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November 7, 2024

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Biden Appoints California PUC Commissioner to Head EPA Region 9

EPA said Thursday that President Biden intends to name California Public Utilities Commissioner Martha Guzman Aceves to run the region of the agency that includes California, Arizona, Nevada and Hawaii, implementing the administration’s environmental agenda in the far West.

Guzman Aceves has served for five years on the CPUC. She worked previously as former Gov. Jerry Brown’s deputy legislative affairs secretary and for the California Rural Legal Assistance Foundation and the United Farm Workers. Much of her focus at the commission has been on providing clean energy to underserved communities and preventing disconnections of basic utilities.

Martha Guzman Aceves (CPUC) FI.jpgCPUC Commissioner Martha Guzman Aceves | CPUC

“Given Martha’s extensive background in successfully delivering access to underserved communities, I am confident she is an excellent choice to lead our Region 9 team,” EPA Administrator Michael Regan said in a statement. “Martha is an experienced leader that values economic justice and will represent the best interests of the residents in the region.”

Guzman Aceves said she was “honored to be appointed by President Biden to serve as administrator of EPA Region 9 under the leadership of Administrator Regan. And I am grateful for the opportunity to work with the resilient staff at Region 9 as we tackle the chronic and emerging environmental issues in our communities.”

The move continues a series of transitions at the CPUC, an agency tasked with ensuring resource adequacy, preventing utilities from igniting wildfires and shepherding the state through its transition to 100% clean energy by 2045.

CPUC President Marybel Batjer announced in September that that she planned to step down at the end of the year with five years left in her seven-year term. Gov. Gavin Newsom in late November named his senior energy adviser, Alice Reynolds, as the commission’s next president. (See California PUC President to Step Down and Calif. Governor Names Next CPUC President.)

In December 2020, Newsom named then-CPUC Commissioner Liane Randolph as chair of the California Air Resources Board, which oversees vehicle emissions and other types of air pollution. Randolph replaced retiring Chair Mary Nichols, whom Biden reportedly was considering to head EPA at the time. Instead, he appointed Regan, then head of North Carolina’s Department of Environmental Quality. (See EPA Nominee Regan Receives Bipartisan Support.)

EPA on Thursday also announced the appointments of Earthea Nance and Meg McCollister as administrators of its regions 6 and 7, respectively. Nance is an environmental engineer and an associate professor of urban planning and environmental policy at Texas Southern University; Region 6 covers Arkansas, Louisiana, New Mexico, Oklahoma and Texas. McCollister is an independent consultant based in Kansas City, Mo., where she serves “as an adviser and strategic thinker in areas including environmental, health and social improvement initiatives, as well as communication strategies,” according to EPA. Region 7 covers Iowa, Kansas, Missouri and Nebraska.

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FERC Rejects SEEM Opponents’ Rehearing Requests

Another door has been closed to opponents of the Southeast Energy Exchange Market (SEEM), after FERC on Friday ruled that their request for a rehearing on the market was submitted too late to be heard (ER21-1111, et al.).

The opponents — an ad hoc alliance of environmental and clean energy organizations calling themselves the Public Interest Organizations (PIOs), and a separate group referred to as the Clean Energy Coalition (CEC) — filed their rehearing requests Nov. 12. (See SEEM Opponents File Rehearing Requests.) In its Friday order, FERC declined to engage with these criticisms on the grounds that the opponents should have submitted their requests by Nov. 10.

Both groups also submitted alternative requests in the event FERC denied rehearing. The PIOs asked for their objections to SEEM to be the subject of a “paper hearing with a technical conference before briefing,” while the CEC asked the commission to provide “clarification and confirmation on the role and function of the SEEM proposal and the platform that will enable transactions.”

However, FERC rejected these requests as well. Because the PIOs’ rehearing request was untimely, the commission said the issues raised therein could not be set for a paper hearing. Regarding the CEC’s request, FERC said that “in the absence of an order” relating to SEEM, “there is nothing to be clarified.”

Because the commission was split 2-2, SEEM was automatically approved “by operation of law” Oct. 12. Hence, there was no actual order from the commission. (See SEEM to Move Ahead, Minus FERC Approval.)

According to the Federal Power Act, any parties “aggrieved” by a FERC order may apply for rehearing within 30 days of its issuance. But because FERC did not issue a formal order in the proceeding, the PIOs and CEC recognized Oct. 13 — when FERC announced that the agreement had taken effect — as the date of FERC’s “order.” Under this logic, the deadline for submitting the rehearing request was Nov. 12, making their filings timely.

By contrast, SEEM’s supporters, in a Nov. 30 filing, argued that the “date of issuance” is not when the commission announces a decision, but when it issues an order — or, in this case, fails to do so. (See SEEM Members Seek to Quash Rehearing Requests.) Because Oct. 11 was the deadline for FERC to issue an order, members said that rehearing requests must be filed 30 days after this date, meaning that any requests filed after Nov. 10 were out of time.

FERC did not cite either filing in Friday’s order, but the commission acknowledged that it “has not previously explained … the proper calculation of the deadline for rehearing requests following the failure of the commission to act.” Its subsequent clarification echoes the opinion of SEEM members, with FERC stating that the date of its “order” in this case was Oct. 11 and that the 30-day clock for rehearing requests “starts running on the day after the last day that the commission could have taken action,” meaning the deadline was Nov. 10.

