing at MISO’s Carmel, Ind., headquarters.

“So naturally after working in Europe, Carmel, Indiana, is the next logical step,” he said.

“Todd’s contributions to MISO have been unbelievable,” MISO CEO John Bear said during an executive update Monday. He thanked Hillman for his dedication in integrating the MISO South region.

Hillman said MISO’s successful integration of Entergy as MISO South in 2013 ranks among its greatest achievements during his tenure. He described the work as “climbing Mt. Everest with one hand tied behind your back.”

“It took a village to do that,” he reflected.

Hillman said he considers the grid operator’s employee culture as his greatest personal accomplishment. He said he’s proud of the strides made on workplace diversity, equity and inclusion. He pointed to the creation of dedicated resource groups for employees who are also caregivers or veterans and employees’ annual $1 million in contributions to the Make-A-Wish Foundation.

“I look back, and I think about the culture,” Hillman said.

He said MISO today allows its employees to be creative and thrive in an industry that “isn’t smooth sailing.”

Hillman said MISO’s endeavor to attract and retain talent must continue. However, he said MISO is making progress and voiced confidence in Allegra Nottage, the RTO’s first chief diversity officer. (See MISO Installs First Diversity Officer; “High employee turnover concerns leadership,” MISO Board Week Briefs: Sept. 12-15, 2022.)

Hillman said MISO has a “huge opportunity to reset the turmoil” wrought by the Covid-19 pandemic and the Great Resignation.

“I feel like it’s a work in progress, but I know I leave it in great hands,” he said.

Hillman remembered challenging times during MISO’s early days, when Ohio and Kentucky members departed the footprint as former CEO James Torgerson also announced his exit in 2008.

“Imagine you’re having all this turmoil against a senior leadership change,” Hillman said.

Hillman said in all, MISO lost 7% to 10% of the footprint but gained roughly 30% in service territory with a spate of new memberships that began with MidAmerican Energy’s entry in 2009.   

“So, we lost members, but then we had more members come on [within] a few years,” he said.

Hillman also said he has thought about his impending transition from MISO to SPP, where Kansas-based Sunflower is a member. The two RTOs attempted to merge last decade and remained rivals until recently.

“I promise I’m going to be a very good stakeholder,” he said. “I know how tough it is, so I want to be a help.”

Hillman said he’s encouraged by the RTOs’ collaboration in recent years and said he will place his Sunflower hat on and will advocate for his utility. “As it gets tougher in the business, the more those relationships can improve,” he said.

Hillman said he’s taking three important lessons learned from his time at MISO to Kansas.

“You always assume noble intent with anyone you’re working with,” he said. “Very few times are there issues that are black and white, and you can’t get the ball across the line. We have to figure out how to get that [assumption of] noble intent on both sides up across the industry.”

He said he plans on listening to all sides of an issue, something that’s served him well working with MISO’s 11 sectors and their differing viewpoints. He also said he will always remember that people are responsible for the electric industry’s operations and progress.

“This is very complex work at the end of the day. And I always remember that there are people behind it,” Hillman said.

He said he’s excited about Sunflower’s “main street” element and meeting customers. Hillman joked that he’s equally excited to “serve just one state,” instead of the 15 in MISO’s footprint.

Hillman said he’s “learned from the best” from MISO and its members and said he’s taking those leadership templates with him to Sunflower.

“People ask me, ‘Are you ready to be CEO?’ I don’t know, but I feel incredibly confident that if I can be anywhere near what they have done, I’ll be all right.”

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Red State AGs Challenge Vanguard Climate Activism

Attorneys general from 13 conservative states asked FERC this week to reject Vanguard’s request for a waiver allowing it to acquire large stakes in utilities, saying the investment giant’s climate activism violates its promise not to influence the companies’ management (EC19-57-001).

Attorneys general from Utah, Indiana, Alabama, Arkansas, Kentucky, Louisiana, Mississippi, Montana, Nebraska, Ohio, South Carolina, South Dakota and Texas cited Section 203 of the Federal Power Act, which prohibits holding companies like Vanguard from acquiring more than $10 million in securities of a utility without commission authorization.

