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November 9, 2024

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Energy-short Europe Importing More US Shale Gas

Thierry Lepercq (Green Hydrogen Coalition) Content.jpgFounder of Hydeal Ambition Thierry Lepercq | Green Hydrogen Coalition

Europe is in a historic energy crisis, and the impact on the U.S. is not going to be good as exports of its shale gas increase, warned a Paris-based industrialist and entrepreneur Tuesday.

Thierry Lepercq — an energy entrepreneur, author and founder of HyDeal, a pro-hydrogen industrial coalition aiming to replace gas with hydrogen — said U.S. gas prices will “skyrocket” because of European demand.

“I can tell you that $150 billion right now are being invested in LNG terminals across the coast of Texas and Louisiana to ship that very cheap” shale gas, he warned in a webinar produced by the U.S.-based Green Hydrogen Coalition.

“You’ll have that arbitrage thing where in the next few years, massive amounts of natural gas are shipped from the U.S. and to go to Europe and Asia. And the prices in Europe are likely to go down, but the price in the U.S. is going to skyrocket.

“Imagine the whole of the U.S. economy with energy prices going up by 100 to 200% because of the contamination from Europe.

“The same thing is going to happen to the U.S. with maybe [a] one- or two-year delay,” he said. “The message here for the U.S. is to think big immediately. You want to go into tens of millions of dollars to upgrade hydrogen [production] very fast.”

LNG Export Terminals Approved (DOE) Content.jpgDOE and FERC have approved the construction of another 13 export terminals with a combined capacity of 25 bcfd. The first-ever exports of domestically-produced LNG from the lower-48 states occurred in February 2016. | DOE

 

Lepercq, who is also on the board of directors of a newly formed U.S.-based HyDeal coalition, said hydrogen is the only real answer.

He said most of the global oil companies are reluctant to invest the billions of dollars or euros to increase production as they did following the 1970s oil crises because they fear the investments will become stranded assets.

“There needs to be a shock therapy,” he said, referring to the governments of industrialized nations. “We’re talking about hundreds of gigawatts that need to be deployed [to produce green hydrogen] very quickly, if the U.S. wants to avert that … tragic situation, which is going to strike Europe in the next couple of months.”

Florian Knobloch (Green Hydrogen Coalition) Content.jpgGerman economist Florian Knobloch | Green Hydrogen Coalition

In the face of that dire outlook, fellow panelist Florian Knobloch, an economist based in Berlin and adviser to the German federal government, outlined a detailed strategy that Germany has developed to help finance the production of hydrogen globally, with contracts to buy it via pipeline or vessels.

German gas prices have skyrocketed 400% in the last year. Knobloch said the government has developed a plan to assist consumers and industry with soaring energy bills this winter. Those subsidies will cost 4% of GNP, he said.

“We have to be quite realistic [that] hydrogen won’t help us to come through the next two winters,” he said, adding that natural gas imports from the U.S. and elsewhere are crucial.

The government’s plan is to push for the use of hydrogen in the hard-to-abate sectors such as heavy industry, steelmaking and chemicals, and heavy transportation. He said the government does not see the value at this point of heating buildings with hydrogen.

But Germany will remain an energy importer indefinitely, he said.

“We will be relying on hydrogen imports at massive scales, which is why we are planning for actually creating these hydrogen production facilities around the globe already, because hydrogen is a new market and we can’t just wait for hydrogen production facilities to pop up around the globe.”

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Arkansas PSC’s Thomas Makes Way for His Successor

Arkansas Public Service Commission Chair Ted Thomas, a towering presence among MISO and SPP stakeholders, said his decision to step down from the state’s regulatory body and enter the private sector is simply a matter of making room for his successor.

Appointed by Gov. Asa Hutchinson in 2015, and with four years left on his term, he said that with a new governor taking office next year, it is time to move on.

“I didn’t want it to last forever,” Thomas told RTO Insider on Monday. “I had a great working relationship with Hutchinson. I thought it best to let the other person make their own choice.”

