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November 17, 2024

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MISO Weighs MTEP 23 Alternatives to South Reliability Projects

MISO planners say they have pinpointed several proposed projects in this year’s transmission planning cycle that might provide more system benefits with altered designs.

During a series of subregional planning meetings this week, staff said nine projects in the draft 2023 Transmission Expansion Plan (MTEP 23) are candidates for alternative designs because of their size and complexity. The projects account for more than 40% of the MTEP 23 price tag, currently standing at $8.8 billion across 578 projects.

During a MISO Central subregional planning meeting Tuesday, expansion planner Amanda Schiro said most of the projects singled out for alternative designs are for substation work in the southern region. They include the controversial $1.1 billion, 150-mile 500-kV line and substation project Entergy has proposed for southeast Texas and all three phases of its nearly $2 billion, 500-kV Amite South line and substation work in the state’s southern region. Entergy has said both projects are needed for reliability.

The $3.6 billion in localized reliability spending MISO South transmission owners proposed this year has sparked debate among stakeholders as to whether Entergy is attempting to dodge more efficient, regionally cost-shared projects. The grid operator this year pledged to examine the TOs’ proposals for larger, combined project opportunities. (See Initial MTEP 23 Ignites Familiar Arguments over MISO South’s Reliability Spending.)

Competitive transmission developers and clean energy groups have said the two Entergy projects resemble previous economic projects MISO recommended and ultimately canceled in 2016 and 2017. The economic projects’ costs would have been shared regionally, but reliability projects are billed only to the local transmission zone in which they’re located. (See NextEra, SREA Protest Canceled MISO Project at FERC.)

Other projects tagged for alternative exploration include Entergy Louisiana’s $164 million line and substation upgrades to alleviate the Downstream of Gypsy load pocket in southern Louisiana; Ameren Illinois’ $159 million, 138-kV substation and 29-mile line in south central Illinois; and Michigan Electric Transmission Company’s $63 million plan to construct a new 138-kV substation and related facilities to serve a new industrial customer. The projects all rank among the MTEP 23 portfolio’s most expensive.

Trevor Armstrong, manager of MISO South’s expansion planning, said during another subregional planning meeting Thursday that staff are evaluating the nine projects’ effectiveness and will announce any alternative recommendations in early September. MISO is hosting its final round of subregional planning meetings at the same time and will present its final MTEP 23 project recommendations.

Some alternative project costs might be higher than the original projects. The RTO’s planners said larger project costs aren’t necessarily a dealbreaker if the project can satisfy additional benefits criteria. They stressed that a higher price tag doesn’t necessarily mean the project is a worse option.

The proposed $4.3 billion investment for 68 projects in MISO South exceeds the entire MTEP 22’s $4 billion cost.

Armstrong said MISO is introducing an economic screen in the region this year for the five most expensive projects. The screen replaces the normal market congestion planning study, currently on hold while staff chart its four long-range transmission planning (LRTP) portfolios.

“In order to do our due diligence on these very large projects, we’re putting a screener on them to see if they warrant further economic study … and get insights into congestion relief,” Armstrong said. The screen could designate some of the proposals as market efficiency projects, with their costs allocated regionally.

Different project designs will be pursued if they are a “better alternative in terms of cost and performance,” Armstrong said. “MISO’s focus isn’t just keeping the lights on. We also plan for other benefits.”

“The Amite South project area is a hotbed of load growth. There are industrial requests along the Mississippi River … and they’re related to electrification,” MISO’s Clayton Mayfield said, noting that much of the state’s load growth is in a load pocket. “We’ve studied in excess of 8 GW of load growth. It’s really the foot of the wave coming our way, and customers have aggressive timelines. They’re looking to come online in 2026 through 2028.”

Armstrong said he would consider a request from stakeholders to share the economic screen’s results before announcing any alternative projects.

Southern Renewable Energy Association’s Simon Mahan urged MISO to search for alternatives that will “future proof the system.” He reiterated that stakeholders weren’t privy to the grid operator’s new generation and retirement data, which could have helped them propose more suitable project alternatives. Stakeholders had until the end of May to submit project alternatives.

Mahan also asked whether staff’s extensive alternative project analysis will cause MISO to abandon the LRTP’s third portfolio, the first to consider planning needs in the southern region. Jeanna Furnish, MISO’s director of expansion planning, said staff remain committed to examining South system needs with the LRTP.

The RTO is also including an exploratory study to alleviate near-term congestion in MTEP 23. The study will review historical congestion data and recreate system conditions in production cost models to distinguish between persistent trouble spots and temporary ones.

Because the study is informational, MISO won’t recommend any transmission projects. Stakeholders had requested that the grid operator come up with smaller, congestion-relieving projects like its interregional targeted market efficiency projects with PJM and SPP. Some expressed disappointment that the study won’t result in a new class of projects. (See MISO Adding Near-term Congestion Study to MTEP.)

MISO has said it first needs to better understand the nature of its near-term congestion before proposing a new project type and potential cost allocation.