In 2019, the commission granted Vanguard a blanket authorization to acquire up to 20% ownership in aggregate by Vanguard and its affiliates and subsidiaries or up to 10% ownership by any individual Vanguard fund. The commission said it was relying on Vanguard’s assurances that it would not invest “for the purpose of managing” utility companies or seek to “exercise any control over the day-to-day management” of them.

“Now, Vanguard’s own public commitments and other statements have at the very least created the appearance that Vanguard has breached its promises to the commission by engaging in environmental activism and using its financial influence to manipulate the activities of the utility companies in its portfolio,” the AGs said. They asked the commission to hold a hearing to determine whether Vanguard has violated the 2019 authorization and whether granting it an extension is in the public interest.

In February, Vanguard asked FERC to extend the initial three-year authorization for another three years.

Vanguard did not respond to a request for comment Wednesday.

The AGs cited Vanguard’s 2021 decision to join the Net Zero Asset Managers Alliance, nearly 300 asset managers who pledge to work together to “accelerate the transition towards global net zero emissions” and to prioritize “the achievement of real economy emissions reductions within the sectors and companies in which [it] invest[s].”

The states also pointed to Vanguard’s membership in the Ceres Investor Network, which works with “investors around the world to accelerate action on climate change.” Vanguard has told its portfolio companies that it will support shareholder proposals requiring the pursuit of climate risk mitigation targets, the states say.

They noted that Berkshire Hathaway’s PacifiCorp, which serves Utah, currently gets 20% of its energy from coal or natural gas. “Consumers in Utah would be harmed if their costs went up because of closure of these facilities or substitution of more expensive energy sources,” they said.

“We are concerned that Vanguard’s actions with respect to influencing environmental corporate policy — especially in combination with the stated motives of [money managers] BlackRock and State Street Global Advisors — will inflate the rates consumers and our states pay for electrical service.” (See BlackRock to Divest from Coal Companies.)

Extension Sought

Vanguard’s request to extend the 2019 waiver also asked FERC to exclude from the 10% and 20% limits securities of utilities in portfolios managed by unaffiliated external advisers.

On Aug. 8, the Office of Energy Market Regulation extended the 2019 authorization for nine months, prompting a critical joint statement from Republican commissioners James Danly and Mark Christie, who noted that Vanguard’s assets under management have increased from about $5 trillion to $8.5 trillion since the 2019 order.

“Vanguard’s application raises a number of issues that demand commission scrutiny because Vanguard could potentially exercise profound control over the utilities it owns,” they said. “The commission cannot merely rubber stamp requests for blanket authorizations if it is to carry out its statutory duty to ensure that the accumulation of such substantial equity in utilities is not contrary to the public interest. Should a company like Vanguard seek to influence the management and operation of utilities’ generation portfolio, for example, this could have a significant impact on the rates consumers pay for electrical service.”

‘Woke’ or Not?

In addition to the challenge by the AGs in conservative states, Vanguard’s climate policies have also attracted protests by climate activists such as the Earth Quaker Action Team, which says the fund manager is “the world’s largest investor in coal and #2 investor in major climate-harming projects across the globe.”

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SoCalGas System Still ‘Impaired’ but Winter Outlook Improves

Southern California Gas’ system remains “impaired,” but the risk of service reductions is lower than in previous years because a warm winter forecast could reduce demand for gas-fired electric generation, the California Energy Commission heard Wednesday.

During a joint workshop with the California Public Utilities Commission, Energy Commission staff said two key pipelines are operating at reduced capacity, including one pipeline that ruptured in 2017. An El Paso Natural Gas mainline that ruptured last year south of Phoenix is shut down, limiting supply from the Permian Basin. And storage at SoCalGas’ Aliso Canyon natural gas storage facility continues to be restricted after one of the worst methane leaks in U.S. history in 2015-16.

“Recognizing these restrictions, staff assesses that the risk of service interruptions is lower this winter than in recent winters,” CEC staff wrote in a briefing paper. “This lowered risk is largely due to forecast demand being lower than in prior years. Specifically, staff projects zero curtailment on a winter day cold enough to occur once in 10 years.”