Sarah Huckabee Sanders — former White House press secretary under President Donald Trump and the daughter of former Arkansas Gov. Mike Huckabee — is a heavy favorite to win the state’s gubernatorial election in November. Hutchinson is term limited.

Thomas made his decision to resign public last week after submitting a resignation letter to Hutchinson on Sept. 9. The resignation is effective Oct. 1.

Almost always the tallest person in the room, Thomas has been heavily involved in regulatory matters over the last couple of years. In addition to serving on SPP’s Regional State Committee (RSC), several other stakeholder and regulatory groups, and the National Association of Regulatory Utility Commissioners’ Electricity Committee, he was appointed last year to FERC’s Joint Federal-State Task Force on Electric Transmission that was charged with unleashing transmission expansion to improve resilience and connect new renewable generation (AD21-15). (See FERC-State Task Force Considers Clustering, ‘Fast Track’ to Clear Queues.)

That work continues. Thomas expressed regret about stepping away from the task force before it completes its task.

“I’m sure there’s more to do, but we’ve talked about a lot of the issues on the front end,” he said.

“This is sad for all of us who follow utility regulation,” tweeted Matt Christiansen, general counsel at FERC. “I am not sure there’s anyone whose perspective I have been more eager to hear over the last several years than Chair Thomas’.”

“Big shoes!” added energy consultant Karl Rabago, a former Texas commissioner.

Thomas said he has enjoyed working with the grid operators and their staffs, saying it was a big part of his tenure. He named-checked staff from SPP’s Cost Allocation Working Group and the Organization of MISO States (OMS) and said he was “very lucky to get to know some of those people.”

“You’re creating value for the ratepayers” when working with RTOs,” Thomas said. “There are a lot of benefits, but it’s not easy to earn them. You have to work through the stakeholder process.”

If there’s a regret for Thomas, it might be not seeing through the SPP Improved Resource Availability Task Force that he chairs. The group is responsible for addressing recommendations following the RTO’s review of its response to the February 2021 winter storm.

“That’s very important work,” he said, noting the task force is still in the middle of its assignment.

Thomas hinted he may still be visible in future grid operator circles, but right now, he has work to do.

“I’ll run through the tape,” he said.

Arkansas PSC Commissioner Justin Tate will take Thomas’ place on the RSC, beginning with October’s meeting. Fellow Commissioner Kimberly O’Guinn will remain on the OMS, Thomas said.

The resignation came two days after Thomas colorfully recused himself from a solar energy case involving Petit Jean Electric Cooperative and other utilities over alleged unauthorized net-metering practices. He accused Petit Jean of making false criminal accusations against him and said it was “soullessly” wielding “the billy club of the monopolist” and called the utility a “litigation machine paid for by the same ‘members’ that they club.”

The utilities requested Thomas’ recusal after he made comments during a legislative committee hearing earlier this year. They said his comments on interconnection requirements reflected a “predisposition or prejudgment of key issues.”

Thomas told an Arkansas newspaper that his resignation had “nothing to do” with the case, but that “no one will believe that.”

In his recusal Thomas wrote that the utility had four times defied PSC orders to file a tariff that included statutory language to interconnect residential solar customers to the grid.

“Then, like a Saul Goodman stunt, Petit Jean’s counsel falsely accused me of criminal conduct and sought my recusal. Better call Saul!” he said, referring to the lawyer character from the TV shows “Breaking Bad” and “Better Call Saul,” in making his point.

“Solar panels have been sitting in the sun not interconnected for months and months, and a formal PSC process would be litigated and appealed for additional months, if not years,” Thomas said. “This result seems to be the monopolist’s intended purpose. I do not wish to be used as a weapon by the monopolist in the endless expensive efforts to keep people … from interconnection to the grid.

“I’m all good, man. I recuse.”

“I’m very contentious. It’s in my DNA,” Thomas said Monday. “If someone wants to throw down, let’s throw down. Perhaps I could be a better person, but if we have to rumble, let’s rumble.”