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Solarium Report Warns of E-ISAC Info Sharing Shortfalls

A new report by the successor organization to the Cyberspace Solarium Commission this week warned that utilities’ relationships with the Electricity Information Sharing and Analysis Center (E-ISAC) are not as strong as they could be.

The report was published by the CSC 2.0 Project, created after the bipartisan, congressionally sponsored commission issued its final report in 2020 to “support continued efforts to implement outstanding CSC recommendations” and continue to research additional cybersecurity issues discovered by the group. The goal of the report was to review Presidential Policy Directive 21, issued during the Obama administration, which established the federal government’s approach to critical infrastructure security and resilience.

In a letter to Congress last year, President Joe Biden indicated that he planned to “review and revise” PPD-21 to address emerging cybersecurity risks. CSC 2.0 conducted its own review of the directive — and Executive Order 13636, which focused on improving engagement between critical infrastructure stakeholders on cybersecurity and information sharing — to develop its own set of recommendations and review the current state of public-private sector security collaboration.

The review focused on the performance of sector risk management agencies (SRMAs) in supporting U.S. critical infrastructure. The 2021 National Defense Authorization Act established SRMAs for each critical infrastructure sector to support sector risk management, assess sector risk, manage sector coordination, facilitate information sharing between private and public sector entities, support incident management, and contribute to emergency preparedness efforts.

Citing their review of the Colonial Pipeline ransomware attack of 2021, when cybercriminals since linked to Russia hacked the company managing the flow of almost half the supply of gasoline and other fuel products to the U.S. East Coast and caused it to shut down its entire pipeline, the report’s authors sought to highlight “the broader challenge of inconsistent capabilities and performance across SRMAs.” They chose three examples for the discussion, including the Department of Energy, designated as the SRMA for the electricity sector.

While the report acknowledged DOE as “one of the best performing SRMAs” and called E-ISAC “one of the best” among its counterparts in other sectors, the authors observed that even such praise needs caveats. In this case, the E-ISAC’s relationship with NERC — which reports to FERC on reliability standards compliance and enforcement — creates an unintended chilling effect that discourages entities from turning over evidence that could implicate them in compliance violations.

“Our interviewees relayed that, because the E-ISAC is located within NERC, which in turn is subject to oversight by FERC, in-house counsels on occasion advise electricity companies not to share certain information with the ISAC for liability reasons,” the report said.

The commission said the utilities’ concerns constituted “an obstacle without an obvious solution,” because separating the E-ISAC from NERC would deprive it of financial resources and relationships that help with its services to the electric sector. It also did not provide any examples in which NERC or regional entities may have used information provided to E-ISAC in enforcement actions.

In an email to ERO Insider, a NERC spokesperson did not dispute the report’s claims but pointed out that the report itself notes that “the electricity sector has one of the best ISACs due to the robustness of its member-driven information sharing.” The spokesperson continued that NERC and the E-ISAC actively work to keep the organizations separate to allay the fears outlined in the CSC 2.0 report.

“NERC has a code of conduct in place that prohibits E-ISAC staff from sharing information about potential violations and compliance monitoring staff from seeking to obtain such information from the E-ISAC,” NERC said — a claim also noted in the report. “In addition, a firewall between networks and a separation of E-ISAC and NERC staff exists to further enhance safeguards. To date, this process has worked effectively and without fail since its inception.”

The spokesperson added that ongoing cyber and physical security threats to the grid make “the nexus between NERC and the E-ISAC … more valuable than ever before.”

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CAISO Tries to Shake up Its Interconnection Process

CAISO on Wednesday began a series of stakeholder meetings to deal with a surge of interconnection requests by focusing on generation and storage proposals more likely to meet California’s reliability needs and climate goals.

The ISO received a record 544 interconnection requests totaling nearly 350 GW during its Cluster 15 application window in April. That was five times the average number of requests it received in Clusters 8 to 13 during the years before 2021, the year application numbers began to soar.

The state needs to add 7,000 MW of clean-energy and storage resources to its grid each year for the next 10 years to meet its 100% clean energy goal by 2045 while maintaining grid reliability, CAISO and the California Public Utilities Commission estimate.

In a discussion paper published May 31, CAISO said that “given the rapid acceleration of clean energy development necessary to meet reliability and policy objectives and the unprecedented level of resource development activities reflected in interconnection requests to the ISO, this paper explores concepts for significant and transformative improvements to the ISO’s role in resource planning coordination, transmission planning, interconnection queuing and management, and power procurement.”

The paper kicked off Track 2 of CAISO’s 2023 Interconnection Process Enhancements stakeholder initiative. Wednesday’s meeting was held to present stakeholders with the ISO’s suggestions and elicit their initial feedback.

CAISO is breaking with its traditional stakeholder process by convening working groups to address the paper’s concepts and possibly come up with proposals of their own. Typically, the ISO presents a management straw proposal that is refined in a stakeholder process. But it used working groups last year to develop parts of its proposed extended day-ahead market for the Western Energy Imbalance Market.