When FERC deadlocked on the original SEEM proposal, Chair Richard Glick and Commissioner Allison Clements — both Democrats — opposed the agreement, while Republican Commissioners James Danly and Mark Christie approved of it. The commission’s filing on Friday did not mention the views of specific commissioners, though it did say that Commissioner Willie Phillips, the newest member who was confirmed by the Senate on Nov. 16, did not participate. (See Senate Confirms FERC Nominee Willie Phillips.)

SEEM Moving Toward 2022 Launch

Because the SEEM agreement took effect in October, FERC has approved revisions to four of the participating utilities’ tariffs implementing the special transmission service used to deliver the market’s energy transactions. (See FERC Accepts Key Tariff Revisions to SEEM.) Members have also submitted further changes to the commission that would implement a series of “transparency enhancements” to the market. The changes were proposed in June in response to FERC’s first deficiency letter, but the commission was not able to mandate their inclusion in the SEEM agreement because it did not issue an order. (See SEEM Members Offer Rule Changes.)

SEEM members also announced on Friday that they had chosen technology solutions company Hartigen to build and deploy the market’s technology platform. The selection of Hartigen follows a request for proposals issued in March. In a press release, members said they plan to have the new market online by the third quarter of 2022.

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Implementation Underway for NWPP’s Western RA Market

The Northwest Power Pool (NWPP) last week took its first steps in implementing its Western Resource Adequacy Program (WRAP), opening the door for participants to submit resource data for a “nonbinding” phase of the capacity market, which the organization says will serve as a “beta test” for a final program design.

The data from the 26 “Stage 1” participants are needed to model “forward showings” of resource adequacy and availability for the WRAP’s winter 2022 season commencing next November. In the future, participants will be required to provide their forward showings seven months in advance of the summer (June-September) and winter (November-March) compliance periods.

NWPP developed the WRAP to help Western balancing authorities cope with potential generation shortages during critical hours as the region confronts the retirement of increasing numbers of thermal generators and its growing reliance on variable renewable resources such as wind and solar.

The WRAP is intended to increase visibility into existing RA conditions in the West, addressing concerns among industry stakeholders and state regulators that load-serving entities are unknowingly relying on the same capacity resources without realizing it, threatening system reliability during periods of scarcity. The program is designed to provide participants a framework in which to access capacity resources when a participant is experiencing an extreme event.

“An extreme event could be when a participant’s load is in excess of their [forward showing] forecast or resources (generation and transmission) are experiencing unexpected outages; this portion of the program unlocks the footprint’s load and resource diversity,” NWPP explained in a “detailed design” document released last July. “The program seeks to achieve a balance between planning in a reasonably conservative manner but also to provide flexibility in order to protect customers from unreasonable costs.” 

In developing the WRAP, NWPP distinguished among various forms of RA — such as flexibility, energy and capacity — and decided to initially focus on a capacity-based program “with a demonstration of [resource] deliverability.”

The WRAP will kick off next winter with a nonbinding, no-penalty phase, denoted as Stage 1 in the NWPP timeline. The absence of enforcement and penalties shields the program from FERC oversight, giving members additional time to iron out wrinkles and finalize its design.

The binding Stage 2 program will introduce a requirement that participants demonstrate to the RA program administrator that they have sufficient resources to meet required metrics for a compliance season seven months ahead of the operational timeline or face a penalty based on the cost of new gas peaking plant.

The 26 Stage 1 participants represent more than 65,000 MW of winter peak load and nearly 67,000 MW of summer peak load within the Western Interconnection.

“This group is diving into the remaining program design questions, including a task force dedicated to a second transmission hub that would allow participants in the southwest region to more readily access program diversity; one considering specific contract terms that would be necessary to ensure an enhanced WSPP Schedule C agreement would count as qualified capacity; and others considering other outstanding issues,” NWPP said in a statement last week.

“We are very excited about the interest and commitment to the WRAP we’ve seen from former NWPP members and new participants alike. The level of excitement for the program’s forward program speaks to the determination and dedication of the participants,” NWPP CEO Frank Afranji said.

NWPP also noted last week that the move to implement the WRAP officially kicks off its working relationship with SPP, which has been retained to administer the program. (See SPP to Operation NWPP’s Resource Adequacy Program.)

“SPP has begun providing program operation services, including facilitating the collection of participants’ data to perform modeling for the upcoming seasons,” NWPP said.

“As we reach this significant milestone in the WRAP’s implementation, SPP is grateful for the relationships we’ve built and the opportunity to work with such a collaborative and diverse group of entities,” SPP CEO Barbara Sugg said. “This resource adequacy program will play an important part in the reliability of the Western grid, and it’s exciting to see new participants joining the effort.”

WRAP Stage 1 participants include Arizona Public Service, Avangrid, Avista, Black Hills Energy, Basin Electric Power Cooperative, Bonneville Power Administration, Calpine, Chelan PUD, Clatskanie PUD, Douglas PUD, Eugene Water and Electric Board, Grant PUD, Idaho Power, NorthWestern Energy, NV Energy, PacifiCorp, Portland General Electric, Powerex, Puget Sound Energy, Seattle City Light, Snohomish PUD, Shell Energy, Salt River Project, Tacoma Power, Turlock Irrigation District and The Energy Authority, which is representing seven Washington and Oregon publicly owned utilities.

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Texas RE Briefs: Dec. 8, 2021

The Texas Reliability Entity highlighted its involvement in a joint NERC–FERC inquiry into the February winter storm that nearly collapsed the ERCOT grid but warned its Board of Directors that next year could be more challenging.

“Still, there’s so much to do to ensure such an event never happens again,” Board Chair Milton Lee said. “We must hold ourselves accountable to develop future strategies, implement them, and ensure we monitor and update them for future improvements.”

