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September 6, 2024

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Berkeley Seeks Rehearing of Gas Ban Reversal

Attorneys for the city of Berkeley, Calif., have asked the 9th Circuit Court of Appeals to rehear a case overturning the city’s effective ban on natural gas appliances in new buildings, a first-of-its-kind rule that led to two dozen other local governments adopting similar restrictions.

On April 17, a three-judge panel reversed a district court’s ruling and agreed with the California Restaurant Association that the city’s gas ban is preempted by the federal Energy Policy and Conservation Act (EPCA), which gives the U.S. Department of Energy authority to set energy conservation standards for appliances such as furnaces and water heaters.

The ruling called into question building decarbonization efforts in the 9th Circuit’s nine Western states and raised the possibility of the ruling having a national effect. (See Impact of Berkeley Gas Ruling Debated.)

On May 31, Berkeley’s city attorney and outside law firms asked the 9th Circuit to rehear the case before an 11-judge en banc panel.

“The panel’s invalidation of the City of Berkeley’s prohibition on natural gas infrastructure in newly constructed buildings is based upon fundamental legal errors that threaten vital health, safety, and environmental regulations throughout the Circuit,” the lawyers wrote in their rehearing petition.

The decision could “disable state or local regulations” that limit the use of gas appliances, they said.

“That ruling is seriously wrong and highly consequential,” the petition says. “Indeed, the [legal] regime the panel discerned in this unheralded 35-year-old provision [of the EPCA] is in every way extraordinary. It makes the federal government’s establishment of an efficiency standard for an energy-consuming product the trigger for automatic displacement — but not replacement — of vast swaths of health and safety protections that serve purposes wholly unrelated to conserving energy.”

Berkeley adopted its ordinance prohibiting the installation of natural gas piping in new buildings in 2019, making it the first U.S. jurisdiction to effectively ban new natural gas use. Since then, more than 70 jurisdictions have required or incentivized all-electric new buildings, according to the Building Decarbonization Coalition, with about 25 following Berkeley’s approach. Most are in California.

The city said its ordinance was meant to reduce the environmental and health hazards of using natural gas for cooking and heating.

The California Restaurant Association sued, saying the EPCA preempted the ordinance.

A federal judge dismissed the case, saying the federal law preempted only ordinances that facially or directly regulate covered appliances.

A three-judge panel of the 9th Circuit disagreed, saying “such limits do not appear in EPCA’s text.”

“By its plain text and structure, EPCA’s pre-emption provision encompasses building codes that regulate natural gas use by covered products,” the panel said. “And by preventing such appliances from using natural gas, the new Berkeley building code does exactly that.”

In their rehearing petition, Berkeley’s lawyers argued the three-judge panel had wrongly interpreted the law and 9th Circuit precedent, arriving at a conclusion that undermined cities’ ability to enact health-and-safety ordinances.

“The en banc court should disavow this vast and unauthorized preemption regime and the decision’s federalism-denying interpretive approach,” they wrote. “The decision disrupts the coherent and effective administration of an important federal statute, overrides many existing measures similar to Berkeley’s, and improperly denies States and municipalities authority to address matters at the core of traditional state authority.”

The restaurant association and other interested parties next have an opportunity to respond.

States and cities that filed amicus briefs supporting Berkeley previously included California, Maryland, New Jersey, New Mexico, New York, Oregon, Washington, Massachusetts, Washington, D.C. and New York City. They, too, can weigh in on the rehearing request.

The rehearing petition and responses will be sent to all of the 9th Circuit’s 28 active judges, who will vote on whether to grant the request.

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Lawmakers, White House Promise More Work on Permitting After Debt Deal

Even before the Senate on Thursday passed the Fiscal Responsibility Act (H.R. 3746) — the bipartisan deal to lift the U.S. debt ceiling that also included provisions related to energy infrastructure permitting — lawmakers on both sides of the aisle were talking about the work still ahead to truly streamline and accelerate the process and construction.

Signed by President Joe Biden on Saturday, the new law sets time and page limits on environmental reviews under the National Environmental Policy Act (NEPA) and calls for designation of a single federal agency to lead reviews and issue the final environmental evaluation, provisions that already had general bipartisan support. It also expands the use of “categorical exclusions” exempting projects from NEPA evaluations but does little to advance the buildout of vitally needed interregional transmission, a top Democratic and industry priority. (See Debt Ceiling Bill Provides ‘Mini-deal’ on Permitting.)

“As it sits right now, I feel like we just lost two years,” Rep. Sean Casten (D-Ill.), co-chair of the House Sustainable Energy and Environment Coalition, told E&E News on Wednesday.