“Given the complexities associated with this issue, the ISO is taking a different approach with this initiative and intends to initiate a robust stakeholder process to solicit feedback and suggestions to address the volume of new interconnection requests received in Cluster 15 and to encourage progress of existing projects in the queue,” it said.

CAISO is hoping to seek approval from its Board of Governors for Track 2 in December. The board approved Track 1, a timeline extension to study Cluster 14 requests, in May along with the ISO’s restructured transmission plan. (See CAISO Board Adopts Revamped Transmission Plan.)

The discussion paper proposed principles, problem statements and conceptual solutions. Its principles, or “process redesign parameters [and] objectives,” include prioritizing interconnections in “zones where transmission capacity exists or new transmission has been approved” and limiting the amount of interconnection studies to “reasonable capacity volumes that align with state resource planning.”

The paper’s first problem statement says: “The massive increase in interconnection requests seeking to meet the accelerated cadence of resource development now needed by the state on a sustained basis has overwhelmed critical planning and engineering resources across the industry. The current generator interconnection processes simply cannot efficiently accommodate all applicants and must be substantially redesigned to meet state policy and reliability needs.”

It then offers concepts for discussion in the working groups, including:

  • “a qualification process for determining projects studied for full capacity delivery status, and an alternative study path for all others;
  • a process where load-serving entities and other off-takers select projects for study as an indication of commercial interest in advance of the cluster studies; and
  • a process that selects the projects for study through an auction.”

Managing a large, unwieldly queue is another problem the paper targets. It offers concepts for queue management that include increasing deposit amounts and holding projects in the queue more accountable.

Stakeholders who spoke at Wednesday’s meeting asked for clarification of some aspects of the relatively novel process for CAISO.

“Just to clarify, these concepts that you introduce are not intended to limit the potential reforms that you’re open to exploring as it relates to managing interconnection requests,” said Ryan Millard of NextEra Energy Resources. “So, if we see something missing here, or see problems with some of these concepts, we’ll still be able to explore it in working groups. If we have some or reform ideas that don’t necessarily relate to just these concepts, there’s still opportunities to identify those concepts as part of the working groups. Is my understanding, correct?”

Robert Emmert, senior manager of interconnection resources at CAISO, said, “Yes, that’s correct. The main thing that we are looking for is that whatever proposals stakeholders bring forward … deal with the principles that we’re developing. That’s why the principles are so important.”

Some speakers took issue with CAISO asking for initial stakeholder comments by June 14, saying that was unrealistic.

Emmert said the comments the ISO is hoping for in that time frame are “at just a very high level on the various concepts that have been laid out.”

The working groups will begin meeting this month, CAISO said.

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DOE Loans Chief: Industry Ambition ‘Very Low’ to Meet Climate Challenges

Though new federal incentives have made the U.S. increasingly attractive for clean energy investments, the industry suffers from a lack of ambition, the head of the Department of Energy’s Loan Programs Office told the American Council on Renewable Energy’s (ACORE) Finance Forum on Wednesday.

Faced with the massive financial incentives in the Inflation Reduction Act and challenges in permitting, transmission and supply chains, “there really isn’t a confident solution set to solving [these problems],” said Loan Programs Director Jigar Shah. “There is a modeling solution set. … We can model the crap out of everybody else, but the level of ambition that we have in this industry around actually taking control of our future is very low.”

Zeroing in on interregional transmission, Shah pointed to the industry’s “affliction … around believing that if we actually present a fantastic idea with a really good report, that someone’s going to read it and fix the problem for us.”

“It’s not that people don’t recognize the value of interregional transmission; it’s not that people don’t recognize the value of the offshore wind grid that would be built from Boston to New Jersey,” he said. “Clearly, there’s somebody who’s not wanting to do it, and so the question is who doesn’t want to do it? Why do they not want to do it, and what can you offer them to get them to do it?

“That’s the game,” Shah said. “That’s what it’s like to be at the big-boy table.”

Shah’s challenge to the developers and investors at the ACORE event in New York comes as the IRA has made the U.S. a focus for clean energy investment. A new report from ACORE released Wednesday shows that companies are spending more on new projects and, in some cases, risking more to take them on.

Clean energy investments (ACORE) Content.jpgMore than half of the companies surveyed by ACORE are planning to up their clean energy investments by more than 10% this year. | ACORE

 

While investments in renewables dipped slightly in 2022, more than half of the companies surveyed for the ACORE report said they would be upping their spending in the sector by more than 10% this year. On risk, the results were more divided, with 37% saying they would be moderately increasing risk and 32% moderately decreasing risk, reflecting industry concerns with “headwinds,” such as inflation, supply chains and permitting.

But the survey found universal agreement that the IRA has made the U.S. a major magnet for clean energy investment. ACORE CEO Greg Wetstone noted that for the first time in the six years of the organization’s annual finance survey, “virtually everyone we asked said that the U.S. would be a more attractive place for renewable investment compared to other countries” over the next three years. 