In colder conditions, SoCalGas might have to curtail 280 million cubic feet per day, a tenth of its total pipeline flow of 2.8 million cubic feet per day, the CEC said. The curtailment would affect “noncore load,” mainly electric generators plus some industrial customers and other users.

“Any adverse event, such as a pipeline going out of service, could lead to a higher curtailment,” the CEC report said. “The key risk to reliability is multiday cold weather events with additional infrastructure outages.”

SoCalGas serves nearly 22 million customers, about the same as the population of Florida, in its 24,000 square mile territory.

The CEC’s review is part of its informational proceeding on decarbonization, which it launched with a workshop in June.

“The Energy Commission is making great strides towards enhancing our modeling and analytical capabilities in this winter assessment,” Chair David Hochschild said at Wednesday’s workshop. “We are using our own gas-demand forecast results for the first time, [and] we’ve been able to dig deeper into the winter demand scenarios. All this leads to more verifiable results that feed into the gas decarb.”

Aliso Canyon

Aliso Canyon, regarded as both a threat to public safety and essential for reliability, has been a sticking point in that effort.

Residents and public officials have repeatedly called for its shutdown after it spewed more than 100,000 tons of gas into the atmosphere. The leak was contained after four months and multiple failed attempts.

SoCalGas and parent Sempra Energy agreed to pay $1.8 billion last year to settle the claims of 35,000 residents who claimed they suffered physically and emotionally from the leak.

In November 2021, California’s two Democratic senators, Dianne Feinstein and Alex Padilla, issued a joint statement saying it is “critical that the California Public Utilities Commission outline concrete steps to close this facility while ensuring the reliability of our power grid.”

The storage facility serves more than 11 million customers and provides fuel to 17 gas-fired plants, according to SoCalGas.

“It is a critical part of the region’s energy infrastructure,” the utility says on its website. “More than 90% of Southern Californians depend on gas for heat and hot water, and approximately 60% of all the electricity generated in California is made by natural gas-fired power plants.”

Last November, the CPUC increased Aliso Canyon’s storage limits from 34 billion cubic feet to 41 billion cubic feet because of reliability concerns — still well below its pre-leak capacity of 86 Bcf. Climate change-induced extreme weather “unfortunately has created greater short-term dependency on natural gas generation,” former Commissioner Martha Guzman Aceves said at the time.

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FERC Approves PJM Plan to Speed Interconnection Queue

FERC on Tuesday approved PJM‘s proposal to speed up its interconnection queue by handling requests through a new clustered approach that prioritizes projects that are ready to build (ER22-2110).

Under the new paradigm, PJM will shift away from its current first-come, first-served methodology to instead study new service requests with a first-ready, first-served approach that clusters proposed projects together to determine network impacts and allocate network upgrade costs. Much of the backlog of submitted projects will be grouped into transitional cycles, which are expected to be completed in the fourth quarter of 2026.

PJM Vice President of Planning Kenneth Seiler said the RTO sees FERC’s Nov. 29 order as a win for interconnection customers, stakeholders and electric users by allowing projects to more quickly move through the queue and begin development. He credited the transparency and dialogue with stakeholders through the process of drafting the proposal with creating a solution that was accepted by the commission nearly unaltered.

“We’re very happy with how FERC has come forward with this,” Seiler said.

An Aug. 30 deficiency notice from the commission seeking more information from PJM did not affect the anticipated timeline for implementing the new transitional process, Seiler said, and staff will be discussing the next steps at the Dec. 6 Planning Committee meeting. (See FERC Issues Deficiency Letter on PJM Queue Overhaul.)

“I believe we’re well on track to move forward,” he said.

Signing off on Tuesday’s order were commissioners James Danly, Mark Christie, Willie Philips and Allison Clements, who wrote a concurrence. Only Chair Richard Glick did not participate in the order; FERC’s Division of Media Relations could not supply a reason for his non-participation.

The order also requires two compliance filings from PJM. The first, due within 30 days, calls for new tariff language codifying that only new service requests with no network upgrade costs and that do not require further studies can receive acceleration to a final interconnection-related agreement.

The second filing is due 60 days before PJM begins to study interconnection requests under its new rules, after the completion of the transitional studies.