While crediting Biden for getting the deal done and averting a potentially disastrous U.S. default, Casten said White House negotiators “totally messed up the transmission piece, and they didn’t deal with us on the level about what they had. And so, we didn’t know how bad they botched it until after we saw the text.”

Casten was referring to the FRA’s call for a study on the need for transmission to support interregional transfers of power for grid resilience and reliability, which NERC and FERC now have two and a half years to complete.

“There is absolutely no good reason why anybody needs to spend two years studying a problem that has been asked and answered 15 times,” Casten told E&E after his attempt to amend the bill was killed in the House Rules Committee.

Casten was one of several lawmakers quoted in post-deal analyses of the next moves, if any, on “permitting reform,” as the issue is commonly referred to.

On the Republican side, Sen. Kevin Cramer (R-N.D.) saw the permitting issue going “one of two ways.”

“One way might be to check the box — ‘We did this’ — and then never think about it again,” Cramer said, according to The Hill. “The other possibility would be that we create a little bit of momentum and say, ‘OK, now let’s get serious and drill down a little bit.’ I hope it’s the latter.”

Similarly, Sen. Shelley Moore Capito (R-W.Va.), ranking member of the Senate Environment and Public Works (EPW) Committee, described the FRA as a “jumping point to start off again in our bipartisan talks,” The Hill reported. Her particular target is “judicial reform”: cutting down the six-year time frame now allowed for legal challenges to NEPA reviews, which the FRA did not include.

Industry trade groups also urged Congress to move ahead with more comprehensive initiatives on permitting and transmission.

Christina Hayes, executive director of Americans for a Clean Energy Grid, said her organization “believes that setting timelines for federal environmental reviews is a helpful first step but is only the beginning. While we do not believe that an interregional transmission study is needed, we hope that it can be completed quickly, building on efforts already underway at FERC, to ensure buildout of the transmission we need to keep the lights on.”

The American Clean Power Association seconded the motion. “ACP is appreciative of the steps taken to include much-needed reforms to improve efficiency of the permitting process for clean energy projects,” said CEO Jason Grumet. But “it’s critical that Congress build upon these initial steps and tackle comprehensive, meaningful reform to improve our nation’s clean power transmission capabilities and bring about the clean energy future America needs.”

BIG WIRES Nixed 

A drive for bipartisan permitting legislation had been a key focus in both the House and Senate in May, before the tense negotiations on the debt ceiling overwhelmed work on other issues in Congress and at the White House.

Biden issued a fact sheet outlining his permitting priorities, and Sen. Joe Manchin (D-W.Va.), chair of the Senate Energy and Natural Resources (ENR) Committee, declared his intention to have bipartisan legislation hammered out before Congress begins its August recess. (See Podesta Lays out Biden’s Priorities for ‘Permitting Reform’.)

House Republicans’ original debt ceiling package, the Limit, Save, Grow Act (H.R. 2811), included a previously passed energy bill, the Lower Energy Costs Act (H.R. 1), with provisions that would accelerate permitting of fossil fuel projects, but without any mention of clean energy or transmission.

Capito and ENR Ranking Member Sen. John Barrasso (R-Wyo.) also introduced bills primarily focused on accelerating the leasing and permitting of oil and gas projects and slashing the window for NEPA legal challenges from six years to 60 days.

On the Democratic side, Manchin and EPW Chair Tom Carper (D-Del.) each introduced bills that called for two-year time limits on NEPA reviews but also contained provisions on transmission. Manchin’s bill would cement FERC’s authority to permit transmission deemed in the national interest. Carper’s would authorize millions in federal funding to support broad community engagement in permitting processes, as well as training programs to ensure federal agencies are able to hire staff with the needed expertise. (See Carper Throws Progressive Bill into Senate Permitting Debate.)

Sen. John Hickenlooper (D-Col.) and Rep. Scott Peters (D-Calif.) added to the ongoing debate with their Building Integrated Grids With Inter-Regional Energy Supply (BIG WIRES) Act, which would require transmission planning regions, as defined by FERC, to be able to transfer at least 30% of their peak demand between each other. The bill calls on regions to pursue a range of options to achieve this target, from building new transmission and upgrading existing lines to cutting demand through energy efficiency.

BIG WIRES was on the table as part of the debt ceiling negotiations, according to The Washington Post, but was nixed by Reps. Cathy McMorris Rodgers (R-Wash.) and Jeff Duncan (R-S.C.), arguing that Republicans needed more time to review the bill. McMorris Rodgers is chair of the House Energy and Commerce Committee, while Duncan leads the committee’s Energy, Climate and Grid Security Subcommittee.

The law’s much-criticized transmission study was the result.

