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August 27, 2024

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Whitmer Backs Palisades Reopening Plan

LANSING, Mich. — Gov. Gretchen Whitmer on Friday fired a major shot boosting efforts to reopen the now-shuttered Palisades Nuclear Plant along Lake Michigan’s shores by telling the U.S. Department of Energy the state will take steps toward finding state funding and “facilitating” a power purchase agreement with the generating plant if it wins a federal grant.

In a letter to U.S. Energy Secretary Jennifer Granholm — herself a former Michigan governor — backing a proposal by Holtec International for a Civil Nuclear Credit Program grant, Whitmer said reopening the plant, closed last spring, “is a top priority” for the state as it provides hundreds of jobs, paying on average more than $117,000 a year and producing as much as 800 MW of “reliable, clean power.”

“I will do everything I can to keep this plant open, protect jobs, increase Michigan’s competitiveness, lower costs and expand clean energy production,” Whitmer said in the letter.

Less than two full months after the nearly five-decade-old Palisades closed, Holtec in July proposed a plan to remove radioactive materials. That proposal was controversial because it called for using Great Lakes barges.  

Whitmer had said little about nuclear energy in the state in the early days of her administration and as it worked on a net-zero-emissions plan. Shortly before the plant’s closing, Whitmer expressed support for seeking federal aid to keep it open.

While nuclear energy is a controversial topic among environmentalists, keeping the plant open was cited by many as critical to the state’s goal of reach net zero before 2050.

The plant was closed on May 20, 11 days before its May 31 decommissioning date, when its fuel supply ran out and a PPA the plant had with CMS Energy ended. Holtec took possession of Palisades from Entergy this past June.

With Palisades closed there are currently two nuclear plants operating in Michigan: the Cook plant, operated by American Electric Power subsidiary Indiana Michigan Power, and Fermi 2, operated by DTE Energy.

Holtec CEO Kris Singh said Whitmer’s support has been “instrumental” in the company’s efforts to win the federal grant to reopen Palisades.

Whitmer said that while the state and company wait for an answer from DOE, the state will “continue to efforts to diversify economic opportunities in Southwest Michigan through the Michigan Department of Treasury’s Energy Transition Impact Project,” as well as other economic development programs.

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MISO’s 2022 Tx Planning Cycle Exceeds $4B

MISO’s final 2022 Transmission Expansion Plan (MTEP 22) clocks in at 384 new projects and about $4.3 billion in construction costs.

MTEP 22’s $4 billion value is a marked increase over a 2021 plan that included 335 projects worth $3 billion, but more in line with the 2019 and 2020 cycles’ spending. The draft MTEP 22 called for $3.8 billion in spending over 364 new transmission projects. (See MISO Annual Transmission Package Nears $4B.)

The plan comprises 40 baseline reliability projects at $535 million; 67 projects to accommodate generator interconnections at $523 million; and $3.3 billion in 275 “other” projects for reliability, load growth and addressing aging facilities. MTEP 22 also includes two market participant-funded projects at $7.7 million.

MISO will recommend the MTEP 22 report for the Board of Directors’ approval in early December.

The plan’s costliest project is the $120 million for new static synchronous compensators necessary to reinforce the system in preparation for Ameren Missouri’s retirement of its 1.2-GW Rush Island coal power plant. The project’s expense is tied with Entergy Arkansas’ new $120 million Sandy Bayou 500/230-kV substation, which will tap into its existing Driver-Shelby 500-kV line to accommodate the state’s load growth.

Four of the other 10 most expensive projects are in East Texas to meet increasing load there.

Enviros: Plan for Growing Load, Aging Infrastructure

During a Thursday West Subregional Planning meeting, Clean Grid Alliance’s Natalie McIntire said MISO and stakeholders should have a better understanding of which aging infrastructure needs replacement sooner so the grid operator can pursue larger, more cost-effective projects that could supplant the need for future projects.

“It seems when you have an asset that has such a long life, you should have a better idea of when a replacement is necessary more than a year or two in advance,” she said.  

McIntire asked why stakeholders don’t get more notice of projects addressing age and condition before the release of MTEP reports. Staff responded that transmission owners likely inspect facilities on a rotating basis, making it difficult to get a sweeping picture of aging elements.

“We’ve been asking for this for years, and it doesn’t seem that we’re going to get a good answer. … You can’t inspect all of your facilities in a year, but you should have a clearer picture of … when assets are getting to the end of their life, maybe five to 10 years in advance,” McIntire said. She said it appears MISO is giving its transmission owners too much deference in assessing system needs.

Iowa Office of the Consumer Advocate’s Tim Tessier also called for more transparency from transmission owners on aging facilities so the RTO can plan more comprehensive upgrades.

MTEP 22’s inclusion of several late additions by Cleco and Entergy for substation work in MISO South raised some eyebrows among clean energy advocates, who have said the region needs more cohesive transmission planning.