PJM is also required to submit informational reports alongside its Order 845 filings during the transitional period, detailing its progress toward reducing the backlog. The reports are to include the number of studies completed, average completion time, the number remaining in each cycle queue and updated timelines on when the RTO expects to begin and complete each phase.

Approval Paves Way for New Rules and Transitional Process

PJM has argued that the queue changes were needed as the number of new service requests tripled from 2019 through 2022, with more than 2,700 active projects as of May 10. In a letter accompanying filing, the RTO said the current interconnection process doesn’t provide incentives for speculative projects to leave the queue in timely fashion. When such projects exit the queue late in the process, they trigger restudies impacting the cost allocation for other submissions further down the queue.

Shifting from a process of studying and allocating costs for each project individually, the new approach groups projects into clusters and conducts studies in three phases, with an increasing share of a readiness deposit required at each step equal to a portion of the network upgrade costs.

Deposits vary with the size of a project, ranging between $75,000 and $400,000. There will be “off-ramps” — or decision points — between each phase for developers who wish to discontinue their projects and partial refunds of the deposits.

Developers also are required to show evidence of site control, with escalating degrees required the further a project has progressed through the three phases. Currently, developers are only required to demonstrate site control once when submitting a project and only for the generator site.

For two queue cycles, projects that entered the queue between April 2018 and September 2021 will be studied under transitional rules, while projects valued under $5 million will be subject to a “fast track” process. PJM will begin to conduct studies under the new rules after completion of both the transitional cycles and the fast-track process.

Many protestors raised concerns about the potential for the fast track to allow less mature — and possibly speculative — projects to jump the queue over more mature, higher-cost projects. Protestors also complained that the $5 million threshold was arbitrary and that the readiness deposits are insufficient to weed out speculative submissions. (See Renewable Devs Criticize PJM Response to FERC on Queue Proposal.)

But FERC found that the interconnection rule changes strike a balance of allowing PJM to expedite its ballooning interconnection backlog, helping developers progress their projects toward construction, and letting mature projects continue under the current rules.

“PJM’s proposed transition mechanism is a reasonable means of implementing PJM’s queue reform proposal and reasonably balances the interests of completing the interconnection study processes for mature New Service Requests under PJM’s current rules with the need to move expeditiously to a first-ready, first-served clustered cycle approach in order to clear the significant backlog and begin full implementation of the New Rules,” the commission wrote in its order.

“We recognize that PJM’s proposed queue cycle cutoffs for use of the current rules and the Transition Period Rules will inevitably exclude certain interconnection customers, but, as the commission has pointed out in multiple queue reform proceedings, ‘any cutoff date inevitably will have that effect.’”

Operational Penalties Eliminated for Late Tx Service Request Studies

The approved proposal also removes tariff language outlining penalties for transmission studies that are not completed on time, which PJM argued is now unnecessary given that FERC Order 845 requires that failures to meet study deadlines be publicly reported to the commission.

Protestors contended that removing the language would contradict the commission’s interconnection notice of proposed rulemaking and said the provision would lengthen delays for firm transmission service customers. But FERC determined that removal of the tariff language meets the requirements of Order 890, as the penalties “would not necessarily target delays due to studying firm transmission service requests.”

Clements Concurs Reluctantly

Clements issued a concurring opinion in which she expressed reluctant support for approving PJM’s proposal, which she described as an imperfect solution to an interconnection queue that has “spiraled out of control.”

Clements was most concerned about the requirement that developers demonstrate 100% site control for interconnection facilities at the decision point at the end of the third study phase. She noted that commenters’ protests raised the possibility that viable projects could be removed from the interconnection queue, particularly should a generation-owning transmission owner direct a late-stage route change to force a project out of the queue.

“They argue that the site control requirement may prove to be too onerous in practice because gen-tie line sites may involve numerous small land parcels for which minor issues could come up, and because last minute changes in line routes may occur. PJM’s untested approach appears to be unique among RTOs,” she said.

Clements’ also expressed concerns about the elimination of penalties for transmission service request studies that do not meet their deadlines, a revision she said only complies with the commission’s Order 890 due to the “unique circumstances of PJM’s interconnection process.”