Without directly mentioning his bill, Hickenlooper expressed disappointment with the FRA’s permitting provisions. “I don’t feel that we got what I’d hoped we would get, and I feel like we gave up a little more than I would’ve wanted to give up,” he told E&E.

Green Pivot Ahead?

The FRA’s provisions calling for expedited completion of the Mountain Valley Pipeline (MVP) were another flashpoint during Senate debate on the bill Thursday. The 303-mile, 94% complete natural gas pipeline has been a top priority for Manchin, who until now had been unsuccessful in getting it into must-pass legislation.

Sen. Tim Kaine’s (D-Va.) amendment cutting the project out of the bill was voted down, with some Democrats saying they agreed with Kaine but did not want to threaten quick passage of the FRA, The Post reported.

A key question now is whether, with completion of the MVP finally secured, Manchin will still push for a more comprehensive bipartisan permitting bill. As ENR chair, he has a formidable track record as a gatekeeper on issues and nominations he does not support, and he is facing a potentially tough re-election campaign against West Virginia Gov. Jim Justice (R) in 2024.

White House press secretary Karine Jean-Pierre on Friday included permitting in a list of issues Biden still hopes to tackle, but the president did not mention it in his prime-time address to the nation that evening.

Administration officials speaking at The Economist’s Sustainability Week US conference in D.C. on Wednesday stressed that work on permitting and transmission will continue.

“The job [on these issues] is definitively not done,” said Andrew Mayock, federal chief sustainability officer. “Permitting remains a really important piece of the agenda … and I think it’s safe to say that there is more to do, and the White House will continue to push on that until we get where we need [to be].”

Answering a question about the FRA-mandated transmission study, Gene Rodrigues, the Department of Energy’s assistant secretary for electricity, said the study could have a positive impact by bringing “more people to the table to start thinking about what grid modernization means, and it’s not changing out just poles and wires. It’s about everything to do with how we plan, operate and invest in our system.”

But, he said, “does that mean … everything else stops, and then we wait for that [study] to be done? Absolutely not. … Let’s bring more people into the conversation, but let’s continue moving forward with what needs to be done to support the reliability, resilience, affordability and security of America’s grid.”

Industry analysts ClearView Energy Partners even see a possible “green pivot” now that the debt deal is done and “the White House may not worry as much about alienating fossil-friendly Democrats or the GOP. … The White House may also seek to balance its support for MVP with new strictures on fossil fuels.”

ClearView pointed to a Friday notice from the Interior Department withdrawing 336,404 acres surrounding Chaco Culture National Historical Park in New Mexico from potential mineral leasing and mining. The park marks the site of a once-thriving center of Pueblo culture, which existed between the 9th and 12th centuries.

‘Reasonably Foreseeable’

The implementation of the FRA and its likely impacts on permitting and clean energy deployment in general also will likely become a matter of close political scrutiny in the months ahead, especially for GOP lawmakers.

While the bill calls for slashing time for NEPA reviews, from more than four years to two years for a full environmental impact study, hitting those deadlines may prove challenging.

The permitting provisions of the law are largely based on the Building U.S. Infrastructure through Limited Delays & Efficient Reviews (BUILDER) Act, which Rep. Garret Graves (R-La.) first introduced in 2021.

A chief GOP negotiator on the debt deal, Graves has said the new law would cut not only the time, but also the scope of NEPA reviews to “reasonably foreseeable environmental impacts,” language taken from the BUILDER Act.

Speaking at a press conference announcing the deal May 28, Graves said, “NEPA has grown to just study all these things that don’t have anything to do with the environment, which I would argue … has worked against the protection of the environment. So, we’re trying to refocus the scope back on that, on the environmental impacts, and making sure we get the best environmental outcomes.”

However, while the FRA incorporates many provisions of the BUILDER Act, it does not include that bill’s definition of “reasonably foreseeable environmental impact.” As defined in the U.S. Code, it is one that is “sufficiently likely to occur such that a person of ordinary prudence would take it into account in reaching a decision.” Whether this definition is broad enough to include climate change or public health impacts will likely be a matter of ongoing debate and litigation.

The impact of the FRA’s page limits also is uncertain. The law does limit each EIS to 150 pages, or 300 for “extraordinarily complex” projects, but it places no limits on appendices for such reports, which can run into hundreds or even thousands of pages. For example, the Bureau of Ocean Energy Management’s recently released final EIS for the Ocean Wind 1 offshore wind project comes in four volumes, with 570 pages for the EIS itself (Vol. 1), plus 1,760 pages of appendices (Vol. 2-4). (See BOEM: Major Visual, Scientific Impacts from NJ’s 1st OSW Project.)