NERC and FERC released their joint report in November, highlighting the failure of electric and gas utilities to adequately prepare for Winter Storm Uri’s frigid temperatures. The event caused more than 23 GW of manual firm load shed as generators and their supply lines froze. (See FERC, NERC Release Final Texas Storm Report.)

Texas RE staff were among the nearly 50 subject matter experts who helped prepare the report. Their final report included 28 recommendations that covered both industries and went beyond NERC reliability standards revisions to address cold weather, which were approved in August 2021.

“This report recognizes that folks at the RTO and ISO level coordinated very well and made the best of the situation by bringing in [power] supplies from their neighbors,” said Mark Henry, Texas RE’s director of reliability services and registration.

Henry said the RE staff’s next task is a deeper dive into the unavailability of ERCOT’s black start units during Winter Storm Uri.

The board approved the Nominating Committee’s recommendation that Lee again serve as its chair in 2022 and that Crystal Ashby serve as vice-chair.

The directors also approved Joseph Younger’s selection as Texas RE’s COO.

The Member Representatives Committee met before the board meeting and approved a work plan for NERC Project SAR-012: Revisions to the Standards Development Process. The work plan lays out the steps for revising a Regional Standard in accordance with Texas RE’s standards development process document.

Annual Membership Meeting

Texas RE CEO Jim Albright said staff is “leaning in” to a NERC audit next year, the result of a FERC order that applies to all six regional entities.

“We’re ready to show our work and be involved,” he said during the organization’s short annual membership meeting.

Albright said staff’s full return to the workplace is still “in flux,” given the coronavirus’ stubborn presence and the mutating variants. A target date has been set for Jan. 10, but staff will be limited to two days a week.

“We’ll be very cautious about bringing employees back to the office,” he said.

Resuming onsite stakeholder engagement will be a “challenge,” Albright said. He said the organization will focus on “comprehensively engaging” with stakeholders on all extreme events, not just those related to the winter.

Staff said Texas RE’s membership re-elected Lee to serve another three-year term as independent director. Lee’s term will expire Dec. 31, 2024.

The membership also elected three new MRC members: Acciona Energy USA Global’s George Brown and Vistra’s Kristopher Butler as the generation sector’s representatives, and Denton Municipal Electric’s Cameron Molsbee as the municipal alternate.

Lee honored Oncor Electric’s Liz Jones for her service as the MRC’s vice chair. Jones remains on the committee, which will elect its 2022 chair and vice-chair in January.

Texas RE added six new members in 2021, pushing its membership roll to 116. Five of those new members were in the generation sector, thanks to the continued growth of the state’s renewable energy.

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MISO Board of Directors Briefs: Dec. 9, 2021

MISO Pulls off 1st Face-to-face Meetings Since Start of Pandemic

ORLANDO, Fla. — MISO Board Week meeting marked MISO’s first plunge into in-person gatherings in nearly two years.

“Isn’t it great to be back in person?” CEO John Bear said in opening the Board of Directors’ meeting Thursday, held at Loews’ Sapphire Falls Resort, near Universal Orlando. “I was excited to put my tie on this morning.”

Organization of MISO States President Julie Fedorchak thanked MISO for “forging ahead” with an in-person meeting. She said the RTO showed it can be done in a “safe and pragmatic way.”

“There’s nothing quite like face-to-face communication,” Fedorchak said.

Board Week drew about 90 stakeholder attendees. MISO also offered a virtual attendance option.

MISO Board Week 2021-12-08 (RTO Insider LLC) Alt FI.jpgSocially distanced attendees at MISO Board Week | © RTO Insider LLC

MISO is charting a return to in-person meetings at its offices in Carmel, Ind.; Eagan, Minn.; and Little Rock, Ark., in late January.

The grid operator plans to reduce meetings of its major stakeholder committees from monthly to eight times per year and rotate which meet in-person, to limit virus exposure. Some stakeholders have misgivings that MISO can accomplish all its market and reliability aims and related FERC filings with just eight meetings per year, four of them in a virtual format. (See MISO Modifies Stakeholder Meeting Schedule.)

Robert Kuzman, MISO’s head of stakeholder relations, called the plan “a good start to get back in person as safely as we can.”

“This is a partnership. We intend to be as efficient as we can while still working through out goals,” Kuzman told the Advisory Committee on Wednesday.

Members asked if MISO would enact vaccination requirements for stakeholders wanting to enter a conference room.

Chief Customer Officer Todd Hillman said MISO is still navigating which requirements in-person meeting attendees must follow.

“Given the 15-state footprint, we’re trying to do right by all,” Hillman said.

Hillman said this week’s event will serve as the “litmus test” for MISO’s on-site meetings. So far, he said, MISO envisions socially distanced attendees, with tables spread apart.

MISO: New Market Platform Running by 2025

MISO said it remains on track for a late 2024 completion for its market platform replacement.

The RTO this year launched its new, one-stop system modeling tool and new market user interface, the nonpublic site market participants use to submit energy bids and offers. It believes it can complete the conversion by late 2024.

MISO is using Siemens smart grid technology to support its new model manager. It plans to cut over to a new method of member data submittal by March and retire its old method of data collection thereafter.

Chief Digital Officer Todd Ramey said MISO will retire both its legacy modeling system and old market user interface in 2022.

Next year, the RTO will work to debut an energy storage participation model on its vintage market platform. It previously said it couldn’t both roll out energy storage offers and focus on the platform replacement. Now it must introduce the storage participation model on both its old and new market platforms. (See MISO: No Choice but to Double Up on 841 Compliance.)