Thomas has previously served as chief deputy prosecuting attorney for Arkansas’ 20th Judicial District, an administrative law judge for the PSC, Gov. Huckabee’s budget director and a member of the Arkansas House of Representatives, where he was chairman of the State Agencies and Governmental Affairs Committee during his final term.

The Arkansas Advanced Energy Association last year honored Thomas with its Ron Bell Advanced Energy Leadership Award for outstanding contributions to the renewable power, efficiency and energy contracting industry.

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Utilities File Incident Reports in Latest California Wildfires

Pacific Gas and Electric (NYSE:PCG) and Southern California Edison (NYSE:EIX) each filed incident reports with the California Public Utilities Commission last week indicating their equipment may have been involved in the two largest fires burning statewide.

PG&E said the U.S. Forest Service placed caution tape around the base of a 60-kV transmission pole close to the ignition point of the Mosquito Fire, a 47,000-acre blaze burning mostly out of control in the Sierra Nevada foothills, 50 miles northeast of Sacramento. The fire began near the Oxbow Reservoir in Placer County, where PG&E said it recorded “electrical activity” when the fire started on Sept. 6.

“Thus far, PG&E has observed no damage or abnormal conditions to the pole or our facilities near Oxbow Reservoir [and] has not observed down conductor in the area or any vegetation related issues,” the utility said in a report Thursday to the CPUC. “Our information reflects electrical activity occurred close in time to the report time of the fire. The investigation is ongoing. This information is preliminary.”

The California Department of Forestry and Fire Protection (Cal Fire) has not reported any injuries or structural damage from the Mosquito Fire, but the blaze has caused hazardous air pollution in the nearby city of Auburn and threatened rural communities in its path.

More than 400 miles to the south, the Fairview Fire has killed two people and burned more than 28,000 acres, Cal Fire and the Riverside County Fire Department said. The blaze is 53% contained, Cal Fire reported Monday.

SCE filed a report with the CPUC on Sept. 5 saying, “Our information reflects circuit activity occurred close in time to the report time of the fire” at 3:37 p.m. that day near the city of Hemet. “The investigation is ongoing.”

September traditionally marks the start of fire season in California, as autumnal offshore breezes fan vegetation parched by dry summers. The fire season typically continues until rains begin in the late fall in the state’s Mediterranean climate.

SCE and PG&E equipment has been blamed for starting major wildfires in recent fire seasons.

The catastrophic blazes include the Camp Fire, the state’s deadliest wildfire, which was ignited by a broken PG&E transmission line in November 2018, and last year’s Dixie Fire, a nearly 1 million-acre wildland blaze started by a PG&E distribution line.

Government investigators determined that SCE power lines blown together by high winds sparked the 282,000-acre Thomas Fire in Santa Barbara and Ventura counties in December 2017. The largest fire in state history at the time, it killed a firefighter and a civilian. Mud and debris slides in its aftermath killed 21 others when heavy rains drenched fire-scarred mountain slopes, washing away homes and vehicles.

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Acoustic Study to Protect Whales Extended at Empire Wind Site

A marine acoustic study underway in the Empire Wind project lease area will be extended through 2028.

The study by Empire Wind and the Wildlife Conservation Society (WCS) is monitoring large whales in the New York Bight and is expected to yield data that will aid in protection of wildlife before, during and after construction.

The offshore wind farm will be built across 80,000 acres 15 to 30 miles south of Long Island and will generate 2.1 GW.

Two moored acoustic monitoring buoys have already compiled more than 2,000 days of monitoring data and detected more than 18,000 sounds from fin, humpback, sei and North Atlantic right whales. The most frequent sound has been a low-frequency song note produced by fin whales. Detections have tended to peak in early winter.

The partners on the project say the acoustic data, combined with sighting data from aircraft and surface vessels, are providing important baseline information on whale activity in and near the Empire Wind lease area. This will guide efforts to minimize the project’s impacts on them.

Empire Wind is a joint venture of Equinor (NYSE:EQNR) and bp (NYSE:BP). WCS is working with the Woods Hole Oceanographic Institution, which invented and operates the acoustic buoys. WCS began the monitoring in 2016, and Equinor began supporting it in 2019.