Cleco applied for expedited treatment to include the $15 million, 230-kV Marthaville substation and the $15 million, 138-kV Vernon substation in western Louisiana. Entergy requested the go-ahead to install two additional 230-kV breakers into its existing Legend substation near the Louisiana-Texas border. It also asked to construct a new 230-kV substation for about $1 million in the same area and a $32.6 million, 115-kV substation in northern Mississippi.

Both transmission owners said the substation projects are necessary to accommodate industrial load growth and can’t wait for the MTEP 23 cycle.

Southern Renewable Energy Association (SREA) Executive Director Simon Mahan said that though MISO allows stakeholders to propose study alternatives for expedited projects, the stakeholder community generally lacks insight into the grid operator’s and TOs’ analyses to suggest substitutions. He said stakeholders are in the dark regarding the extent of study alternatives, and he said he’s unaware of the RTO ever opting for a stakeholder-proposed alternative to an expedited project request.

SREA’s Andy Kowalczyk asked whether all the late industrial load growth applications in one cycle should prompt MISO to embark on a planning study on MISO South’s projected load growth. He said he is concerned over the length of agreements with industrial customers and the possibility of stranded costs for transmission facilities.

“Is this the most economical way to be planning?” he asked during a Wednesday South Subregional Planning meeting.

Edin Habibovic, MISO’s senior manager of expansion planning, called Kowalczyk’s query “a good question,” saying market competition makes it difficult to get early data from industrial customers about their expansion plans and energy needs. He also said TOs are often bound by non-disclosure agreements about load-growth projects.

MISO will review the MISO South expedited requests with stakeholders again during October’s Planning Advisory Committee meeting.

Stakeholders Ask for Special MTEP 23 Studies

The RTO has also been gathering input from stakeholders on the special studies it should conduct under MTEP 23.

Last month, MISO project manager Sandy Boegeman warned that the grid-operator’s long-range transmission planning (LRTP) is currently drawing a lot of manpower and resources, possibly limiting the ad hoc planning studies for MTEP 23. MTEP 22 didn’t contain any supplementary studies for the same reason.

The Organization of MISO States has asked the RTO to continue concentrating on LRTP planning and pay special attention to finding projects that expand the Midwest-South transfer constraint.

Other stakeholders have asked MISO to study the historic levels of congestion in MISO Midwest, potential impacts from widespread adoption of energy storage, and future thermal generation retirements in Illinois under of the state’s Climate and Equitable Jobs Act.

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California Lays Groundwork for NEVI Solicitations

California agencies will start soliciting applications early next year from private entities seeking a share of National Electric Vehicle Infrastructure (NEVI) funds to build public EV charging stations throughout the state.

The agencies plan to issue 20 solicitations during 2023 and 2024, which will encompass at least 864 DC fast chargers at 143 sites. The proposals will be solicited in four rounds, starting in the first quarter of next year and then spaced six months apart.

The solicitations were the subject of a pair of workshops last week hosted by the California Energy Commission (CEC) and the state’s Department of Transportation (Caltrans). The agencies are seeking public feedback before finalizing details of the solicitations.

The goal of the NEVI program is to establish a nationwide network of public EV chargers along “alternative fuel corridors.” California is expecting to receive $384 million in NEVI funds over five years.

‘A Big State’

California has about 6,600 miles of alternative fuel corridors, including interstates, U.S. highways and state routes. Caltrans and CEC decided to first break the corridors into segments. Segments were then divided into 20 corridor groups, based on factors including location, gaps in the existing charging network and estimated future demand. Each NEVI solicitation will cover one corridor group.

“California’s a big state,” said Mark Wenzel, manager of the light-duty electric vehicle infrastructure and analysis office at the CEC. “To fully build out the network to NEVI standards will take hundreds of sites and thousands of chargers. It is not possible for us to design and competitively bid each site. We just don’t have the time and capacity for that.”

The NEVI program requires charging stations to be 50 miles apart or less and within one mile of a highway, although states can request exceptions.

Another NEVI program requirement is that each charging site must have at least four fast chargers and site power of at least 600 kW to support 150 kW per charging port.

California is planning to require more than four chargers at some sites, based on a demand forecast from the EVI-RoadTrip tool. The agencies’ goal is to build out the corridors to at least half of the charger demand expected in 2030.

California’s proposed corridor groups range in size from five to nine sites, with 20 to 166 chargers.

Caltrans and CEC also ranked the 20 corridor groups in order of priority. Priority was determined from a wide range of factors, including the percentage of the corridor that is in a disadvantaged community and the number of fast chargers needed to meet 2030 demand according to the RoadTrip tool.

The highest priority groups will go out to bid first.

The highest priority group is proposed corridor group No. 7, which includes eight new charging stations and 73 new chargers along State Route 58 and interstates 15 and 40 in Southern California.

Who Can Apply?

Applicants for California’s NEVI funds must be private entities that agree to build, operate and maintain the charging stations. But public entities, such as local governments, may still be part of a project team.