Late next year, MISO anticipates that it will receive its new day-ahead market clearing engine from General Electric.

This year marked the fourth full year of the ongoing swap of the grid operator’s old and rigid platform for a new modular one that can host more complex market offerings.

Board Approves Budget Shaped in part by COVID-19

MISO’s Board of Directors has greenlit a $376.1 million total budget for 2022.

The budget includes a $282.3 million base operating expenses, $37 million in project investments and $56.8 million in other operating expenses.

The 2022 budget is 1% lower than last year’s. MISO executives said pandemic impacts continue to influence budgeting. The RTO originally estimated that it would be largely free of pandemic irregularities in summer 2021.

Like other companies, MISO is contending with cybersecurity issues, supply chain issues, inflation and a tight labor market. CFO Melissa Brown said in fall that MISO was waiting on about $4 million in physical goods, including laptops, tables and new wallboards for the control room, that had yet to be delivered.

Brown also expects that MISO’s higher-than-expected employee vacancy rate will persist into 2022.

She said compared to pre-pandemic levels, MISO is earning a much lower interest rate on its cash, money it usually uses to offset some expenses.

Increasingly severe weather events are also upping spending. Executives said they spent about $2 million over 2021 to answer state- and federal-level questions about MISO’s decision-making and operations during extreme weather events.

Year to date, MISO is $5 million underbudget from its $226 million base operating allotment.

MISO Director Barbara Krumsiek thanked the RTO’s financial team for balancing a budget despite an “extraordinary number of variables.”

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MISO Members Weigh Potentially Rough Winter

ORLANDO, Fla. — MISO members this week offered a few tips on how the footprint can weather a tough winter, a day after the RTO elevated the risk level.

The grid operator warned that it’s in for a bumpier season, considering fresh concerns around coal and natural gas fuel assurance and security. (See related story, MISO Sounds Alarm on Potential Winter Fuel Scarcity.)

Todd Hillman 2021-12-07 (RTO Insider LLC) FI.jpgTodd Hillman, MISO | © RTO Insider LLC

“For this winter in particular, we know [awareness around] fuel assurance has been heightened,” MISO Chief Customer Officer Todd Hillman said, noting a doubling of natural gas prices since last year and concerns around coal stockpiles and deliveries.

The U.S. Energy Information Administration recently reported that coal production has sunk to a level not seen since 1978.

Speaking at an Advisory Committee meeting Wednesday as part of MISO Board Week, Hillman said the RTO’s planning futures point to an increased reliance on natural gas going forward.

“In MISO’s view, the number of recent outages is unacceptable,” Hillman said, calling up gas generation performance during mid-February’s arctic blast. (See MISO Underscores Need for RA Action in Winter Storm Review.) “This winter, are we better prepared, or more just bracing for impact?”

MISO’s current generation fleet contains about 80 GW worth of natural gas capacity, 80% of that without firm fuel service. During the February winter storm, the gas fleet experienced a more than 30% forced outage rate.

“Every time we see a weather event that we think is unsurpassed, Mother Nature says, ‘Here, hold my beer,’” MISO President Clair Moeller quipped.

Madison Gas and Electric’s Megan Wisersky said it’s not cost effective for most gas generation operators to secure firm transport.

Stakeholders pointed out that NERC’s new cold weather standards aren’t set to come into effect until April 2023.

“We have a potential reliability situation in front of us that can’t wait,” Cleco Cajun’s Tia Elliott said.

MISO Director Todd Raba asked what the RTO could immediately do to assuage conditions this winter. “There might not be an answer; that’s OK,” he said after a beat of silence.

Travis Stewart 2021-12-07 (RTO Insider LLC) FI.jpgTravis Stewart, COMPP | © RTO Insider LLC

“Other than meditation and prayer,” Hillman jokingly added, prompting stakeholders for suggestions.

Coalition of Midwest Power Producers representative Travis Stewart said MISO could reach out to generators with long lead times to make commitments days in advance.

“We might end up with some uplift, but that’s the cost of reliability. It’s a tough situation, and I think MISO’s markets do an excellent job,” Stewart said.

Clean Grid Alliance’s Beth Soholt said regulators should issue more conservation pleas through television and radio. “It may help us through a shortage or critical time. … I think it just heightens that we’re both going to need the demand side and the supply side,” she said.

“I think we spend so much time taking care of customers that we don’t realize that they have a responsibility to the system. And I think that’s a positive,” Indiana Utility Regulatory Commissioner Sarah Freeman agreed.

But Wisersky said “constant public appeals” might diminish MISO members’ credibility. She also said critical loads like hospitals should obtain on-site backup generation, given the new reality of intermittent generation coupled with knockout weather events.

Beth Soholt John Orr 2021-12-07 (RTO Insider LLC) FI.jpgCGA’s Beth Soholt and Exelon’s John Orr | © RTO Insider LLC

“If we’re honest with our customers, we can’t 100% guarantee that we’re going to be there all the time,” Wisersky said.

Exelon’s John Orr said MISO could address the public about its largely behind-the-scenes work.

“The public gets very little information. … MISO can provide some of this understanding,” he said, noting that the RTO can explain its role and decision-making process and actions taken like rolling blackouts.

Freeman also said the impending introduction of MISO’s seasonal capacity auction and availability-based capacity accreditation will deliver some hard truths on the readiness of MISO’s fleet.

“Like it or not, it will send a signal to generators on how they’re going to be compensated,” she said.

Stakeholders also said MISO should look to generation other than natural gas.

Soholt said that though gas plants are necessary to reliability, she questioned how much natural gas generation the U.S. should build on its way to decarbonization. She said the MISO footprint could use electric storage and more transmission projects to move power around during winter storms.