To create an interconnection process that meets the needs of customers, she said the approved proposal should be viewed as “one step upon which several others could conceivably be layered.” She encouraged PJM and other RTOs to consider implementing forward-looking study processes that would provide those applying for interconnection with a more information that is less prone to unpredictable changes based on changes to the queue.

“Further changes that hold potential to accelerate PJM’s interconnection queue include modifying the threshold at which network upgrades are triggered by the interconnection process, and adjustments to cost allocation for interconnection upgrades such that network upgrade costs are less likely to spur queue withdrawal,” she wrote.

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NECEC Scores Another Victory in Maine’s Highest Court

Maine’s high court on Tuesday issued another favorable ruling for the New England Clean Energy Connect (NECEC) transmission project, increasing the possibility that the contentious line will be resurrected.

The decision by the state’s Supreme Judicial Court marks the second in favor of the project since August, when it found that a referendum blocking the project may have been unconstitutional. (See Maine Court Ruling Gives New Life to Contentious Transmission Line).

In Tuesday’s order, the court reversed an August 2021 decision by the state’s Business and Consumer Court to vacate a lease agreement for public lands between the Maine Bureau of Parks and Land (BPL) and Central Maine Power, NECEC’s developer.

The court said that the BPL had followed the appropriate process in approving the lease, and found that Question 1, the referendum Maine voters approved in 2021 to oppose the project, had not vacated the lease.

“Because we conclude that the evidence contained in the record is sufficient, we see no reason to impose a further burden on the parties’ time and resources by remanding for the Bureau to take further evidence,” the five-judge panel wrote. “We conclude that the record establishes that the Bureau acted within its constitutional and statutory authority in granting the 2020 lease.”

Together, this week’s ruling and the August one mark significant victories that could put the project back on track.

“We think these two decisions have resuscitated the viability of the transmission project,” ClearView Energy Partners said in a note to clients.

A legal fight over Question 1 will continue, with the Business and Consumer Court set to hear more arguments in April as to “whether or not CMP had vested rights to complete construction of transmission line,” according to ClearView.

Depending on how that decision goes, CMP could restart construction as early as mid-2023, or face the prospect of having to make another appeal to the state’s highest court.

“Today’s ruling by the Law Court is yet another step in the right direction for Maine’s renewable energy future,” Scott Mahoney, senior vice president at CMP parent company Avangrid, said in a statement.

NECEC proponents have been arguing for years that the project is necessary to transmit electricity from hydro plants in Quebec down through Maine and into Massachusetts.

“The serious need for the NECEC project to reduce our reliance on fossil fuels, combat climate change, and lower regional energy prices remains unchanged,” Mahoney said.

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Ohio Lawmakers Envision a State Nuclear Development Authority

Ohio lawmakers appear to be on track to create a nuclear development authority that would promote the state as a center for companies seeking to develop small modular and other advanced reactors and engage in related nuclear research.

The effort stems from House Bill 434, which was introduced in September 2021, approved by the Ohio House on a 75-to-18 vote in May and referred to the Senate. Backers of the bill testified Tuesday before the Senate Energy and Public Utilities Committee.

Proponents contended that the federal agencies that have dominated expensive nuclear research and development will in the future look to interact with state authorities that organize R&D efforts to attract entrepreneurial nuclear research companies such as TerraPower, which was founded by Microsoft co-founder Bill Gates.

The Washington-based company is focusing on the development of reactors cooled by molten chloride salt, a technology pioneered decades ago at Oak Ridge National Laboratory but abandoned when light-water reactors proved more practical to build given the technology of the day. Proponents of the new authority cited the reactor design as the kind of advanced technology that Ohio ought to be attracting.

William Thesling, an electrical engineer and lifelong Ohio resident, singled out molten salt reactors in his testimony.

“A goal of House Bill 434 is to make Ohio a leading state in advanced nuclear technology research, development and commercialization,” Thesling said.

“This has some enormous long-term benefits for Ohio as a manufacturing state,” he said. “There has been much advancement in materials technology, digital controls, sensors, instrumentation and computer modeling over the past several decades. These gains in technology have allowed us to revisit old technologies that were previously considered to be not viable.  Nowhere is revisiting an old technology more compelling than molten salt reactor technology that was abandoned in the early 1970s largely for political reasons.”