“As a new industry, it is crucial that we establish best-in-class practices throughout the development phase of our projects from the start,” Siri Espedal Kindem, president of Equinor Wind US, said in a news release Wednesday announcing extension of the program.

“The data from this acoustic monitoring and our analyses clearly demonstrate that several large whale species are seasonally present, and some for extended periods of time in the New York Bight,” said Howard Rosenbaum, the project principal investigator and director of WCS’ Ocean Giants Program.

“We applaud Equinor and the Wildlife Conservation Society for expanding their partnership and ongoing commitment to environmental stewardship and understanding marine life — setting a strong example for how strategic collaboration can mitigate potential risks and support responsible project development,” said Doreen Harris, president and CEO of the New York State Energy Research and Development Authority.

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PJM Market Implementation Committee Briefs: Sept. 7, 2022

DR Data Proposal Rejected

VALLEY FORGE, Pa. — The PJM Market Implementation Committee narrowly rejected a proposed issue charge from curtailment service provider CPower Energy Management that would have sought to expand access to data from retail demand response customers.

Stakeholders cited pending legislative efforts at the state level and concerns about utilizing statistical sampling instead of collecting data from households directly. (See NJ Eyes Rules to Protect, Gather Advanced Metering Data.)

Paul Sotkiewicz, of E-Cubed Policy Associates, questioned if statistical sampling could be an adequate substitute for direct household data and said that the belief that residential use tends to be homogenous may be a poor assumption. If sampling was to become standard, he said that could discourage states from pushing smart metering technology down to the residential level.

“I don’t find it very appealing that either because somebody didn’t do their due diligence … that PJM and the rest of its membership should be beholden to that and have to settle for statistical sampling,” he said.

Two Alternatives on VOM Advance to MRC

Two competing proposals from PJM and Constellation Energy to address variable operations and maintenance costs advanced to the Markets and Reliability Committee meeting on Sept. 21.

The PJM proposal, which passed with more than 70% support, would include default adders for minor maintenance and operating costs, clarify the definitions of major and minor maintenance, create a new review process and timeline, and clarify the requirements for supporting documentation.

The Constellation package, which passed with 54%, contains the same provisions as the PJM document, but it would include nuclear refueling costs and associated major maintenance under a generator’s capacity offer rather than its VOM energy offering.

Constellation’s Jason Barker said that defining refueling as a variable cost is inconsistent with how maintenance is conducted on nuclear units.

“This is a significant change in that respect because they are deeming most, if not all, the maintenance done in a reactor fueling as variable,” when nearly all of it is fixed, he said. (See “Variable Operations & Maintenance Cost Development,” PJM Market Implementation Committee Briefs: Aug. 10, 2022.)

Rather than vote for their preference of the two proposals, Barker encouraged stakeholders to vote against them both, pushing the revisions back to the Cost Development Subcommittee for additional rewriting. He said those meetings tend to see less participation and said a better package could be formed there through input from more voices. Instead, the MRC will consider both proposals.

IMM, PJM to Collaborate on Manual Revisions Prior to MRC

The MIC endorsed a slate of manual revisions to conform with FERC’s order approving revised energy price formation rules (EL19-58, ER19-1486), but discussion regarding the impact some of the changes will have on hydropower resources led to a request that PJM staff work with the Independent Market Monitor to finetune the language.

The committee endorsed by acclamation revisions to manuals 11, 27, 28 and 29. But before it did, the Monitor raised concerns that the Manual 11 changes were inconsistent with the Operating Agreement’s provisions and would limit the amount that hydro resources could offer as reserves.

The Monitor did not have proposed revisions to present, and some stakeholders expressed frustration that its presentation was only posted the day prior to the meeting. Barker noted that the tight time frame before the Oct. 1 implementation of the manual revisions could make it challenging for hydro operators, such as Constellation, to get a firm understanding of any changes before they’re responsible for compliance.

PJM and Monitor staff pledged to work together, with input from hydro stakeholders, on a friendly amendment that the Monitor would offer at the MRC when the revisions are brought up for a vote at that committee.