And the team must include an experienced charging network provider. The agencies will be looking for a company or organization with a proven track record of overseeing DC fast charger projects at three or more different locations and for three or more different customers in California since January 2018.

The NEVI program requires that applicants chosen to receive funding provide at least a 20% match. The California agencies have proposed increasing the required funding match to 50% for 13 of the 20 solicitations.

Caltrans and CEC are estimating total project cost based on $250,000 per charger. For example, a project with 24 chargers would have an estimated cost of $6 million, and a successful applicant would receive $3 million in cases where a 50% match is required.

Projects eligible for NEVI funding include new chargers at new stations, or additional chargers at existing stations. In addition to the costs of charging equipment, the funding may be used for solar panels or energy storage systems to power the EV chargers.

Extended warranties and maintenance agreements of up to five years are also eligible costs. Applicants for the NEVI funds must have a five-year operations and maintenance plan, and chargers will be required to be functional at least 97% of the time.

The agencies also plan to require restrooms at the NEVI-funded EV charging stations. The restrooms would need to be open at least during business hours, while the chargers must be available around the clock. No decisions have been made on restroom specifications, such as size and number.

Wenzel noted that proposed program requirements are still subject to change and feedback on the proposals is welcome. Changes are also still possible at the federal level, where NEVI regulations have been proposed but not finalized.

Buy America requirements that apply to federally funded projects are another variable for the NEVI program. The Federal Highway Administration (FHWA) has proposed phasing in the requirements for EV chargers in 2023. The agency is accepting public comment on the proposal through Sept. 30.

States File NEVI Plans

The NEVI program is part of the federal Infrastructure Investment and Jobs Act signed into law in November 2021.

All 50 states, Puerto Rico and the District of Columbia met the Aug. 1 deadline to file their NEVI plans with the FHWA. (See States File Plans on Deadline for Federal EV Charging Funds.) The FHWA now has until Sept. 30 to review and approve the plans.

More information on California’s NEVI plan is available here.

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CISA Seeks Comment on Cyber Reporting Rules

As it moves toward implementing the cybersecurity requirements added to its budget this year, the U.S. Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) said Friday that it will seek public comment on the best approach to their execution.

CISA’s draft request for information — set to be published in the Federal Register on Monday ­— stems from the Cyber Incident Reporting for Critical Infrastructure Act of 2022 (CIRCIA), part of the omnibus spending bill passed by Congress and signed by President Biden in March. The bill requires entities “in a critical infrastructure sector, as defined in Presidential Policy Directive 21” — which includes the energy sector — to report relevant cyber incidents to CISA within 72 hours after they occur, as well as when they make a ransom payment to the perpetrators of a ransomware attack. (See Budget Mandates Cyber Reporting for Critical Infrastructure.)

Authority for several key areas within the law is designated to CISA’s director, including defining which incidents are subject to reporting and which additional sectors, if any, are covered by the requirements. CISA must issue a Notice of Proposed Rulemaking within two years regarding the matters left to the director’s discretion, with a final rule to follow after another 18 months that will also specify what content entities must include in their cyber incident and ransom payment reports, as well as the data preservation requirements.

In a statement, CISA said comments received in response to the RFI “will inform the agency’s development of the proposed regulations.” Members of the critical infrastructure community, as well as the public, will have 60 days from the publication of the RFI to submit their feedback.

CISA’s suggested topics for respondents to address include:

  • definitions, criteria and scope of regulatory coverage, including the meaning of “covered entity”; the number of entities likely to be identified with that label; the meaning of “substantial cyber incident,” “ransom payment” and “ransomware attack”; and the number of ransom payments likely to be made every year;
  • report contents and submission procedures, such as what information should be required for inclusion in reports, the format of reports and when the deadline for reporting ransom payments begins;
  • other reporting requirements and vulnerability information sharing; and
  • additional policies, procedures and requirements.

In addition to written comments, stakeholders may participate in one of 11 public listening sessions, one in D.C. and in each of CISA’s 10 regions. The first listening session will take place Sept. 21 in Salt Lake City, and the last currently on the schedule is planned for Nov. 16 in Kansas City, Mo.; the date of the session in D.C. has not yet been determined.

In the agency’s statement, CISA Director Jen Easterly called the CIRCIA “a game changer for the whole cybersecurity community [that] will allow us to better understand the threats we are facing, to spot adversary campaigns earlier, and to take more coordinated action with our public and private sector partners in response.”

“We can’t defend what we don’t know about, and the information we receive will help us fill critical information gaps that will inform the guidance we share with the entire community, ultimately better defending the nation against cyber threats,” Easterly said. “We look forward to continuing to learn from the critical infrastructure community … to understand how we can implement the new cyber incident reporting legislation in the most effective way possible to protect the nation’s critical infrastructure.”

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FERC Comes to Vermont and Leaves with a New England-sized Headache

Nearly 10 years ago, FERC convened a gas-electric conference in Boston to talk about the issues facing New England’s electric grid in the winter.