Other proponents argued that U.S. Department of Energy and the Nuclear Regulatory Commission would, under a provision in the 1954 Atomic Energy Act, be obligated to work with a state authority such as what Ohio intends to create.

A spokesman for the NRC had no immediate comment other than that the agency does not normally comment on state issues.  A DOE spokesperson could not be reached.

The next hearing by the Senate committee, which has not yet been announced, will focus on opposing testimony.

HB 434 is the work of Rep. Dick Stein (R), who argued that there has been a change in public sentiment about new nuclear technologies.

“In recent years, there has been a global shift in attitudes toward the development of new nuclear technologies to deploy scalable clean energy,” Stein said in a prepared statement. “This legislation will bring Ohio to the forefront of advanced nuclear innovation and strengthen our domestic supply chains.”

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Montgomery County, Md. Passes Building Electrification Law

Maryland’s largest county on Tuesday passed the state’s strongest building electrification law, requiring most new residential and commercial construction be powered by electricity or other carbon-neutral technologies.

The Montgomery County Council voted to require issuance of the regulations for most new construction by Dec. 31, 2026 (Bill 13-22).

Electrification requirements for residential buildings of four stories or more, affordable housing and schools were pushed back to the end of 2027.

The unanimous vote ended months of negotiations over the bill, which had originally called for the electrification standards to be issued by Jan. 1, 2024, and would also have required electrification for “major renovations and additions.”

The revised deadlines were among a series of amendments to the bill, which in its original form had triggered strong opposition from local builders, Realtors, chambers of commerce and utilities.

Removing the provisions on renovations and additions helped minimize some of the conflict, said At-Large Councilmember Hans Riemer, who led negotiations on the bill as chair of the Planning, Housing and Economic Development (PHED) Committee.

Figuring out “when a house gets triggered to have to transform all its existing systems to electric, when it may have a … gas-burning furnace, that is an extremely difficult process,” Riemer said. “The [county’s] Department of Permitting Services is not there yet, and they need some time.”

The committee also recommended exemptions for buildings that treat sewage or food waste, along with “the cooking portion of restaurants” and other commercial kitchens, such as kitchens in a church or community center. Farming and “farm alcohol production” — specific types of breweries — will also be exempt.

At-Large Councilmember Will Jawando, who co-sponsored the bill with Riemer, called the revised deadlines “a decent compromise. Obviously, we want to move as quickly as we can. … We want to send a strong message, passing this bill unanimously, that we need to move to all electrification. If this helps us get there, I think it’s something that is worth doing.”

Riemer also noted that about three-quarters of commercial buildings in the county are already all-electric, so that the electrification requirement will not hurt the county’s competitiveness for commercial development.

“We’re confident that the private sector is on a path already to make this very feasible for the residential sector,” he added.

Doug Siglin, policy advisor for the Chesapeake Climate Action Network, a local advocacy group, would have liked the council to stick with its earlier deadline, but he still sees the bill as “a very important policy step forward. 

“We didn’t get everything we wanted, but we understand that’s the legislative process,” Siglin said. “In the big picture, we think it’s a hugely important policy.”

Flashpoints

With more than one million residents, Montgomery County is Maryland’s most-populous county and, arguably, its most progressive. The county’s Climate Action Plan calls for an 80% reduction in communitywide greenhouse gas emissions below 2005 levels by 2027 and a 100% reduction by 2035.

The Montgomery County school district also has one of the largest electric bus fleets in the nation. (See Md. County’s Electric School Buses to Provide Synch Reserves for PJM.)

But building electrification and green building in general have long been flashpoints in Maryland, with successive attempts to pass a statewide green building code turned back in the legislature. Most recently, green building provisions in the Maryland Climate Solutions Now Act (SB528) were watered down and replaced with a mandate for the state Public Service Commission to undertake a study on the issue. The PSC’s study, which will include cost and grid capacity evaluations, is to be completed by the end of 2023. Gov. Larry Hogan (R) allowed the bill to become law without his signature. (See Md. General Assembly Sends Climate Solutions Bill to Hogan.)