Other MIC Business

Because other agenda items ran over their allocated time (See related story, PJM, Monitor Debate Black Start Fuel Requirements Proposals.), work on an IMM proposal addressing capacity offer opportunities for generation with co-located load was postponed. A special session of the MIC will be scheduled to continue discussion of the issue.

The MIC also reviewed PJM’s proposed capital budget, which would increase spending to $45 million, a $3 million increase over current funding. The budget was first presented at the Planning Committee the day before and was also shown to the Operating Committee the next day. (See related story, “Planning Committee Reviews Capital Budget,” PJM Planning Committee Briefs: Sept. 6, 2022.)

Finally, the committee endorsed routine revisions to Manuals 18 and 18B, deleting outdated information, correcting and clarifying existing provisions or practices, and adding administrative updates.

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PJM Operating Committee Briefs: Sept. 8, 2022

Cybersecurity Update

PJM Chief Information Security Officer Steve McElwee briefed the Operating Committee last week, saying that cyberattacks against the U.S. and its allies remain a principal concern. Although attacks from Russia and associated entities have declined, Iran has been increasing its offensives, he said.

Among the major forms of attack seen recently are ransomware, which encrypt a computer and lock users out of data and functionality, and distributed denial of service attacks, essentially bombarding a server with requests to overwhelm a network.

PJM has been hardening its systems by retiring weak encryption tools, blocking international and anonymous traffic and prioritizing external vulnerability remediation, McElwee said.

Committee Endorses Maximum Emergency Package

The committee overwhelmingly endorsed a package from PJM addressing the supply chain for generators and concerns regarding the impact of increased environmental restrictions on maximum emergency generation actions. The PJM option received 92% support over a second package from the Independent Market Monitor, which would have added clarifications and changed references to “fuel” to “fuel and consumables.”

The IMM proposal also would have allowed for resources with less than 10 days of fuel and consumables inventory to be made unavailable for economic dispatch, with a penalty equal to the daily capacity values.

Renewable Dispatch Proposal Vote Delayed

The OC agreed to postpone voting on a joint PJM/Monitor proposal intended improve the dispatch of renewable generators after several stakeholders expressed concern about certain elements.

The proposal would require intermittent resources with capacity commitments to offer economic maximum megawatts equal to or greater than their hourly forecast. Several stakeholders said this could result in renewable output being held back by an under-forecasted value being used.

Other stakeholders were concerned about the elimination of the curtailment flag, which PJM uses to indicate to generation operators that their units have been curtailed and that they should adjust their output accordingly. The proposal would instead use existing basepoints to reflect the RTO’s desired dispatch.

Several committee members said they did not share these concerns but that they would not oppose delaying a vote to address them.

PJM staff agreed to send the proposal back to the DER & Inverter-Based Resources Subcommittee for work and bring it back to the committee for a vote at its meeting next month. They said a one-month delay on approval would still allow for implementation before the second quarter of 2023.

Delays to Scheduled Go-live Date for PPL DLR

The scheduled go-live date for PPL’s dynamic line ratings has been moved out by two weeks, with implementation now slated for Sept. 27 for the day-ahead market and Sept. 28 for real-time. PPL had already delayed rollout from July to this week because additional work was needed for changes to its energy management system with its vendor. (See “PPL Delays DLR Implementation to September,” PJM Operating Committee Briefs: July 14, 2022.)

Review of IROL-CIP Solution Postponed

Discussion of creating a mechanism for generators to receive reimbursement for compliance with NERC reliability standard CIP-002-5.1 was postponed because of concerns raised by the Monitor.

The PJM proposal would have allowed generators deemed critical to interconnection reliability operating limits by NERC to submit their capital and recurring costs to PJM and the Monitor for review and possible monthly payments. According to the problem statement, designation as a critical generator can carry a “significant additional cost burden.”

PJM staff noted that they have adequate time to explore other avenues.