Last week, the federal agency came to New England again. The room was bigger, and some of the terminology has changed. Energy technology has evolved and, in many cases, improved tremendously.

But the conversation was strikingly similar, according to New England Power Generators Association President Dan Dolan, who was in attendance for both.

“It’s shocking and terrifying how close the notes and talking points we had for that one could be reflected today,” Dolan told FERC commissioners on Thursday at a conference center in Burlington, Vt.

Even the more specific issues around LNG supply have been identified for years, Dolan said, with no tangible action to solve them in the long term.

Experts, analysts and lobbyists laid out the problem for FERC commissioners, who surely knew what it was before they walked into the room: a resource adequacy crisis fueled by New England’s unique geographic and political constraints, which ISO-NE fears will be exacerbated by the states’ push to replace fossil fuels with clean energy.

Largely acknowledged throughout the conversation was that it’s too late to do anything for this winter.

“‘Hope’ is not a strategy,” said Richard Paglia, vice president of U.S. marketing at Enbridge. Later, NERC CEO Jim Robb echoed him: “‘Luck’ is not a strategy.”

Gordon van Welie 2022-09-09 (RTO Insider LLC) FI.jpgISO-NE CEO Gordon van Welie speaks to FERC regulators. | © RTO Insider LLC

But that’s essentially what ISO-NE has accepted as its position for this year: hoping that, like last winter, the region is lucky enough to avoid the most extreme cold, which the grid operator says could lead to rolling blackouts.

An exchange between ISO-NE CEO Gordon van Welie and FERC Commissioner James Danly hinted at one possible move that the commission could make this year: initiating a Federal Power Act Section 206 proceeding to force some sort of action from the grid operator.

But van Welie urged the commissioners to be cautious about that option and only use it if it involves clear direction.

Tomorrow’s Problem

The long-term solution to the region’s challenges depends on who you ask.

The natural gas companies and their allies present at the meeting want to build more gas infrastructure — not necessarily new pipelines, but potential brownfield development, like changing out pipes for larger ones or adding compression, as Paglia suggested.

There was also substantial discussion about making sure that operation continues at the Everett LNG terminal, which ISO-NE highlighted in a recent problem statement, arguing that the facility is vital to the region’s energy security. (See ISO-NE: Reliability Still Depends on Mass. LNG Import Terminal.)

But others say the clean energy transition brings opportunities to maintain grid reliability in the same fell swoop as decarbonization. (See related story, Clean Energy Groups Don’t Buy ISO-NE’s Gas Reliance).

“We’re taking our eyes off the prize,” Liz Delaney, of solar and storage developer New Leaf Energy, told commissioners. “We need to resolve the near-term issue, and it’s complicated, but at the same time we need to focus on the market mechanisms that are going to get us through the energy transition.”

It’s not just long-duration storage that can help, she said.

“Short-duration battery storage does have a role to play in supporting winter reliability. It’s not the end-all and be-all. But we have miles to go in terms of being able to understand how to optimize battery storage,” Delaney said.

Vermont Department of Public Service Commissioner June Tierney also urged policymakers not to skate past demand response as a powerful grid management strategy.

She pointed to the recent energy emergency in California, which saw significant conservation efforts help CAISO avoid rolling blackouts during an unprecedented heat wave. (See related story, California Runs on Fumes but Avoids Blackouts.)

“Let’s not underestimate the people of the United States. Let’s not underestimate the people of New England,” Tierney said. “If they’re called upon, as millions of Californians were on their cell phones, to reduce demand immediately, they will respond.”

Richard Glick 2022-09-09 (RTO Insider LLC) Alt FI.jpgFERC Chairman Richard Glick (left) and FERC Commissioner Allison Clements listen as panelists talk about New England’s winter reliability problems. | © RTO Insider LLC

FERC Chairman Richard Glick called for a broader focus too, saying that he would like to see a focus on longer-term fixes like new generation, transmission buildout and energy efficiency.

“If we spend all our time thinking about how we’re going to keep the Everett LNG facility open … today will be a failure,” Glick said.

In the end, both the short-term LNG challenges and longer-term clean energy transition got plenty of air time at the forum. But there’s still significant anxiety in the energy sector and among its regulators about what will happen when the thermometers drop and stay low.

“If the lights go out, we’re all to blame. There’s not going to be any finger pointing because we’re all on the hook,” said Phil Bartlett, chairman of the Maine Public Utilities Commission.

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Planning Underway for GridEx VII

NERC has begun planning for next year’s GridEx VII security exercise and is expecting a boost in attendance after participation in the distributed play portion declined for the first time last year.

Speaking at Thursday’s meeting of NERC’s Real Time Operating Subcommittee (RTOS), Laura Brown, director of engagement and security policy coordination at the Electricity Information Sharing and Analysis Center (E-ISAC), told attendees that planners are “looking for … additional support that industry can provide … the [reliability coordinators] in particular.”