The building electrification law passed Tuesday represents the council’s attempt to balance the concerns of the county’s business community with its climate goals. In a Nov. 15 report, the PHED Committee said that businesses groups and individuals raised concerns about the law’s impact on housing and building costs and whether the grid would be able to manage the increased capacity electrification would cause.

Other issues included who would pay for needed grid upgrades and the potential for delays in constructing large residential developments.

In an email to NetZero Insider, Pepco (NASDAQ:EXC) spokesman Ben Armstrong said the utility shares “similar decarbonization goals as our communities in Montgomery County.” But he also pointed to the need for the PSC study that would outline “system investments necessary to support an all-electric building code,” while maintaining reliability and affordability for all customers.

“We appreciate the increasing demands on the grid as we partner with the county to electrify and decarbonize more energy sectors,” Armstrong said. “The grid is a dynamic and integral part of enabling carbon reduction, and we are fully committed to supporting those efforts.”

Councilmember Sidney Katz said pushing back the electrification deadlines should give all stakeholders more time. “The timing was such a concern for me, and what [building electrification] does to the grid because the grid does not work on a county-by-county [basis or for] the Washington, D.C. area. It works on a regional basis, and we needed to make certain that what we were doing … would be done with that in mind.”

The Dec. 31, 2026 deadline is the same as in Washington, D.C.’s mandate for new construction to be net zero.

Amendments to the Montgomery County law will also require the county executive to provide the council with a report on the PSC findings by September, 2024.

Still another amendment ensures that the final regulations will not go into effect without “active” approval of the council. Council President Gabe Albornoz said requiring the council’s approval would provide “another check and balance” for any final changes, based on the PSC study or any other analyses.

Fireplaces and Grills

The new law also puts Montgomery County on the front lines of what has become a national debate on whether natural gas hookups should be allowed in new construction. According to the Sierra Club, 68 cities and counties in California have banned natural gas in new construction. A counteroffensive by the natural gas industry has resulted in 20 states passing laws prohibiting such bans.

Maryland has not passed a law prohibiting bans or natural gas hookups.

But issue remains divisive. The only amendment the council did not pass unanimously was a proposal from Albornoz to also exempt residential gas fireplaces and outdoor grills, which he argued are “amenities that are popular among certain home builders and that homeowners are looking for.” Gas fireplaces and grills also produce fewer emissions than wood- or charcoal-fired alternatives, he said.

County officials raised concerns that these exemptions could create a loophole that would allow natural gas hookups in new construction, but Riemer said few would be likely to exploit it. “The expense that would be involved in trying to switch out … a brand new, fully functional, very effective electric heating system with a gas system is probably like the biggest waste of money you could imagine doing as a homeowner,” he said.

But Jawando and Council Vice President Evan Glass spoke against the exemption. “It goes against the meaning and what we’re trying to do here and gives an exemption to people who are the wealthiest and able to do this,” Jawando said. “It’s not good for racial equity and social justice reasons, not good for the intent of the bill.”

Gas-fired fireplaces and grills are “aesthetic amenities,” Glass said. “If the goal of this overall bill is to minimize or quite frankly eliminate some of these uses, then I can’t justify doing it or allowing it just for an aesthetic amenity.”

Councilmember Tom Hucker joined Jawando and Glass in opposing the amendment, which passed on a 6-3 vote.

Councilmember Craig Rice voted for the exemption but also stressed the need for the council to focus on “the reality that many people are living in buildings that continue to suffer from lack of environmental justice, and it will be important for us to make sure that as we continue this onboarding process of electrification, that access is provided to those in our community who are of lower socioeconomic status and who are in existing buildings.”

The positive changes from electrification must be “equitable and accessible to all of our residents,” he said.

CCAN’s Siglin is hopeful that by the time the county releases the regulations at the end of 2026, the definitions of “major renovations and additions” can be clarified. The bill is silent on the issue, which leaves the door open for county officials to “figure out what definitions they want and come back with [them],” he said.