“How much is in our carbon checkbook to keep building natural gas?” Soholt said. “Natural gas is part of the puzzle, but it’s not the whole answer.”

Consumers Energy’s Kevin Van Oirschot pointed out that several of MISO’s market-based solutions meant to aid reliability are waiting on the new market platform, which will be better able to handle energy storage, distributed energy participation and more demand-side management.

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MISO Wraps Annual Transmission Package

ORLANDO, Fla. — MISO said it’s making headway on three transmission planning initiatives, including its 2021 Transmission Expansion Plan (MTEP), long-range transmission portfolio and a joint study with SPP intended to build transmission that can bring more generation online.

On Thursday, the Board of Directors greenlighted 335 new projects worth $3 billion, about a 20% reduction from 2020’s transmission package. (See MISO Tx Expansion Plans Proceeds to Board Vote.)

Aubrey Johnson, MISO’s executive director of system planning, has said the decrease is largely driven by Central planning region transmission owners submitting fewer projects this year. He said projects are scattered evenly across the footprint except for the West region, which continues to experience fewer projects.

“There’s not really any sexy in this [MTEP] … but this is foundational work that needs to be done,” director Mark Johnson said during the board’s meeting.

MISO says that $28.2 billion worth of transmission facilities have gone into service since the first MTEP cycle in 2003. Another $12 billion in projects will be in service by 2024.

Johnson said the billions in upcoming projects illustrate how long it takes to get transmission built. He also said projects from as far back as the 2008 and 2010 MTEPs have yet to be energized.

“Our team is going back to understand better what is going on with these projects,” Johnson said during a Tuesday System Planning Committee (SPC) of the board. He said most projects have been delayed because of budget or design changes.

This year, some members asked that MISO include transmission’s ability to withstand climate change or support clean energy goals in future MTEP planning.

The Environmental Sector asked staff to create “a more inclusive and holistic” transmission planning process that will support the fuel mix transition from fossil plants to renewable resources.

WPPI Energy asked for transfer analyses to SPP and the Tennessee Valley Authority and requested the RTO consider better connections between southern Illinois and southern Indiana.

Johnson has said MISO already considers extreme weather events in planning and it will dial up those efforts.

“We’re trying to expand that further to drive operational insights,” he told the board’s SPC in September.

WPPI Energy’s Steve Leovy said then that MISO can “reasonably expect” repeats of polar vortices that carry load-shed risk. He said he was worried the grid operator’s planning wasn’t doing enough to prevent a repeat of reliability breakdowns during cold snaps.

Midwest Bent for Long-range Projects

MISO Vice President of System Planning Jennifer Curran said staff is still putting together business cases and reliability and engineering analyses for the dozen or so Midwestern projects that could be recommended in the first cycle of long-range transmission projects.

Curran said the RTO is focused on the footprint’s Midwestern portion first because that region is undergoing a much more aggressive clean energy transition than MISO South.

“The needs are much more imminent. In some cases, they are here today,” Curran told the SPC Tuesday. “We operate and plan as one RTO while addressing the need for speed in the North and Central regions.”

She said the regions remain fairly independent of one another partially because of the transmission constraint between the two. Curran acknowledged that MISO could recommend a long-range project to expand its North-South transmission interface, unifying the RTO and widening its benefits spread.

“It’s a little bit chicken and egg,” she said.

Nancy Lange 2021-12-06 (RTO Insider LLC) FI.jpgNancy Lange, MISO director | © RTO Insider LLC

Director Nancy Lange asked how MISO can be sure that project benefits will be contained to the subregion bearing its costs.

“It’s taken me a while to wrap my head around that,” Lange said.

Curran said while there may be some transmission benefits enjoyed by MISO South from the Midwest, they’re inconsequential.

MISO President Clair Moeller said the North-South subregional limit’s energy flow has less transfer capability than the connection between Minnesota and Wisconsin.

“It’s a severe constraint,” he said.

Clean Grid Alliance’s Beth Soholt urged the grid operator to propose projects in a timely manner, noting that utilities and state commissioners are relying on new transmission to make new resource decisions and meet decarbonization goals.

“We were looking forward to seeing [the first] tranche in December,” she said.

MISO originally planned to recommend long-range projects this month as part of MTEP 21. Now, it says it will present a list of projects for approval to the board in June. Though six months tardy, those projects will still be considered under MTEP 21’s banner.

Joint Interconnection Solutions at $2B

SPP and MISO are finalizing a nearly $2 billion portfolio of 345-kV interregional projects that could resolve most constraints along their seam.

The proposals are the result of the grid operators’ joint targeted interconnection queue study, designed to ease their crowded interconnection queues.

MISO still must discern how the projects would interact with any proposed projects under its long-range transmission plan.

MISO executives predicted disagreements over a cost allocation that could assign bills for both generation and load. SPP’s Antoine Lucas said costs could be recovered from new generators as they exit either of the RTOs’ interconnection queues. (See MISO, SPP: Economics Secondary in Joint IC Planning.)

The seams neighbors plan to hold cost-allocation talks on the projects next year. The RTOs have said they would bring projects to their respective boards for approval once they decide on cost allocation.

“I recognize we still have a lot of work to do … but this will hopefully benefit those along the MISO-SPP seam,” Johnson said.