Another question raised at The Economist conference was whether the FRA’s clawback of $20 billion in Inflation Reduction Act funding for the Internal Revenue Service might affect the agency’s ability to deliver the needed guidance for all the IRA’s clean energy tax credits.

Heather Boushey, a member of the White House Council of Economic Advisers, cautioned that the clawback could send “a signal that that’s maybe a cookie jar we can keep pulling from.”

“It is clear in the short term — at least we are hearing from our Treasury colleagues — that they will be able to do their work, even with these cuts,” Boushey said. “But I do think that we, as people who are concerned about climate, given how much of this is being done through the IRS, we need to be making sure that [Treasury] is on our checklist of agencies that we are watching very closely.”

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MISO Wants Tougher Obligations on Queue Entry and Exit

CARMEL, Ind. — Faced with an exponential rise in interconnection requests, MISO last week announced that it is aiming to make its queue a more exclusive club through new rules.

The grid operator said it needs stricter requirements for developers to enter and exit the generator interconnection queue so it can make its studies more manageable.

“We need to govern the rules for exit and entry. We believe that will improve our queue,” MISO’s Andy Witmeier said at the Planning Advisory Committee’s meeting Wednesday. He said that if MISO imposes more requirements on land ownership, restricts the conditions for penalty-free withdrawals and increases some fees, it will shrink annual queue entrant classes.

Witmeier said 2022’s 171-GW queue class alone eclipses the typical systemwide 123-GW summer peak. MISO is bracing for another record-setting queue volume in 2023.

“It’s significantly more generation than would ever be built in MISO over the next few years, and there are concerns over how to study it,” Witmeier said. “More requests mean more points of interconnection and more study. There are more [hypothetical] overloads because of the sheer amount of capacity. That requires more engineering study.”

If MISO could cut down on the amount of “speculative requests,” it would result in study assumptions that better resemble the actual future dispatch, he said. “Smaller queue sizes mean faster results.”

Witmeier said it currently does not cost that much to enter MISO’s queue. And he said the RTO’s penalty-free withdrawal policy allows most interconnection customers who withdraw requests to get most of their money back. The $4,000/MW first milestone payment MISO requires of its projects is a “low bar” and represents only about 4% of the RTO’s approximate $100,000/MW financial feasibility threshold for the cost of network upgrades, he said. MISO’s deposits were last upped in 2018 and need to be increased, he said.

MISO will propose a package of alterations at the Planning Advisory Committee meeting in July, Witmeier said. After that, the RTO hopes to file a proposal with FERC in the third quarter and receive approval with enough time before year-end to close the 2023 queue application window. The RTO said it will keep the deadline open-ended until it receives FERC approval on the changes.

MISO was already planning to postpone the application deadline for its 2023 cycle of projects past its usual September cutoff. (See MISO: No Deadline Yet for 2023 Queue Applications.)

Witmeier said MISO is aware that enacting stricter requirements on queue entry can be perceived as it hindering generation development. But he said the real impediment to generation development is the flood of requests — with uncertain project plans among those — that bog down the study process and shift network upgrade costs to other projects. He added that only about 20% of the interconnection requests that enter the queue ever become realized generation projects.

Brattle Group Principal Johannes Pfeifenberger asked if MISO was worried that by restricting the entry of interconnection customers, it will raise the costs of network upgrades because there are fewer generation developers to split them.

Witmeier said he does not believe MISO will encounter that problem because it performs adequate backbone transmission planning through its long-range transmission plan (LRTP) portfolios. He said MISO avoids using its interconnection queue as a means to build major transmission. He also said the first, $10 billion LRTP portfolio likely drove up interconnection requests in 2022.

Witmeier said he plans to reach out to stakeholders to get their ideas on how to make queue entrances and exits less heavily trafficked.

The Sustainable FERC Project’s Natalie McIntire said she is concerned that MISO plans on privately discussing the changes with individual stakeholders.

“I think there needs to be a fairly lengthy stakeholder dialogue on this, and not behind closed doors,” McIntire said.

“We need to be able to work expediently on this. This is not a full-fledged redo of the queue,” Witmeier responded. “However, because we have so many requests, we have issues with speed and cost certainty. So, we have to adjust those rules.”

Witmeier said MISO’s penalty-free withdraw provision is akin to being able to play see the “river” card in Texas hold’em poker without matching a bet. “That’s just not right.”

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FERC Approves New Rules to Enhance Battery Performance in CAISO

FERC on Thursday approved new rules for CAISO intended to improve the performance of energy storage resources and ensure reliability (ER23-1533).

The first of the four new rules will pay storage resources their opportunity costs when they get an exceptional dispatch to hold a state of charge for use later when they are most needed by the grid.