Investors also ranked solar and storage at the top of a list of potential asset classes ripe for more investment. However, Wetstone cautioned, ”that doesn’t necessarily mean that’s where the investment is going to go. Storage has been near the top of this list for a long time, but the investment numbers have not been anywhere close to what we’re seeing in generation.”

Implementation Mode

The tension between industry optimism triggered by the IRA and ongoing economic and regulatory challenges was a theme throughout the opening panels at the event, and like Shah, other speakers called for the industry to focus on solutions.

Sandhya Ganapathy, CEO of EDP Renewables of North America, said her company could be committing more than 40% of its global capital to the U.S. renewables market.

“We now need to be in the implementation mode,” Ganapathy said. ”It’s a collective responsibility of the industry to actually sort of push ahead and see what are the challenges we have, make sure that we address those challenges and go ahead.”

“This is a time of optimism; this is a time of growth,” agreed Ingmar Ritzenhofen, chief financial officer of RWE Clean Energy, the U.S. arm of the German energy giant. “What’s crucial in this decisive moment is that we maintain the rational perspective on the things where we need solutions.

“We need to be clear [that] certain things don’t happen overnight. We cannot localize the entire supply chain overnight, even if we want to. … So, there needs to be a transition period; so, let’s have that conversation. I think that needs to be the mindset. How do we work through it? How do we resolve those things? And how do we deploy more?”

Project financing is a key part of the drive to increase deployment, and another point of risk and uncertainty for developers. The transferability provisions of the IRA will allow developers to sell their solar or wind tax credits to a third party, but the industry is waiting for the Internal Revenue Service to issue guidance on the provisions.

Ritzenhofen said transferability will provide a much-needed alternative to tax equity for financing clean energy projects. With renewable energy deployment expected to grow exponentially to meet the country’s decarbonization goals, tax equity alone will not be able to meet the demand.

“Transferability allows us to broaden that further,” he said. “And ultimately, I think we’ll see new structures. We’ll have some hybrid structures where you have a combination of the different [financing] elements and … that’s going to be helpful for all of us to deliver the growth that we’re all talking about.”

Hunter Armistead, CEO of Pattern Energy, also sees transferability as a spur for innovation in project financing.

“Transferability is going to effectively provide a floor or a ceiling value for monetizing your credits,” Armistead said. “I think the biggest issue is, we just need to get on with it.” The current U.S. renewables market is not large enough to “decarbonize the United States or take advantage of the IRA or implement the vision of what we all have to do,” he said.

Do Things Differently

The IRA creates immense opportunities, but it also means pressure on developers to pick up the law’s incentives and deliver, speakers at the Finance Forum agreed.

Shah said some are not taking full advantage of the law’s tax credits, instead writing off certain market segments or demographics, which in turn could hamper the drive for power sector decarbonization.

Less than 4% of U.S. single-family homes have rooftop solar, versus 30% in Australia, he said. Residential and small commercial are “gigawatts that we’ve somehow magically written off … . Are you really telling me that actually putting solar on rooftops is harder than transmission?”

The IRA also has “an enormous amount of incentives around working with tribes,” Shah said. Yet most developers are not pursuing such projects.

“They have the best land in the country for renewable development, the best land that’s not been picked over, that people haven’t secured. … They also have a special ability to jump interconnection queues. … But guess who’s not working with them? This industry.

“There was a notion for a long time that this industry was special, that everything it did was amazing … but that’s no longer the case,” Shah said. “So, I want to make sure that we’re crystal clear that as we move through this energy transition or energy transformation, we’re going to have to do things differently.”

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Wash. Cap-and-Trade Auction Prices Break Soft Cap

Washington’s second cap-and-trade auction netted the state more than $557 million in revenue after bidders bought all 11.035 million carbon allowances on offer last week, preliminary figures show.

The May 31 auction administered by the state’s Department of Ecology cleared 8.585 million vintage 2023 allowances at a settlement price of $56.10, compared with $48.50 for first auction in February. Both auctions had a floor price of $22.20.

Prices for Washington carbon allowances continue to outpace those in the Western Climate Initiative program that includes California and Quebec, where an allowance currently trades for about $30. In both programs, a single allowance entitles its holder to emit one ton of greenhouse gasses.

“Today’s results from Washington’s second cap-and-invest auction — most notably selling 100% of allowances — continue to signal strong demand for allowances and confidence in the program, bringing significant revenue for the state to reinvest in Washington communities,” Environmental Defense Fund (EDF) analyst Caroline Jones said in a blog post.

The clearing price from last week’s auction exceeded the $51.90 soft cap that triggers use of the cap-and-trade program’s Allowance Price Containment Reserve (APCR), a mechanism designed to rein in the market when allowance prices reach a level considered overly burdensome for emitters.