The E-ISAC has developed, managed and delivered each iteration of GridEx since the first one held in 2011.

GridEx VI, held from Nov. 16-18, 2021, consisted of a distributed play the first two days involving more than 3,000 people across 293 organizations, and an executive tabletop featuring almost 200 participants from 88 organizations in the U.S. and Canada. (See NERC: GridEx Lessons Already In Use.)

The number of organizations taking part in the distributed play last year was the lowest recorded since GridEx II in 2013, while the 3,000 individuals participating represented fewer than half of GridEx V’s approximately 7,000. Brown said Thursday that the “dip in participation … was in part due to the pandemic as well as some changes that we made to registration requirements,” referring to the fact that unlike in previous years, participants in GridEx VI were only required to register with the E-ISAC to use the exercise tools or access planning materials.

NERC has previously indicated that the registration changes are likely to remain in place for future installments of the biennial exercise and that “future participation numbers are likely to be more comparable to those recorded for GridEx VI.” However, Brown emphasized that “we do expect to see some of those numbers go back up.” While she did not explain her statement at the time, she was likely referring to the relaxation of travel restrictions among many participating organizations.

E-ISAC Reviews Planning Phases

Accompanying Brown to the RTOS meeting was Jesse Sythe, who recently joined the E-ISAC as GridEx program manager. Sythe provided an overview of the GridEx VII planning process, which involves three distinct groups: sponsorship and management, exercise design and development, and exercise planning and execution.

The first group, sponsorship and management, comprises the executive sponsors — NERC CEO Jim Robb and E-ISAC CEO Manny Cancel — and the planning team, which includes Brown and Sythe. Responsibilities of the planning team, according to Sythe, include “gathering input from … other industry groups, developing exercise materials, training, webinars, exercise tools and then drafting the lessons learned report.”

Next is the exercise design and development group, which Sythe called “the bridge between the sponsorship and management lane and … the exercise participants.” The group is divided into a design team, a reliability coordinator team, a subject matter expert team and a training webinar team, and is meant to provide the planners with perspectives on the challenges utilities face every day.

“We don’t always have day-to-day insight into what utilities see in steady state or emergency situations, so the input that we receive from each team helps us to develop the exercise scenario, the materials and all the training webinars that are most beneficial to planners and players,” Sythe said.

The last group involved in the planning process is exercise planning and execution, which includes the lead planners and planners from each organization who adapt the exercise scenario created by the planning team to their particular circumstances. Players are also considered to be part of this lane because they are the ultimate users of the scenario.

GridEx VII Timeline (NERC) Content.jpgThe E-ISAC’s planning timeline for next year’s GridEx VII | NERC

Currently planners are in the initial phase of the project timeline, which Brown and Sythe shared at the meeting. This phase involves setting the goal, objectives and timeline of the exercise and developing an outreach plan, expected to last through the next few months. In the midterm planning phase the team will finalize the scenario and develop exercise materials, followed by the final planning phase when the final exercise materials are distributed and the planner training webinar series is completed. The two phases of the exercise will be conducted in November 2023, with the after-action phase to follow.

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US Power Plant CO2 Emissions Rise 7% in 2021, Ceres Finds

Carbon dioxide emissions by the 100 largest electric power producers in the U.S. increased 7% from 2020 to 2021, Ceres reported Wednesday in its annual benchmarking analysis.

The jump was attributed to the economy returning to a degree of normalcy in 2021 after COVID-related shutdowns triggered a 10% drop in CO2 emissions in 2020. But Ceres also said the increase highlights the need for power providers to take advantage of clean energy incentives recently put in place by the federal government through the Inflation Reduction Act.

The report added historical perspective that shows progress toward zero-carbon generation, even with the year-over-year increase factored in:

  • Carbon dioxide emissions were about 34% lower in 2021 than at their peak in 2007.
  • Sulfur dioxide emissions were down 94%, and nitrogen oxide emissions were down 88% in 2021 from 1990, when the federal Clean Air Act was strengthened.
  • Zero-carbon generation — renewables, hydropower and nuclear — accounted for 40% of U.S. power generation in 2021, an all-time high.
  • Power plants emitted 93% less mercury in 2021 than in 2000; federal limitations on mercury and other hazardous air emissions from coal-fired plants took effect in 2015.

The 100 largest U.S. electricity producers own 3,600 power plants that account fmore than 80% of total generation and plant emissions nationwide.

Natural gas remained the leading source of generation in the U.S. in 2021, at 38%, even as coal made a big year-over-year increase to 22%.

That is a reversal from a decade earlier: In 2011, coal accounted for 42% of U.S. power production and gas only 25%.

Nuclear accounted for 19% of power generation in 2021. Renewables accounted for 13%, breaking down to roughly two-thirds wind and one-third solar, with geothermal making a tiny contribution.

Hydropower was last, at 6% of U.S. power generation in 2021.