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PJM MRC/MC Preview: Dec. 15, 2021

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings on Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Stakeholders will be asked to endorse proposed revisions to Manual 6: Financial Transmission Rights, conforming to the joint PJM-stakeholder proposal addressing auction revenue rights (ARRs) and financial transmission rights endorsed at the October MRC. The changes were initiated after the GreenHat Energy default in 2018, including a six-month review by an independent consultant and work done at the ARR/FTR Market Task Force. (See Stakeholders Endorse PJM ARR/FTR Market Changes.)

C. Members will be asked to endorse proposed revisions to Manual 10: Pre-Scheduling Operations resulting from a periodic review. The revisions were endorsed at the November Operating Committee meeting. (See “Manual Changes Endorsed,” PJM Operating Committee Briefs: Nov. 4, 2021.)

D. The committee will be asked to endorse proposed Manual 14B revisions resulting from a biennial review. The revisions include the addition of a new section that features details around the incorporation of end-of-life (EOL) needs in the Regional Transmission Expansion Plan, which were part of the tariff attachment M-3 discussions. (See “Manual Endorsements,” PJM PC/TEAC Briefs: Nov. 2, 2021.)

E. Stakeholders will be asked to endorse proposed revisions to Manual 14D: Generator Operational Requirements resulting from a periodic review. The updates featured the addition of several new sections, including one describing eDART modeling requirements. (See “Manual Changes Endorsed,” PJM Operating Committee Briefs: Nov. 4, 2021.)

F. Members will be asked to endorse proposed revisions to attachment DD of the tariff endorsed by the Governing Document Enhancement and Clarification Subcommittee. The revision includes removing section 6.2(c) of the attachment because FERC affirmed PJM’s position that this section of the tariff is no longer applicable and encouraged the RTO to remove this provision as part of its next tariff clean-up filing.

Endorsements (9:10-10:10)

1. Undefined Regulation Mileage Ratio Calculation (9:10-9:30)

The committee will be asked to approve the proposed issue charge to create a new senior task force to re-evaluate the current regulation market design. The issue charge was first presented at the November MRC meeting. (See “Undefined Regulation Mileage Ratio Calculation,” PJM MRC/MC Briefs: Nov. 17, 2021.)

If the MRC approves the issue charge creating the task force, another vote will be taken on the short-term proposals from PJM and the Independent Market Monitor addressing the undefined regulation mileage ratio calculation. Both proposals failed a vote at the October MRC. (See “Regulation Mileage Ratio Fails,” PJM MRC/MC Briefs: Oct. 20, 2021.)

2. Solar-Battery Hybrid Resources (9:30-9:50)

Stakeholders will be asked to endorse the proposed solution and corresponding tariff and Operating Agreement revisions to address market participation by solar-battery hybrid resources. PJM conducted a prefiling meeting with FERC staff in September, and the commission made suggestions to reconfigure the language to increase its chances for approval. (See “Solar-battery Hybrid Resources,” PJM MRC/MC Briefs: Nov. 17, 2021.)

3. Synchronous Reserve Deployment Stakeholder Initiative (9:50-10:10)

The committee will be asked to endorse the proposed solution and corresponding tariff and OA revisions addressing synchronous reserve deployment during a spin event. The proposal was developed from discussions in the Synchronized Reserve Deployment Task Force (SRDTF). (See “Synchronous Reserve Deployment Stakeholder Initiative,” PJM MRC/MC Briefs: Nov. 17, 2021.)

Members Committee

Endorsements (1:30-1:45)

1. Elections (1:30-1:45)

Stakeholders will vote on the proposed sector representatives for the 2021/22 Finance Committee and the 2022 sector whips. The new Finance Committee members include: Susan Bruce, PJM Industrial Customer Coalition (End-use Customer); Jeff Whitehead, Eastern Generation (Generation Owner); Bruce Bleiweis, DC Energy (Other Supplier) and; Alex Stern, PSEG Services (Transmission Owner).

The 2022 sector whips include: Adrien Ford, Old Dominion Electric Cooperative (Electric Distributor); Greg Poulos, Consumer Advocates of the PJM States (End-use Customer); Michael Borgatti, Gabel Associates (Generation Owner); Brian Kauffman, Enel N.A. (Other Supplier); and Sharon Midgley, Exelon (Transmission Owner).

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Biden Calls for Federal Procurement of 100% Clean Energy by 2030

President Joe Biden signed a sweeping executive order Wednesday directing the federal government to use carbon-free electricity for its 300,000 buildings and to decarbonize its 600,000 vehicle fleet.

The order requires 100% carbon-free power on a net annual basis by 2030, including 50% 24/7 carbon-free electricity. What that means, a White House fact sheet says, is that “the federal government’s real-time demand for electricity will be met with clean energy every hour, every day, and produced within the same regional grid where the electricity is consumed.”

The policy will “catalyze the development of at least 10 GW of new American clean electricity production by 2030,” according to the fact sheet.

The order seeks to lead by example and leverage the government’s massive purchasing power of $650 billion per year to “protect the environment, drive innovation, spur private sector investment, improve public infrastructure and create new economic opportunity,” it said.

The order sets out a list of emission reduction goals, including:

    • For all federal government buildings: net-zero emissions by 2045, with an interim goal of a 50% reduction by 2032;
    • For all federal government operations: net-zero by 2050, with an interim target of a 65% reduction by 2030; and
    • For federal procurement: net-zero by 2050, via a “Buy Clean” policy that will promote the use of low-carbon construction materials and other low-carbon materials across the supply chain.

The order also calls for electrification of the government’s fleet of 600,000 cars and trucks, requiring that 100% of new acquisitions be zero-emission vehicles (ZEVs) by 2035, with 100% ZEV acquisition for light-duty vehicles by 2027.