As a result, the state will hold a special secondary APCR auction on Aug. 9, which carbon market analysis firm cCarbon said could release as many as 9 million additional allowances.   

“Critically, these allowances available at the reserve auction are still a part of the overall allowance budget set by Ecology to keep Washington on track to meet its climate targets,” Jones said. “Even though triggering the APCR means that some more allowances are made available at auction, these allowances were budgeted out ahead of time for this exact purpose and do not put Washington over its planned emissions budget.”

The Ecology Department will hold a call June 9 to discuss details of the APCR auction.

Raised Eyebrows

Last week’s auction also included an advance sale of 2.45 million vintage 2026 allowances, which settled at $31.12. The price differential between the two vintages “raises eyebrows,” cCarbon said.

“The price discrepancy between the current and advanced auction is puzzling since both the V2026 and current allowances can be used for compliance at the end of the first compliance period,” cCarbon said. The company speculated that compliance entities — those that need to cover their physical emissions — “are scrambling to purchase allowances and build an internal bank, fearing a substantial rise in the price” in future auctions.

Fifty-four companies, utilities and public institutions bid into last week’s auction, down slightly from 56 participants in the previous one, according to the Ecology Department’s auction summary, which does not disclose the identities of successful bidders.

Compliance entities accounted for the lion’s share of both vintage 2023 (89.88%) and 2026 (73.55%) purchases, with financial entities making up the balance, the summary showed.

This was the state’s second quarterly auction since the cap-and-trade law went into effect in January.  

The first auction on Feb. 28 sold all 6,185,222 allowances at $48.50 each to raise almost $300 million for the state’s coffers. In April, the state legislature divided that $300 million into 188 appropriations for solar panel farms, climate planning, pumped storage projects, developing a hydrogen industry, installing solar panels on buildings, constructing infrastructure for electric vehicles, developing hybrids fuel/electric ferries, and tackling other projects.

Revenue from the second auction will be appropriated in the state legislature’s spring 2024 session, which will allocate money from auctions in August and November, plus February 2024. In January, the Ecology Department estimated that the auctions would raise $484 million for fiscal 2023 (July 1, 2023, to June 30, 2024,) and $957 million in fiscal 2024.

The state is on its way to exceed its preliminary estimates.

The Ecology Department will issue a report on Jun. 28 confirming the final figures for the most recent auction.

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Texas Appeals Court Reverses Another PUC Order

A Texas appeals court last week reversed a Public Utility Commission’s scarcity-pricing order and remanded it back to the PUC for further proceedings.

The Texas 3rd Court of Appeals ruled June 1 that the commission violated the state’s Administrative Procedure Act’s (APA) rulemaking provisions when it approved an ERCOT protocol change related to pricing during certain extreme events. It also agreed with the lawsuit’s appellants, RWE Renewables Americas and Hereford Wind, that the order constitutes a “competition rule” and that the PUC exceeded its statutory authority with its approval (No. 03-21-00356-CV.)

The PUC declined to comment on what action it would take, saying agency policy is not to comment on pending litigation.

Attorney Katie Coleman, who represents market participants before the PUC, tweeted the ruling “could have implications for other major [revision requests] that were adopted without following the APA.”

At issue is a nodal protocol revision request (NPRR 1081) that the commission approved in July 2021, following its endorsement by the ERCOT board. The appeals court said the commission did not follow the APA in adopting the rule, as required by a legislative change passed during that year’s session.

“From our review, we conclude the commission complied with few, if any, of the requirements of [the] APA,” the court wrote. “The myriad ways in which the commission failed to comply with mandatory APA requirements for adopting or amending a rule cannot be characterized as ‘technical defect[s]’ … its actions in approving NPRR 1081 do not qualify as ‘substantial compliance’ with the APA’s mandatory rulemaking procedures.”

The NPRR modifies the real-time on-line reliability deployment price adder’s calculation so that, when combined with system lambda and the real-time on-line reserve price adder, it is equal to the value of lost load when ERCOT directs firm load shed during a level 3 energy emergency alert. The NPRR results in real-time energy prices clearing at the high system-wide offer cap, which was $9,000/MWh when it was adopted. (The PUC later reduced the cap to $5,000/MWh.)

ERCOT’s Independent Market Monitor filed the proposed change as a “more permanent solution” modifying the reliability deployment’s adder. The PUC told the appeals court that because not all demand can be served with available generation during firm load shed, “wholesale market prices should reflect that extreme scarcity and rise to the high systemwide offer cap.”

RWE and Hereford Wind filed a direct appeal challenging the order’s validity the same month it was issued by the PUC. They asserted the commission does not have the statutory authority when ordering load shed under EEA3 “to replace the price of electricity being set by the market with an inflated, fixed price set by the government.”

ERCOT and the PUC came under heat from the IMM and market for keeping prices at the systemwide cap while bringing the grid back from a near-collapse during the February 2021 winter storm’s frigid temperatures. (See “Monitor: $16B ERCOT Overcharge,” ERCOT Board Cuts Ties with Magness.)