FERC also approved changes to the day-ahead default energy bid for storage to avoid a situation where mitigated bids were causing storage resources to be dispatched in the afternoon, rather than the evenings, when they are needed most. That will be fixed by adding an opportunity cost like the one used in the calculation of real-time default energy bids for storage resources.

The third change relates to how storage resources bid into ancillary services markets to ensure they have enough charge to provide what they bid for. Storage resources will have to submit accompanying energy bids in the real-time market that cover at least any capacity awarded for ancillary services from the day-ahead market.

If a resource deviates from the state of charge anticipated in the day-ahead market and is in danger of not meeting its ancillary services award, then the real-time bid will ensure the resource will still be able to charge or discharge.

FERC approved the first three proposed rules, which did not lead to any debates in the docket.

The final rule change makes it so storage resources are scheduled to provide only the regulation they are capable of, given their constraints.

Vistra, which owns two large storage facilities in CAISO, protested that last rule, saying it gives the ISO broad discretion to account for how regulation awards affect state of charge when determining regulation commitments without providing any detail regarding the parameters and rules that will be used to determine states of charge.

FERC agreed with CAISO that the revisions clarify its responsibility to provide storage resources with achievable regulation awards, given their constraints. The new rules clarify the ISO’s responsibility to continue to refine its optimization software based on storage’s inputs and operational experience in providing regulation, it said.

The commission was not persuaded by Vistra’s protest, saying the language the ISO filed is similar to other parts of the tariff describing how the grid operator optimizes its system. Such provisions require the ISO to take numerous dynamic factors into account in market optimization, but they do not establish new static parameters or standards.

CAISO included examples of how the rule might work in its Business Practice Manuals, which FERC said are also consistent with current practices. The manuals are meant to be guides for internal operating procedures and to inform market participants of the ISO’s practices.

The manuals do not affect any rates, terms or conditions, and the examples in question do not belong in the actual tariff as Vistra contended, FERC said.

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MISO Puts 2 Tx Planning Improvement Suggestions on Hold

CARMEL, Ind. — MISO last week said it will salvage two to-do items from its effort a few years ago to better link up interconnection trends with annual transmission planning.

But the RTO warned that it will likely be years before it has the time to work out possible solutions for them.

The grid operator will keep two unaddressed stakeholder suggestions on hold: one to develop more robust analyses to recommend alternative projects to transmission owners’ proposals, and another to devise a method to evaluate network upgrade projects for potential regionally allocated market efficiency projects.

Jeanna Furnish, MISO’s director of expansion planning, said the two items are the only ones left unaddressed from the project it launched a few years ago to better match its annual transmission planning with the projects that generation developers submit to the interconnection queue. (See MISO Begins Bid to Merge Tx, Queue Planning.)

Since then, MISO has begun recommending and planning portfolios under its long-range transmission planning (LRTP) initiative, satisfying most of the endeavor. The RTO had suggested dropping the listing altogether as part of a cleanup of old stakeholder recommendations, but the Environmental Groups sector protested the deletion. (See MISO Proposes Review of Improvement Ideas’ ‘Parking Lot’.)

“At this time, we don’t foresee having enough resources to be able to work on this until at least 2025,” Furnish warned stakeholders at the Planning Advisory Committee meeting Wednesday. She said MISO’s LRTP effort is already dominating the manpower needed to create an alternatives or evaluation process. It will consider the recommendations “inactive” until 2025.

Earlier in spring, the Sustainable FERC Project’s Natalie McIntire argued the concerns that gave rise to MISO’s retired Coordinated Planning Process Task Team (CPPTT) remain: “MISO has no process to evaluate whether a transmission project required for either generator interconnection or a transmission service request also meets the criteria” of a baseline reliability project or market efficiency project. She argued that the RTO’s tariff demands due diligence across its planning practices.

McIntire said she believes MISO has a duty under FERC Order 1000 to look for more cost-effective transmission alternatives that combine planning needs. But she said MISO simply assures stakeholders it is already doing that, though not much is known about the process.

“MISO must comply with its tariff and create a process by which projects can be evaluated to see if they meet the criteria of other project types,” McIntire said.

The RTO closed out the CPPTT in 2020 when it began working on the first of its LRTP portfolios. At the time, it reasoned that the hefty, comprehensive transmission portfolios would cover the need for an examination into the depth and interconnectedness of its transmission planning amid the clean energy transition.

McIntire said her concerns would be assuaged if MISO committed to conducting the LRTP on a regular basis, but the RTO has not said it has a frequency in mind for long-range planning. She also said LRTP studies take multiple years to finish, making a cadence difficult to establish. Interconnection requests in the intervening years between LRTP studies could turn up network upgrades that would be better suited as regional or reliability projects, she said.