Ceres is a nonprofit focused on creating an equitable and sustainable future. Its annual benchmarking analysis of power plant emissions is a collaborative effort with Bank of America Charitable Foundation, Constellation Energy Corp. and Entergy, and the National Resources Defense Council.

ERM authored the analysis, which is drawn from generation and emissions data reported by the U.S. Energy Information Administration and Environmental Protection Agency.

“While the power sector has shown marked improvement over our two decades of analysis, we need to see an acceleration of larger emissions cuts across the industry in order to reach our 2030 emissions reduction goals,” Dan Bakal, senior program director of climate and energy at Ceres, said in a news release accompanying the report. “It’s important to recognize how far we have come, but impossible to ignore how far we still have to go to meet our critical 2030 goals set by the Paris Accord. While many of the largest power producers have announced climate commitments and strategies to reduce their carbon emissions, the rapid decarbonization required demands increased ambition.”

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California Runs on Fumes but Avoids Blackouts

CAISO came dangerously close to calling for rolling blackouts Tuesday night but avoided issuing the final order to utilities thanks in part to a jarring alert sent out to millions of cell phones by the governor’s Office of Emergency Services.

A series of shrieking tones was followed by a text that said, “Conserve energy now to protect public health and safety. Extreme heat is straining the state energy grid. Power interruptions may occur unless you take action.”

The unusual alert was sent at 5:45 p.m. after CAISO declared an energy emergency alert 3. An EEA 3 means the ISO is “unable to meet minimum contingency reserve requirements and controlled power curtailments are imminent.”

CAISO CEO Elliot Mainzer summed up Tuesday’s near miss in a media briefing Wednesday, comparing it to a car running out of gas.  

“We were well into the reserve tank of the car,” Mainzer said. “We were down to the last gallon there and dipping into our operating reserves. And we typically carry somewhere in the area of 3,000 to 4,000 MW of operating reserves, so we were very, very close to the bottom.”

Demand in CAISO hit a record high Tuesday of more than 52 GW as temperatures broke records across the state, including 116 degrees Fahrenheit in Sacramento, near CAISO’s headquarters.

CAISO Record Demand (CAISO) Content.jpgCAISO saw record demand Tuesday of more than 52 GW. | CAISO

 

CAISO had ordered utilities to “arm” for load shed when a wave of consumer conservation following the cellphone alert narrowly averted blackouts. (A number of cities experienced outages because of a communications snafu with the Northern California Power Agency, CAISO said.)

Locational marginal prices throughout the state ranged between $1,700 and $2,300/MWh as the crisis continued, according to data posted on CAISO’s website.

The ISO called off the EEA 3 at 8 p.m., posting on Twitter: “Consumer conservation played a big part in protecting electric grid reliability. Thank you, California!”

The 3,500 MW of utility-scale 4-hour lithium-ion batteries installed since the state’s last rolling blackouts in August 2020 performed well and played a role in avoiding worse problems, Mainzer said.

Demand response from industrial users, and the ability to access emergency generation resources under an executive order from last year, played a part, as did more than 6,000 MW of imported hydroelectricity from the Pacific Northwest, CAISO said.

The crisis did not end Tuesday, however. The extraordinary heat wave gripping California is predicted to continue through Friday, with temperatures exceeding 100 F in greater Los Angeles, the San Francisco Bay Area and the inland Central Valley.

CAISO declared an EEA 2 on Wednesday afternoon, asking customers to turn up their thermostats and to postpone using large appliances such as clothes dryers and dishwashers.

Mainzer said the state would need consumers to continue conservation efforts, “hopefully for another reliable evening.”

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PJM TEAC Briefs: Sept. 6, 2022

Dominion Adds $25M to Data Center Alley Upgrades

VALLEY FORGE, Pa. — The price tag on Dominion Energy’s (NYSE:D) “Data Center Alley” transmission upgrades in Northern Virginia has grown by $24.6 million to $627.6 million.

Dominion told the Transmission Expansion Advisory Committee Sept. 6 it needed to increase the scope of the reliability project to clear capacity from two planned substations, including reconductoring seven 230-kV lines and upgrading terminal equipment. The new Wishing Star substation will be constructed near the existing Brambleton substation, while the Mars substation would be sited near Dulles Airport.

The reconducting of 11.4 miles of 230-kV lines totals about $29 million, and the terminal equipment is estimated at $12.65 million. Eliminating upgrades to the Brambleton substation and Loudoun breaker replacements will save $17 million.

According to the immediate needs statement presented by PJM Senior Manager Sami Abdulsalam, data centers in Dominion’s transmission zone in Northern Virginia have been experiencing “unprecedented load growth” since 2018, which is expected to continue past 2027.  (See PJM Sees Additional $603M ‘Data Center Alley’ Tx Spend.)