The commission argued that its order is not a “competition rule,” which the Texas Utilities Code allows to be challenged. However, the court found that NPRR 1081 falls within the APA’s definition of “rule” — “a state agency statement of general applicability” that “implements, interprets, or prescribes law or policy” — and within the term “competition rule,” allowing it to be challenged through the direct-appeal process.

Pointing to its March ruling reversing the PUC’s orders to keep prices at the $9,000/MWh cap during Winter Storm Uri, the court said it was bound by the precedent and held that NPRR1081 “exceeds the commission’s statutory authority and is therefore an invalid rule.” (See Texas Court Reverses PUC’s Uri Market Orders.)

The appeals court also rejected the PUC’s argument that the revision request constitutes a rule because ERCOT’s stakeholder process “substantially complied with the APA’s requirements for agency rulemaking.” The court said the commission failed to meet the APA’s requirements, which include: (1) notice, (2) public participation, and (3) contents of the agency order.

“Because we conclude that the commission has failed to demonstrate that it substantially complied with the APA rulemaking procedures, we hold that NPRR 1081 is, for that separate reason, an invalid rule,” the court said.

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Jackson Named Texas PUC’s Interim Chair

Texas Gov. Greg Abbott on Wednesday appointed the Public Utility Commission’s newest member, Kathleen Jackson, interim chair. She will lead the commission until a permanent chair is named, Abbott said.

Jackson was appointed to the commission in August and only confirmed by the Texas Senate in May. She replaces Peter Lake, who stepped down last week and will leave July 1. (See Texas PUC’s Lake Steps Down as Chair.)

“I’m honored and humbled by Governor Abbott’s trust and confidence in me to lead the Public Utility Commission at this very important time for the agency and for Texas,” Jackson said in a statement.

The commission’s other four members were all appointed in 2021. They replaced the previous commissioners, who all resigned after the February 2021 deadly winter storm.

Jackson has led the PUC’s grid-related energy efficiency efforts. She previously served as a board member of the Texas Water Development Board from 2014 to 2022.

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Debt Deal Weakens Odds for Increased FERC Siting Authority, Glick Tells EBA

WASHINGTON — Giving FERC a larger role in transmission siting would aid decarbonization and grid reliability, but it is unclear whether Congress will have the appetite for that any time soon, former FERC Chair Richard Glick told the Energy Bar Association’s Electricity Steering Committee on Tuesday.

Permitting “reform” has been a hot topic on Capitol Hill this session, and Congress’ debt ceiling agreement included provisions to shorten reviews under the National Environmental Policy Act. (See Lawmakers, White House Promise More Work on Permitting After Debt Deal.)

But the changes “weakened the legislative momentum,” making it much more difficult to find a legislative vehicle for giving FERC increased powers this year, said Glick, a former Senate aide who opened a consulting shop after his term at FERC expired. (See Former FERC Chair Richard Glick Sets up Consulting Shop.)

He noted that the Infrastructure Investment and Jobs Act gave FERC authority to overrule state denials of transmission lines designated by the Department of Energy as National Interest Electricity Transmission Corridors. (See FERC Backstop Siting Proposal Runs into Opposition from States.)

“I think there’s still going to be issues with regard to transmission siting [for] certain lines,” Glick said. “Certainly, it’s not going to happen as quickly as it might have happened, because there’s no one-stop-shopping, so to speak, at FERC.”

The current system of leaving most siting decisions up to states might have made sense for many decades, he said. But with major transmission lines needed to bring renewables across multiple states, or to increase minimum transfer capability among regions to deal with increasingly volatile weather, the current system needs to change, he said.

Rights of First Refusal

Glick and other speakers at the EBA meeting also weighed in on FERC’s controversial proposal to reinstate a federal right of first refusal (ROFR) on transmission construction for incumbent utilities that work with a partner. The change was included in the commission’s April 2022 Notice of Proposed Rulemaking on transmission planning, which Glick supported (RM21-17). (See ANALYSIS: FERC Giving up on Transmission Competition?)

FERC Order 1000 in 2011 eliminated the federal ROFR on regional transmission projects. Glick said he supported reinstating the ROFR because utilities responded to Order 1000 by reducing spending on bigger regional projects in favor of local transmission that remained exempt from competition.

“The answer that I first thought when I was at FERC was why not just subject all of them to competition?” Glick recounted. “And staff convinced me that wasn’t a workable solution.”

Glick acknowledged it was hard to police local transmission projects that often fall under formula rates and have varying levels of state oversight. FERC Commissioner Mark Christie has suggested getting rid of formula rates when states lack the ability to adequately oversee such local lines.

“The states that don’t have that [oversight] authority would quickly act to get that authority because getting rid of formula rates would be complex — and that’s an understatement,” Glick said.

Some states reacted to Order 1000 by imposing ROFRs on any transmission line that goes through their territory. LS Power Development Senior Vice President Sharon Segner said it is an open legal question whether such laws “invade” FERC’s exclusive jurisdiction over interstate transmission.