MISO’s newly revived Stakeholder Governance Working Group is working on how it can have a structured process for closing out stakeholder-submitted ideas for improvement. Today, the RTO doesn’t have a formal process for removing stakeholders’ recommendations from its to-do list.

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Texas PUC’s Lake Steps Down as Chair

Peter Lake, appointed to restore the Texas Public Utility Commission’s credibility after the disastrous 2021 winter storm, said Friday he is stepping down as PUC chair.

His resignation comes after he apparently lost the faith of Texas lawmakers. Lake pushed forward a complicated and novel market design, the performance credit mechanism (PCM), that would benefit primarily thermal generation. The Texas Legislature took little action on the PCM during its recently concluded session other than proposing guardrails that would reduce its financial benefits. (See Clean Energy Escapes Texas Legislature’s Wrath.)

Gov. Greg Abbott announced Lake’s resignation late Friday afternoon, a time normally reserved for dumping bad or uncomfortable news and hoping it goes unnoticed over the weekend. Abbott, who appoints members to the five-person commission, promised to name a new chair “in the coming days.”

Lake will leave the PUC July 1, two months before his term expires.

“The most surprising unsurprising news,” said one industry insider, who wondered whether Lake really enjoyed his job.

Other ERCOT stakeholders weighed in as well.

Attorney Katie Coleman, who frequently testifies before the PUC and represents Texas Energy Industrial Consumers, tweeted that she and Lake disagreed on market policy, but that he “had good intentions, tried to bring a fresh perspective, and put in a lot of long hard hours for the state.”

“He will be remembered for his lack of knowledge of simple microeconomics, unexplained support of the anti-market and pro-oligopoly PCM model, and attempting to implement an authoritarian power structure by removing stakeholders from the ERCOT process,” tweeted another interested observer, who uses the ERCOT Traders Anon handle.

The grid operator’s market participants have been largely sidelined by 2021 legislation that replaced the previous board, composed of market participants and independent directors, with eight independent directors selected by the state’s political leadership. The board then created a reliability and markets subcommittee that creates another layer of separation between stakeholders and the directors.

Asked about the PCM’s fate, a PUC spokesperson said it would be “premature” to discuss any legislation’s effect until it becomes law.

Abbott selected Lake to lead the PUC in April 2021, saying he was confident Lake would “bring a fresh perspective and trustworthy leadership to the PUC.”

Lake replaced DeAnn Walker, who resigned under pressure following the February winter storm that nearly collapsed the ERCOT grid and led to days of blackouts that killed hundreds of Texans and caused billions in financial damage. (See Abbott Appoints New Texas PUC Chair.)

In a statement provided by the PUC, Lake thanked Abbott for the “incredible opportunity” to serve the state.

“When I arrived at the [PUC] in April 2021, our electric grid was in crisis,” he said. “Thanks to the hard work of the teams here and at ERCOT, and my fellow commissioners, today our grid is more reliable than ever. While there are challenges ahead, I know the [PUC] is well positioned to continue the incredible progress we’ve made.”

During Lake’s tenure, the PUC ordered weatherization requirements for generators and transmission facilities, made it easier to build transmission facilities, and directed ERCOT to make several tweaks to the market. However, as with the PCM, he also focused on dispatchable, or thermal, generation and highlighted renewable energy’s intermittency.

Abbott praised Lake for being a “true public servant who stepped up during a critical time in our state” to rebuild the PUC and “Texans’ trust in those charged with providing reliable power.”

“With Lake at the helm of the PUC,” Abbott said, “we have ensured that no Texan has lost power due to the state grid” since legislation passed in the wake of Winter Storm Uri.

Lake previously chaired the Texas Water Development Board, which provides planning for the state’s water resources and wastewater services. He brought a financial background with him, having led business development at Lake Ronel Oil and special projects for equity firm VantageCap Partners.

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WEIM Sees Record Q1 Benefits with Growth of Footprint

CAISO’s Western Energy Imbalance Market yielded members $418.82 million in economic benefits during the first three months of 2023, up 143% from the same period in 2022 and a first-quarter record.

Cumulative benefits since the 2014 rollout of the market have nearly doubled over the past year, reaching $3.82 billion after three consecutive quarters that smashed records, according to CAISO’s first-quarter benefits report, released Thursday.

The sharp growth comes after four new participants entered the market last year: Avista Utilities, Tacoma Power, Tucson Electric Power and, most significantly, the Bonneville Power Administration, which operates 15,000 miles of high-voltage transmission — about 70% of the network in the Northwest.

The first-quarter benefits report was released about a month later than normal, which the ISO attributed to the need for more time “to review the benefits estimates and the underlying congestion observed in certain areas of the WEIM footprint,” according to a press release accompanying the report.