Although Dominion is already working on more than $200 million in supplemental and baseline transmission upgrades in the area, PJM says it expects numerous reliability violations in the 2024/25 timeframe and without additional upgrades it expects there will not be sufficient transmission to serve the load beyond that period. The required service date for Dominion’s solution is June 1, 2025.

Nearly $200 Million in Additional Transmission Projects

FirstEnergy (NYSE:FE) and Dominion presented several other projects to serve new load customers and replace aging infrastructure.

Dominion is planning to construct two new substations for new data centers in Culpeper County, Virginia. The Germanna substation is being considered along the Remington-Gordonsville line at a $55 million cost for a 139-MW data center complex.

Rappahannock Electric Cooperative has asked Dominion to increase capacity at the existing Mountain Run delivery point and to construct a new substation nearby for an estimated $60 million. The project, which is still conceptual, would service a new 350-MW data center.

Dominion also presented a project to rebuild approximately 7.9 miles of double circuit line on the Braddock-Ox line in Prince William County, Virginia, at a $43.5 million price tag in response to the identification of thermal violations on the line.

Other projects:

      • Dominion is planning to replace two aging transformers, Farmville and Clubhouse, for $6.4 million and $6.6 million, respectively. Both units were constructed in 1981.
      • Dominion is engineering a new single 230-kV feed for a crypto mining customer in Battleboro, North Carolina, for $750,000.
      • FirstEnergy is constructing a $4.9 million 230-kV circuit breaker and equipment feeding into a new 230-234.5-kV transformer in Frederick County, Maryland. The installation will supply a new customer request with a 30-MW anticipated load.
      • FirstEnergy presented a $15.1 million project to build a new Sage Substation, near the Doubs-Eastalco lines in Frederick County, Maryland, to serve a new customer with an anticipated 240-MW load.

PJM Outlines Phase 2 of OSW Study

PJM is embarking on the second phase of an offshore wind transmission study requested by the Organization of PJM States Inc., which will consider scenarios for the injection of 8,600 to almost 20,000 MW into Delaware, Maryland, New Jersey and Virginia.

Phase 1 of the study, released last year, looked at five scenarios to identify regional transmission solutions to accommodate the coastal states’ offshore wind goals, as well as all PJM states’ renewable portfolio standards. It identified costs of $627 million to $3.2 billion for injections of 6,400 to 17,000 MW.   (See Tx Upgrades for PJM OSW, Renewables Could Cost $3.2 Billion.)

Phase 2 includes three short-term scenarios (study year 2028) assuming 2,022 or 4,000 MW from Maryland, 3,906 MW from New Jersey and 2,640 MW from Virginia, per state requests. Five additional scenarios target year 2035, most of them using the same injections for Maryland, 7,648 MW from New Jersey and 2,640 or 5,200 MW for Virginia.

The final scenario, requested by Pennsylvania, will assume no offshore wind as a way to separate the OSW cost impacts from that of transmission needed to support other resources needed to meet state RPS requirements.

The new study will use an updated 2022 load forecast and provide a “much more in-depth and granular” market efficiency analysis than Phase 1, said PJM’s Matthew Bernstein. The market efficiency analysis will be performed on at least two scenarios, he said.

The study will include a retirement scenario to offset the increased renewable penetration levels assumed in the studies, based on formal deactivation notices and federal and state policies.

Each scenario will include a generator deliverability thermal analysis for summer, winter and light load conditions and identify transmission solutions for each reliability violation, including costs.

The results of the two scenarios based on current policies are expected to be completed by the end of the year. The sensitivity analyses requested by the states will be available in early 2023, PJM said.

PJM Reviewing Responses to Tx Proposal Windows

PJM received more than 30 proposals in response to two recent transmission proposal windows.

The RTO’s 2022 Multi-Driver Proposal Window 1, which closed Aug. 8, generated 14 proposals from three entities to solve potential reliability violations on multi-driver facilities. The proposals, eight greenfields and six upgrades, ranged from $215,000 to $127 million. None included cost containment.

PJM expects to begin preliminary evaluation of the proposals in early September and complete its selection by the end of the year for board approval in February 2023. PJM will coordinate with MISO in its evaluations.

PJM also received 17 proposals from seven entities in response to Reliability Proposal Window 1, which closed Aug. 30.

The proposals — six greenfield projects and 11 upgrades — ranged in cost from $260,000 to $386.7 million and addresses 275 flowgates. Seven of the proposals included cost containment measures.

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NYISO Proposes Fixes for Interconnection Backlog

NYISO is planning to narrow the scope of its system reliability impact studies (SRIS) and revise its pro forma interconnection agreements in response to resource challenges and the unprecedented increase in the number of generator interconnection requests.

ISO officials outlined the proposed changes at the Sept. 1 Transmission Planning Advisory Subcommittee (TPAS) and Electric System Planning Working Group meeting.

Despite an increase in staffing, the workload for the ISO’s interconnection studies (IS) team has doubled since 2018 when six engineers managed 120+ studies, about 20 per engineer. This year, the ISO’s nine engineers are managing 346+ studies, an average of 40 each. 