A group of MISO transmission customers filed a complaint last year asking FERC to effectively override such state laws (EL22-78). (See Consumer Groups File FERC Complaint Against MISO.)

“They interfere with interstate commerce,” Segner said. “And we’re talking about states interfering with regional projects that are paid for by citizens outside of the state, yet you have state protectionist laws coming into play.”

WIRES Executive Director Larry Gasteiger holds the opposite opinion on ROFRs, contending that FERC’s NOPR would get more interregional transmission built.

“Our general approach to ROFR and to competitive transmission issues comes from the standpoint of … how is it impacting transmission development and the ability to get transmission developed in a timely basis?” Gasteiger said.

More than a decade after FERC introduced competition to transmission, the policy does not seem to be working and is producing results that go against other transmission policies that FERC and others support, he said. Competition makes it more difficult to build the huge amount of transmission that is forecasted as needed to get the grid to net zero emissions, he added.

“It’s taken us over 100 years to get to where we are now,” Gasteiger said. “So, you’re talking about doubling or tripling that amount of transmission in a third of the time.”

Gasteiger argued that it made sense to keep local projects away from competition because often they are needed quickly and are often fairly small — such as the need to raise a substation to avoid floodwaters.

Segner said LS Power does not want to compete with incumbent utilities on such projects. But she said local transmission lines of 100 kV or above should be open to competition.

Making that many lines open to competition would lead to even more states passing their own ROFR laws, said Perkins Coie Partner Jane Rueger. But major interregional lines could benefit from competitive processes, she said.

Major transmission lines that cross states are often built by one company, but those efforts could run into a state ROFR law that blocks them from getting built.

“You might see more pressure to have a federal solution, so again, that everything is rowing in the same direction,” Rueger said.

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CALSTART Brings Electric Vehicles to Hazy Capitol Hill

WASHINGTON — With hazy skies in the nation’s capital produced by Canadian wildfires, clean transportation nonprofit CALSTART brought four commercial electric vehicles to the foot of Capitol Hill on Wednesday for a press event with some of the industry’s supporters in Congress.

CALSTART works with governments and industry to develop clean and efficient transportation solutions. Its members include Audi, Ford, General Motors and Volvo.

Sen. Martin Heinrich (D-N.M.) said the assembled vehicles showed that the industry had made major strides and was ready for real-world use. The vehicles included a Nikola semitruck, a Workhorse box delivery truck, a Monarch Tractor and an electric ice cream truck.

“They just do the job better, and it couldn’t come at a more important time,” Heinrich said, referencing the haze and low air quality from the wildfires. “Those of us in the West are familiar with this. We’ve lived with it for 15 to 20 years now. This is the result of 100 years of burning fossil fuels. And it means we’re now burning our forests because the planet is a warmer place.”

Decarbonizing transportation is key to limiting further impacts from global warming, and while commercial vehicles represent just 5% of the overall fleet, they are a quarter of the sector’s emissions, Heinrich said.

“We won’t be able to tackle the challenge without setting the most ambitious standards to lead transportation emissions and move the market through policy,” Sen. Alex Padilla (D-Calif.) said.

Padilla grew up in Los Angeles, which historically had such bad air quality that he would sometimes be sent home from school because of it. As a tour bus’ diesel engine rumbled past, he described riding to and from school in yellow buses with the same engines and recalled their smell.

“You can imagine the health issues and the learning issues that that would lead to,” Padilla said. “We refuse to accept that as normal and will not impose that same reality, the same environmental harm and health risk on future generations. That’s why California is proud to have set some ambitious goals when it comes to tackling emissions. No state has fought harder to transition to electric vehicles than California.”

The state wants to get to 100% emissions-free medium- and heavy-duty trucks by 2045, he added.

CALSTART worked with the California Air Resources Board to get those first-in-the-nation regulations passed, which have now been adopted by another nine states, organization President John Boesel said.

“What’s really important now is that the U.S. EPA is considering regulations in this space,” Boesel said. “And they have a draft regulation that’s out there for comment, and industry and others are providing input.”

The industry already offers more than 100 types of zero-emission commercial vehicles, especially in states that offer their own incentives on top of those from the Inflation Reduction Act, he added.

“Those vehicles are cost effective today,” Boesel said. “They have much lower operating costs than their diesel equivalent. And that includes both the cost of electricity and maintenance costs. And I think as we see battery technology improve, that business case is only going to get better and better.”

Innovation to limit carbon emissions used to be something to look forward to, but it is here now, Rep. Paul Tonko (D-N.Y.) said.

“Trucks and buses that are the backbone of our current economy, that provide vital services to our communities, can be run in a clean and effective manner,” Tonko said. “These vehicles in the past have disproportionately contributed to air pollution.”

The Biden administration was also represented at the event through the Joint Office of Energy and Transportation, in which the respective departments coordinate their efforts on EVs. Executive Director Gabe Klein said he came from the business world, where he set up an organic food truck company with 16 EVs in the 2000s, when there was nowhere to charge them, not even in D.C.