“Ultimately, no changes to the current methodology have been implemented to estimate the first quarter benefits. The CAISO and its WEIM partners will continue to assess and determine if methodology enhancements are warranted based on various conditions of congestion,” the ISO said in the release.

CAISO itself earned the largest share of benefits during the quarter, at $67.86 million, followed by NV Energy ($47.19 million), Balancing Authority of Northern California — or BANC ($44.63 million), Salt River Project — or SRP ($31.38 million), PacifiCorp ($28.94 million), and Los Angeles Department of Water and Power ($27.99 million).

BANC’s balancing authority area includes the state’s second-largest municipal utility, Sacramento Municipal Utility District, as well as Modesto Irrigation District, the cities of Redding and Roseville, and the Western Area Power Administration’s Sierra Nevada region.

CAISO was the largest net exporter of energy during the quarter, at 1,354,826 MWh, followed by SRP (510,350 MWh), NV Energy (478,330 MWh) and PNM (350,796 MWh). The ISO was also the second-largest net importer, at 848,513 MWh, exceeded only by British Columbia’s Powerex, at 881,791 MWh.

CAISO was also the location of the most wheel-through transfers, at 760,999 MWh, followed by Arizona Public Service (587,198 MWh), the PacifiCorp-West BAA (314,838 MWh) and NV Energy (296,657 MWh). In years past, NV Energy consistently handled the highest volume of wheel-throughs, but the inclusion of more Pacific Northwest WEIM participants appears to be shifting a greater share of those transfers to California. Market members gain no financial benefit from facilitating wheel-throughs, with only the sink and source directly benefiting.

CAISO said WEIM operations helped reduce renewable curtailments by 53,002 MWh during the first quarter, helping to prevent emission of 53,002 metric tons (MT) of CO2. The market has avoided 814,746 MT of carbon emissions since 2015, the ISO estimates.

With the inclusion of the Western Area Power Administration–Desert Southwest region and Avangrid in April, the WEIM footprint now covers 79% of the load in the Western Interconnection. CAISO expects the market to break $4 billion in total benefits this quarter.

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Experts Urge MISO to Consider New 765 kV and HVDC Lines

CARMEL, Ind. — MISO’s future is all but certain to contain more 765-kV and HVDC transmission lines, experts predicted during a special two-day meeting of the Planning Advisory Committee last week.

“The magnitude and scope of possible system challenges point to the need for a higher-voltage, higher-capacity superhighway or backbone of either 765 kV or HVDC,” said Energy Systems Integration Group’s James Okullo, citing the volatile ramping needs, increased congestion, larger energy transfers and voltage stability issues the resource transition will bring.

He pointed out that MISO is planning for a system with 80% annual renewable penetration within 20 years.

VSC converters (Siemens Energy) FI.jpgVSC converters | Siemens Energy

Multiple experts said MISO could use grid-forming voltage-sourced converter (VSC) HVDC lines and include them in the second portfolio of its long-range transmission planning (LRTP) effort. They praised VSC-HDVC’s ability to deliver power-flow control, inherent reactive power and voltage support, dynamic stability, and synthetic inertia, and its potential to provide black start system restoration.

MISO planners have said they’re not ruling out recommending a 765-kV or HVDC line in the second LRTP portfolio. (See MISO: Long-range Tx Needed for 369 GW in Interconnections.)

“VSC today is not as exotic a thing as it was 15 years ago, and with good reason,” Minnesota Power’s Christian Winter said.

Winter said VSC-HVDC is “uniquely suited for the clean energy transition” because it can move power across long distances while supplying ancillary services. He also said VSCs on the receiving end of transfers can function like dispatchable power plants and can be placed where retiring baseload generation is located.

Cornelis Plet, vice president of power system advisory at DNV, said VSC-HVDC is becoming “the technology of choice” in European countries to achieve reliability while meeting ambitious climate goals. It allows the connection of different synchronous zones and can connect remote loads and remote generation. Europe is finding HVDC technology so useful that total installed HVDC capacity will more than triple in the next decade, he said. While the continent is so far building point-to-point lines, an overlay grid of HVDC lines will realize the full benefits.

VSC has become the “workhorse” of HVDC lines, and the use of line commutated converter technology is disappearing, Plet concluded.

Brattle Group Principal Johannes Pfeifenberger said MISO is “in the best position to take advantage” of VSC-HVDC as it plans its second LRTP portfolio.

“Tranche 2 is the opportunity for MISO to get its feet wet and offers a unique opportunity for MISO to gain the necessary planning, market integration and operational experience with VSC-HVDC technology for possible larger-scale future deployments,” he said.