Councilmember Andrew Friedson sees building electrification as inevitably leading to a “conversation about the grid. Ultimately, we need a greener grid, and we have started that conversation in a very public and very substantive way, working collaboratively with industry, with our utilities. We all recognize that for this to make the impact we need it to make, that we want it to make, that a sustainable future requires, we need to have the type of grid that is electric; that doesn’t burn fossil fuels nearly at the extent it is now.”

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ERCOT Says ‘Sufficient’ Capacity to Meet Winter Demand

ERCOT has “sufficient” installed capacity to meet a forecast peak demand of 67.4 GW this winter, the ISO said Tuesday.

Based on its latest seasonal assessment of resource adequacy (SARA), the Texas grid operator expects to have about 87.3 GW of winter-rated capacity available during the upcoming cold months. Two thermal resources, a coal unit and a gas-fired unit comprising 685 MW, will be out of service all season, ERCOT said. The SARA report assumes “typical” thermal outages totaling almost 10 GW this winter.

The projected demand is based on average winter conditions for the 2007-2021 winter peaks that would include the devastating winter storm of February 2021, which still raises Texans’ anxiety levels. The SARA report assumes high demand, high thermal outages and low wind output in its various scenarios but not gas supply disruptions, which FERC and NERC said were responsible for most of the generation outages during the 2021 storm. (See FERC, NERC Release Final Texas Storm Report.)

ERCOT’s demand peaked at 77 GW during the 2021 winter storm before the outages became too much to handle. Texas A&M University’s Texas Center for Climate Studies has said demand would have reached 82 GW had there been enough generation to meet demand.

Pablo Vegas (Admin Monitor) Content.jpgPablo Vegas | Admin Monitor

But Public Utility Commission Chairman Peter Lake expressed optimism about the grid’s preparedness during a joint press conference Tuesday with ERCOT CEO Pablo Vegas. “The lights will absolutely stay on,” he promised.

Lake trumpeted new weatherization requirements and other reliability-focused operational reforms directed by lawmakers following the storm as the reason for his confidence. “We’re better prepared than ever,” he said.

“We are in a position where the elements that are within our control related to the reliability and the operation of the grid are as strong as they’ve ever been going into this winter season,” Vegas said. “The majority of the actions that we’ve taken over the course of this year-and-a-half are designed specifically to address any risk of load-shedding.”

The biggest change has been following up on weatherization requirements placed on generators and transmission facilities. After inspecting weatherization practices last winter at plants that experienced problems during the winter storm, ERCOT staff will check on about a third — or 350 — of the system’s resources this year. Vegas said the ISO plans to complete the inspections early next year.

“Those inspections and audits are showing that the work is getting done to keep those generators operating during the most extreme weather conditions,” he said.

Asked about NERC’s recent winter reliability assessment that found ERCOT’s reserve margin could fall as much as 21% below demand in the most severe scenario, Vegas transitioned to the PUC’s market redesign that is currently underway. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)

“That doesn’t take into account things like winterization,” he said of NERC’s assessment. “We’re not trying to underplay it at all. It does reflect a very low-probability scenario.

“But the fact it exists calls out an issue that needs to be addressed … being able to continue to build dispatchable generation to ensure there will always be enough power. That’s why this [market redesign] work that we’re embarking on is so important,” Vegas added.

He and Lake both used a new message in pointing to the continued growth in ERCOT’s demand. They said Texas is adding a city the size of Corpus Christi — the eighth largest in the state at 317,863, according to the 2020 census — each year, placing additional pressure on developing generation resources.

The PUC’s proposed market designs rely on adding dispatchable thermal resources over intermittent renewable resources.

“We have the same amount of reliable dispatchable resources with no target, no reliability standard, which is a key part of the reforms that this commission has evaluated and discussed,” Lake said. “It’s getting harder and harder to do this, because we have more people … this is a long-term problem, the lack of a reliable reliability standard, but the future is coming.”

ERCOT on Tuesday also released its biannual capacity, demand and reserve report. It forecasts a summer peak demand of 82.7 GW, which would be a new record, and a winter peak of 69.4 GW.

The grid operator said next summer’s planning reserve margin will be 22.2%, a 14-point drop from the 36.2% margin in the May 2022 CDR report.