Committee Approves Slate of Manual Revisions

The committee approved several changes by acclamation, with little discussion and no debate:

  • tariff and manual changes to streamline the process of scheduling internal network integration transmission service; (See “Issue Charge OK’d on Internal NITS Process,” PJM Operating Committee Briefs: July 14, 2022.)
  • revisions to Manual 14D and Manual 13 to conform with NERC standards EOP-011, IRO-010 and TOP-003; and
  • changes to Manual 10, 12 and 13, associated with reserve price formation.
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PJM, Monitor Debate Black Start Fuel Requirements Proposals

VALLEY FORGE, Pa. — PJM and its Independent Market Monitor got into lengthy debates at two different committee meetings last week over each other’s proposed fuel requirements for black start resources (BSRs) as they tried to win last-minute stakeholder support.

Voting on the proposals opened online after the Operating Committee’s meeting concluded Thursday and will close Tuesday at 5 p.m. ET. In a unique situation, voting is open to both the OC and Market Implementation Committee; stakeholders who are members of both need only participate in one committee’s vote, and PJM will remove any double votes. A special joint teleconference of the committees is scheduled for Friday to review the results.

Because the issue was assigned to both committees, each heard identical presentations from PJM and the IMM last week — and sat through nearly identical debates on the proposals’ merits among RTO staff, Monitor Joe Bowring and stakeholders who were confused by certain elements. Both Wednesday’s MIC and Thursday’s OC meetings threatened to run long, but the committees’ respective chairs deferred or shortened other items on their agendas to keep things on schedule.

Both proposals are the culmination of a four-year-long process intended to ensure that BSRs are available when they are needed. They would create two tiers of service, the higher of which provided by fuel-assured BSRs. While the criteria of “fuel assured” varies by resource, they can include dual-fuel capability, on-site fuel storage and connections to multiple gas pipelines.

Each transmission zone would be required to have at least one fuel-assured BSR. Such resources would be selected based on their level of fuel assurance. Also included are additional reliability criteria to mitigate extreme cases in which the unavailability of non-fuel-assured BSRs would result in a large increase in zonal restoration time.

The main differences between the proposals were highlighted at last month’s committee meetings. The Monitor’s plan, for example, would not allow intermittent resources, other than run-of-river hydro, to be BSRs because they cannot currently meet the requirements. (See Members near Vote over PJM, IMM Black Start Fuel Requirements.)

At last week’s meetings, Bowring argued that PJM’s package of revisions — jointly proposed with Brookfield Renewable and the D.C. Office of the People’s Counsel — could result in overpayment for BSRs, as an existing hypothetically “perfect” BSR — one that meets all the physical standards to be fuel assured — would not be required to offer to provide the higher-tier service and meet the performance obligations that came with it; therefore, PJM would not recognize its fuel-assured status.

In such a scenario, Bowring argued that PJM would be required to select another fuel-assured BSR in the same zone in the procurement process, resulting in customers paying twice for the same service. He said all resources that already meet the physical standards to be fuel-assured should also be required to meet the proposed requirements to be designated as such, report on their current status and not receive payment if they cannot not provide the service.

“Customers are already paying these resources to be fuel assured,” Bowring said. “PJM should simply require those resources to meet that obligation.”

Several stakeholders took this to mean that the Monitor was proposing that all existing BSRs become fuel assured. Bowring repeatedly clarified that was not in the proposal, though he did state that all new black start resources should be required to be fuel assured.

PJM staff noted that every transmission zone already has at least one fuel-assured BSR. They acknowledged that the Monitor’s hypothetical scenario was possible, but they argued it was highly unlikely, as the RTO would not necessarily be required to procure another fuel-assured resource and that it could look for other mitigation steps. Bowring responded that the fact that it’s possible “makes my point for me.”

“The zones meet the fuel-assurance requirement based on resources that already meet all the physical standards to be fuel assured but that are not required to become formally fuel assured under PJM’s proposal,” he said. “That is the ‘paying twice’ problem.”

If approved the proposals would go before the Markets and Reliability Committee for a first read next week and voted on at the committee’s meeting next month.

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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.