It allows exemptions for “any vehicle, vessel, aircraft or non-road equipment that is used in combat support” or for other military purposes. Exemptions are also allowed for government activities and facilities for reasons of national security or to protect intelligence sources or undercover law enforcement operations.

Implementation of the order will be overseen by a new federal chief sustainability officer, appointed by the president, and Biden also hopes to draw in executives from the private and nonprofit sectors for “term-limited appointments to bring innovative perspectives and expertise to federal government.” Key federal agencies will also be required to appoint chief sustainability officers and establish sustainability training for employees.

Funding for implementation, the fact sheet says, will come from the bipartisan infrastructure act, signed into law last month, and the Democrats’ Build Back Better budget reconciliation package passed by the House and now being negotiated in the Senate. Build Back Better includes $20 billion for federal clean energy procurement, according to the White House.

Demand-side Incentives

The order was immediately slammed by Sen. John Barrasso (R-Wyo.), ranking member of the Senate Committee on Energy and Natural Resources, who characterized it as an “outrageous and disgraceful” attack on the jobs of U.S. fossil fuel energy workers.

“President Biden’s plan is all about expanding government,” Barrasso said in an email statement. “He is adding a sustainability czar to the White House and every agency. … This is not build back better; it’s another backbreaking move to build bigger bureaucracy.”

Clean energy advocates praised the order, saying it will result in economic growth and job creation while also calling on Congress to finalize passage of the Build Back Better Act.

“This executive order is a critical step to getting the on-the-ground momentum for a complete transition to a decarbonized energy economy,” said Paula Glover, president of the Alliance to Save Energy. She noted that the order references the federal building performance standard now being developed by the White House Council on Environmental Quality for reducing building emissions.

Such standards will “accelerate clean energy research and manufacturing,” she said.

Assuming that building retrofits and vehicle fleet transitions will roll out gradually over a number of years, Harry Godfrey, manufacturing policy lead at Advanced Energy Economy, estimated the order could stimulate business sales of $35 billion to $70 billion by mid-decade, while adding 90,000 to 180,000 jobs in advanced energy manufacturing. The near-term impact on U.S. gross domestic product could be an additional $13 billion to $26 billion, he said.

“As we await the essential clean energy investments contained in Build Back Better to pass Congress, this executive order utilizes the vast purchasing power of the federal government to begin to scale up a large variety of advanced energy technologies and create good jobs in America,” Godfrey said in an email to RTO Insider.

Nancy Ryan, a partner at consulting firm eMobility Advisors, says the commitment to 100% EV acquisition will result in sales of thousands of vehicles per year.

“It’s a commitment going forward that auto manufacturers can take to the bank because they have this commitment to sales,” she said. A more indirect effect is “that it’s a vote of confidence from the federal government because these are working fleets. … It sends a really strong signal that working fleets can be electrified.”

It will also help build out the U.S. supply chain for the thousands of parts that go into electric vehicles, “boosting domestic manufacturing capacity [and] providing another nudge to put the capacity in the U.S. and the jobs that go with it,” she said.

Jason Walsh, executive director of the BlueGreen Alliance, also called out the order’s Buy Clean provisions as a way to “reshore” manufacturing work back to the U.S. “We make steel and cement and other materials in this country in much cleaner ways than some of our biggest competitors, notably China,” he said. “This creates really important demand pull for cleaner building products. We need to create those markets in order to incentivize changes in industry.”

Still another benefit of the order “is the fact that it’s long range, that it is not going to happen overnight,” said Costa Nicolaou, CEO of solar racking manufacturer PanelClaw Inc., an Esdec Solar Group company. “It creates yet another demand-side incentive for manufacturers to set up shop in the U.S., with that demand being in place. And for manufacturers that are already here, it can create a demand-side incentive to increase manufacturing in the U.S. … to scale up our manufacturing even further.”

Filling Skill Gaps

But Ryan said the executive order also creates challenges. For example, electrifying the federal fleet also means building out charging infrastructure, which in turn could put pressure on utility distribution systems, as charging up large fleets creates heavy demand on the grid. Utilities across the country are now looking at different options, such as managed charging programs, to handle that new demand, she said.

The U.S. also may not have the trained workers needed to meet Biden’s ambitious goals, and the executive order in and of itself will not be enough to spur workforce expansion, Walsh said.

“We have skill gaps in certain sectors,” he said. Funds in the Build Back Better Act would allow unions to dramatically increase training and apprenticeship programs to expand the clean energy workforce.

“We need to make clear to a whole new generation of workers that we’ve got to rebuild and repower and retrofit this country,” Walsh said. “And that is a project that is not only enormously important from a climate standpoint, but it also has the potential to be a pathway to career jobs that, if they’re union, can be high quality and family-supporting.”

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Youngkin Vows to Pull Va. from RGGI

Governor-elect Glenn Youngkin (R) said Wednesday he will pull Virginia from the Regional Greenhouse Gas Initiative by executive order once he takes office, but RGGI supporters said he doesn’t have the power to do so.

“RGGI will cost ratepayers over the next four years an estimated $1 billion to $1.2 billion,” Youngkin said in a speech at the annual meeting of the Hampton Roads Chamber of Commerce in Virginia Beach, according to the Richmond Times-Dispatch. “RGGI describes itself as a regional market for carbon, but it is really a carbon tax that is fully passed on to ratepayers. It’s a bad deal for Virginians. It’s a bad deal for Virginia businesses.”

In August, the Virginia State Corporation Commission approved Dominion Energy’s request to recover RGGI costs from ratepayers, which the utility estimated would cost the typical residential customer $2.39/month. Youngkin cited a Dominion filing Monday asking the SCC for permission to increase the surcharge to $4.37/month beginning Sept. 1, 2022.