“The world has changed dramatically, and now these vehicles are mainstream,” Klein said. “And our job at the joint office … is to bring together DOT, DOE and all the resources within the federal government to help to get this job done.”

President Joe Biden set a goal for the U.S. to have 500,000 EV chargers by 2030. The country added 21,000 chargers last year, up from an average of about 5,000 a year, and now the country has about 143,000 in total.

Nikola is building semitrucks out of its factory in Arizona that are aimed at dealing with regional cargo transportation needs with a range of 330 miles, said senior manager for state and local affairs William Higgins. The trucks are already being used at Los Angeles International Airport and the nearby ports of Long Beach and Los Angeles.

“Nikola believes that the electrification of the medium- and heavy-duty sector is critical to reducing carbon emissions given that, on average, one zero-emission truck avoids 106 metric tons of CO2 annually,” Higgins said.

The firm is also to release a hydrogen fuel cell truck this year, with a range of 500 miles that can be used for longer-distance cargo, he added. Nikola also early this year launched its own hydrogen fuel brand, called HYLA, to support the continued evolution of clean heavy trucking.

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RTOs Report Diminished Solar Output, Loads as Wildfire Smoke Passes

VALLEY FORGE, Pa. — RTOs in the Northeast are experiencing diminished solar output and lower-than-expected loads as smoke from wildfires in Canada passes over the region.

“In recent days, smoke from wildfires in Canada has traveled to New England, significantly lowering production from solar resources in the region compared to what ISO New England would expect absent the smoke,” ISO-NE said in a statement Thursday.

Most solar generation in ISO-NE is behind-the-meter of retail loads, leading the smoke’s impact to manifest as increased energy demand in the region. Lower temperature from the smoke has had a counterbalancing effect, reducing energy consumption from air conditioning.

“These two factors — decreased production from solar resources and decreased consumer demand due to lower temperatures — [have] made forecasting demand for grid electricity challenging,” ISO-NE statement said. “In forecasting real-time and future demand for electricity, ISO New England relies on historical data from similar days, adjusting for changing system conditions. Because these smoky conditions are unprecedented in the region, there is little, if any, historical information to rely on, creating further complications in generating accurate forecasts.”

PJM spokesperson Dan Lockwood said the smoke has been having a similar effect as it passes over the mid-Atlantic region as well.

“Smoky conditions throughout the RTO this week have caused a reduction in visibility, reducing solar and keeping temperatures several degrees lower than usual. It is difficult to single out the effect of smoke alone, especially when PJM has not seen an expansive plume like this. However, the cooler temperatures and decreased visibility are similar to what we experienced during the period of July 19-21, 2021, when the RTO was covered with smoke from wildfires in the western U.S. PJM is closely watching the smoke maps and taking these factors into consideration as it forecasts load for its zones,” Lockwood said in an email.

NYISO reported total peak solar output over June 6 and 7 was 1,466 MW lower than forecast, including both utility-scale and behind-the-meter resources.

“Based on data compiled by NYISO forecasters, wildfire smoke cover significantly reduced incoming solar irradiance across the state on June 6 and 7. … While the haze caused by the ongoing Canadian wildfires had a significant impact on solar energy production, the two-day total peak production still reached 4,405 MW. The NYISO will continue to monitor this situation as it develops,” spokesperson Andrew Gregory said.

Jeff Weiss, executive chair of Distributed Sun, said one of their rooftop units in NYISO peaked at 63% of its nameplate capacity Thursday. A few weeks away from the summer solstice, he said solar should be operating at “full blast” this time of year, reaching full nameplate even at 75% solar irradiance due to the oversized inverters installed. While the lower output likely reflects the impact of the smoke, Weiss said upstate New York was expected to have reduced solar output to some degree due to wind, cloud cover and similar atmospheric conditions.

“While this extra particulate matter is certainly blocking out the sun, a detailed atmospheric analysis is required to accurately measure the specific impact of multiple factors,” he said.

A September 2020 analysis by the Energy Information Administration found that average solar output declined by 30% when smoke from wildfires covered California over the first two weeks of the month compared to the July average. Despite 659 MW in new utility-scale solar installations in the region, a 5.3% increase and an 11% growth in distributed solar, overall generation from solar was 13.4% lower for those weeks than in the corresponding period in 2019.

“In July 2020, daily solar-powered electricity generation, which includes generation from solar photovoltaic and solar thermal electric generators, ranged from 104 to 119 GWh, averaging 113 GWh for the entire month. Daily solar-powered generation began declining as large wildfires broke out in mid-August, reaching a low of 68 GWh on Aug. 22 before returning to approximately 100 GWh by the end of the month. Solar-powered generation began declining again as wildfire activity rose in September, falling as low as 50 GWh on Sept. 11 as PM2.5 smoke pollution increased,” EIA wrote.