Productivity also has been hampered as the ISO had to replace five engineers on the IS team between January 2021 and March 2022, meaning two-thirds of the team lacked interconnection experience.

These problems have been exacerbated by labor market shortages, which prevented consultants from taking on more projects, and more customers requiring personalized attention because of their unfamiliarity with NYISO processes, Thinh Nguyen, senior manager of interconnection projects, said.

NYISO attorney Sara Keegan said the volume of interconnection requests is also taxing the ISO’s legal team. 

As a result, Nguyen said the ISO plans to eliminate from the SRIS for large facility interconnections the voltage deviation analysis and harmonic analysis and perform other analyses — NPCC A-10 testing, transfer assessments and sub-synchronous torsional interaction screenings — on a case-by-case basis. 

The streamlining of the SRIS process is in addition to other changes the ISO has made to address the growing interconnection queue and address the labor shortage, including a salary study that resulted in pay increases for engineers and the planned hiring of staff to help guide project developers through the interconnection process. (See NYISO Details 2023 Budget & Compensation Updates.)  

Stakeholders agreed that elements of the SRIS study were redundant for projects that go through class year studies. 

In addition, Keegan said the ISO will seek FERC approval for changes to its pro forma interconnection agreements and the creation of a pro forma engineering, procurement and construction (EPC) agreement for some system upgrade facilities (SUFs) and system deliverability upgrades (SDUs).

Keegan said the ISO will propose revising the small (SGIAs) and large generator interconnection agreements (LGIAs) to add placeholders to address recurring variations that have necessitated non-conforming agreements and clarify security, invoicing and oversight cost rules, among other changes.

Large generator interconnection procedure (NYISO) Content.jpgNYISO large generator interconnection procedure | NYISO

 

The pro forma EPC agreement would cover SUFs and SDUs not addressed in LGIAs or SGIAs because the upgrades are required for affected systems or for multiple projects, Keegan said. She noted that FERC has approved such an agreement for MISO and has proposed an agreement for affected system in its generator interconnection Notice of Proposed Rulemaking (NOPR) in June (RM22-14). (See FERC Proposes Interconnection Process Overhaul.)

NYISO anticipates presenting the interconnection agreement related tariff revisions at either the Oct. 3 or Nov. 1 TPAS meeting and is targeting Q1 2023 for a Section 205 filing with FERC. NYISO also anticipated additional revisions in 2023 as part of a project proposed by the Alliance For Clean Energy New York and through an expected compliance filing from FERC’s final order on the generator interconnection NOPR.

Nguyen also outlined plans to revise the base case inclusion rules used in the interconnection studies to ensure the studies incorporate transmission and class year projects that may impact each other by using existing system capacity or requiring similar upgrades.

The ISO said it expects discussion of proposed tariff changes through the third quarter. It said written comments should be sent to Kirk Dixon (kdixon@nyiso.com).  

RNA Draft Report Finds No Immediate Needs

The 2022 Reliability Needs Assessment (RNA) found that there were no reliability needs on the New York bulk electric grid through 2032.

While the report found the ISO’s grid will meet all reliability criteria based on forecast demand and expected weather, it said the reliability margin could be narrowed or eliminated, based upon changes in forecasted system conditions.

“Delayed implementation of projects in this plan, additional generator deactivations, unplanned outages, changes in load patterns and extreme weather could potentially lead to deficiencies in reliable electric service in the coming years,” the report said.

The report said reliability margins will likely shrink in the future because of the unavailability of simple cycle combustion turbines because of environmental rules, including the state Department of Environmental Conservation’s Peaker Rule, which will reduce nitrogen oxides emissions from CTs in a phased implementation from 2023 to 2025.

“Additionally, significant load-increasing impacts are forecasted due to expected growth in electric vehicle usage, large cloud-computing data centers and other electrification (i.e., conversion of home heating, cooking, water heating and other end-uses from fossil-fuel based systems to electric systems),” the RNA said. “However, additional resources planned to be in-service in the near-term horizon, such as the Champlain Hudson Power Express connection from Hydro Quebec to New York City, provides a boost to the margins. Additionally, the NYISO is forecasting over the next ten-year period a decrease in energy usage due to energy efficiency initiatives and increasing amounts of behind the meter solar generation.”

“While we don’t have reliability needs in the study period, the margins are not far from tipping,” the ISO’s Laura Popa told the two committees.

The RNA is the first step of the ISO’s reliability planning process. The grid operator plans to issue its 2023-2032 Comprehensive Reliability Plan in 2023. Any needs identified in the short-term reliability process in year one through year three will be addressed in its quarterly short-term assessments of reliability.

NYISO requested comments or questions be submitted to either Laura Popa (lpopa@nyiso.com) or Kirk Dixon (kdixon@nyiso.com) by Sept. 6. The ISO is targeting Sept. 19 for its third RNA draft and then submitting the report for board approval in November.