Authority Questioned

The Democratic-controlled legislature approved a bill to join RGGI in 2020. Youngkin will take office Jan. 15 with a Republican-controlled House of Delegates but with Democrats still in control of the Senate.

As part of the compact, RGGI’s members — including Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island and Vermont — agree to a declining cap on CO2 emissions from the power sector.

The Department of Environmental Quality’s (DEQ) regulation implementing the law capped CO2 emissions for Virginia at 27.1 million short tons for calendar year 2021 and decreases the emissions cap annually by about 3% to reach a 30% reduction from 2020 levels by 2030. Emission sources subject to the rule must obtain and surrender a CO2 emission allowance for every short ton emitted.

“I can assure you there’s a lot of lawyers … that are busy going to the [law] books right now,” Sen. Lynwood Lewis (D), who sponsored the RGGI authorization in the Senate, told The Washington Post.

“I thought Virginia freed itself from an all-powerful monarch in 1776? Perhaps Glenn Youngkin still thinks he’s a CEO and can’t recall his fourth grade separation-of-powers lesson?” tweeted Sen. Scott Surovell (D).

Youngkin’s transition office issued a statement saying the governor has authority to leave RGGI because “Virginia’s participation is governed by a contract agreement, signed by the Department of Environmental Quality and other regulations.”

Cale Jaffe-(UVA Law School) Content.jpgUniversity of Virginia Law School Associate Professor Cale Jaffe | UVA School of Law

University of Virginia Law School Associate Professor Cale Jaffe, director of the Environmental Law & Community Engagement Clinic, told the Virginia Mercury that although the governor will have authority over DEQ — which the legislation directed to manage the program — it would require action by the seven-member Air Pollution Control Board to quit RGGI. “The governor cannot just undo regulations that he might not like via executive order,” Jaffe said.

Democrats currently have a 7-0 majority on the board, and it could take Youngkin three years to win control of it. Two members’ terms expire next June; one expires in 2023; and two more expire in 2024.

Lee Francis, a spokesman for the Virginia League of Conservation Voters, which supports RGGI, agreed with Jaffe’s analysis. “Youngkin’s proposal is grounded in neither fact or law,” Francis told the Times-Dispatch.

Impact Challenged

In addition to legal questions over Youngkin’s authority, the governor-elect’s statement sparked a debate over RGGI’s impact.

Del. Todd Gilbert (R), who will become House speaker, said RGGI’s impact on climate change has been “negligible at best.”

“Virginia was reducing carbon emissions from power plants at a rate comparable to RGGI states before joining the cap-and-trade group,” Gilbert said in a statement. “When a policy costs the public a significant amount of money for no tangible benefit, that policy should be examined carefully and, if practical, rolled back.”

Dominion, which opposed joining RGGI, agreed, saying it continues to believe it “would result in a financial burden on its customers with no real mitigation of GHG emissions regionally.”

“Here in Virginia, we are focused on an all-of-the-above approach to sustainability while keeping our rates below the national average and our service reliability strong,” spokesperson Rayhan Daudani said. “This includes the largest offshore wind project in the nation, transformation of the grid, re-licensure of our nuclear units, energy storage and solar energy, all of which creates jobs and economic opportunity.”

But others said Youngkin’s action would eliminate the source of hundreds of millions in funding for flood preparedness and energy efficiency. Youngkin also told the chamber of commerce Wednesday he would develop a plan to “combat sea-level rise.”

The state is directing 50% of its RGGI auction proceeds to low-income energy-efficiency programs and 45% to a new Community Flood Preparedness Fund. The remainder offsets administrative expenses.

“Regardless of your political party, if you’re a legislator in an area that’s impacted by sea-level rise of just recurrent flooding … you should be very reluctant and cautious in completely devastating that fund,” Sen. Lewis said. “This was going to provide a significant source of revenue.”

Rising Prices

Virginia raised $227.6 million this year in carbon credit auctions this year, including $85.6 million in the quarterly results announced last week. The DEQ had previously predicted the state’s annual proceeds would be between $104 million and $109 million.

Last week’s quarterly auction cleared at $13/ton — the highest price and single largest price jump in the program’s history. (See RGGI Price Hits Record High, Jumps 40% over Last Auction.)

Dominion’s Dec. 6 filing with the SCC estimated the company will need 19 million allowances to cover the emissions from its Virginia-based generation fleet for the year beginning in September. The company said it assumed a weighted average price of $10.53/allowance based on December ICE futures contracts for 2021 and 2022 and the ICF International forward price curve for 2023.

Reaction

Environmental groups and others reacted with alarm to leaving RGGI.

The Northern Virginia Affordable Housing Alliance tweeted, “Saving $54 annually per household is not worth the tradeoff” with the loss of the EE funding.

“This is the wrong decision,” said Virginia Advanced Energy Economy.

Lynnhaven River Now, an environmental group, tweeted that Youngkin’s move would “gut” the flood preparedness fund.

“Hell no! This is unacceptable,” tweeted the Chesapeake Climate Action Network.

U.S. Rep. Don Beyer (D-Va.) tweeted that withdrawing from RGGI “would mean Glenn Youngkin’s first steps as governor of Virginia are steps backwards. He has time to take a closer look at this and reconsider, and that is what he should do.”

Maryland Del. Marc Korman (D) noted that Republican Gov. Larry Hogan attempted to pull Maryland from RGGI and was blocked by the legislature. “We are still in the cap-and-trade program,” he tweeted.