Pfeifenberger said Europe has discovered that VSC is “so compelling in what it can do” and has cemented itself as the dominant converter technology. He said grid planners struggle with placing a value on the resilience that HVDC can deliver. A well-placed 2,000-MW HVDC line would help Texas address its AC stability limits when it transfers power from the western portion of the state.

“It’s future-proof in a way that would be very expensive to address with AC technology,” Pfeifenberger said. He recommended that MISO adapt its markets to be able to dispatch HVDC lines to capitalize on the “incredible advantage” of alleviating congestion by controlling power flows.

American Transmission’s Bob McKee, representing MISO’s transmission owners, said the RTO’s current 240-GW interconnection queue shows the fleet transition is gearing up. He said he was delivering a “call to action from the TO sector” and encouraged MISO to “be bold” in its planning and consider all transmission solutions.

“I think Winter Storm Uri and Winter Storm Elliott are fresh in our minds, and we realize the importance of a robust transmission system,” McKee said.

McKee also said electrification “just isn’t coming; it’s already here.”

“This is our opportunity to identify a set of facilities that will fit our needs,” he said.

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Mass. Stakeholders Debate the Scope of Clean Heat Standard

Massachusetts energy providers, consumers and climate advocates presented contrasting visions of what solutions should be included in a clean heat standard (CHS) that is currently being developed by the state’s Department of Environmental Protection (DEP), as shown by public comments published last week.

The development of the standard was endorsed in the final report by the Massachusetts Commission on Clean Heat, and the DEP began development in April, soliciting initial comments from stakeholders on the scope of the process and the standard itself.

Under the basic framework, fuel suppliers would be required to acquire an increasing number of credits associated with verified reductions in emissions from heating. Credits could be bought and sold to help suppliers meet their obligations, while suppliers could also be allowed to meet their obligations through alternative compliance payments.

The goal of the standard is to help Massachusetts align its heating sector with its mandatory emissions limits: The state is required by law to reduce its gross emissions 50% by 2030, 75% by 2040, and 85% and be net-zero by 2050. The state also has emissions sub-limits for different heating sectors, as well as for the gas system, which are set in five-year increments.

In 2018, combustion for heating accounted for about 34% of Massachusetts’ carbon pollution, according to a report prepared for the state by researchers at the Regulatory Assistance Project (RAP), which outlined options for a CHS. The report noted that natural gas accounted for about two-thirds of heating emissions.

Defining Clean Heat

Many of the comments received by the DEP focused on whether alternative fuels should be able to generate clean heat credits.

According to the RAP report, decarbonization options include “weatherization improvements, energy efficiency improvements, heat pumps, clean district energy and other verified low-carbon options, potentially including renewable methane, clean hydrogen, biodiesel, renewable diesel and advanced wood heat.”

Fossil fuel producers and providers argued that the DEP should include a variety of options related to alternative fuels in the standard, while environmental groups said the standard should only incentivize electrification and weatherization options.

National Grid said that “electrification and energy efficiency should be the cornerstone strategies for decarbonizing buildings in Massachusetts,” but it also argued for the inclusion of combustion options within the standard.

“Alternative, low-carbon, non-fossil fuels will play an important role in ensuring families and businesses across the commonwealth have access to decarbonized heat,” National Grid wrote. “Repurposing existing infrastructure, including the existing gas distribution network to deliver low-carbon alternative fuels such as RNG [“renewable” natural gas] and hydrogen can help make the energy transition more affordable by reducing the need for new electric infrastructure construction, which will present affordability challenges.”

The Mass Coalition for Sustainable Energy — a group funded in part by Enbridge, Eversource Energy and National Grid, and whose members include the Associated Industries of Massachusetts, the commercial real estate development association NAIOP and several regional chambers of commerce — called hydrogen and RNG “viable decarbonizing pathways” for heating, adding that “we cannot take those pathways off the table.”

Meanwhile, environmental groups argued that hydrogen and RNG should not be included in the standard.

“Our top priorities for a CHS for Massachusetts are ensuring adequate equity protections and an electrification-only compliance program, particularly for gas utilities,” wrote a coalition of 37 environmental groups, led by the Conservation Law Foundation, Acadia Center, Green Energy Consumers Alliance and Pipe Line Awareness Network for the Northeast. “Alternative gases are not a long-term solution for the buildings sector, so incentives should not encourage buildout of these wasteful processes in the near term.”

Sector sub-limits for carbon (Massachusetts DEP) Content.jpgMassachusetts sector sub-limits for carbon emissions | Massachusetts DEP

 

The coalition said that the greenhouse gas emission reductions associated with replacing natural gas with hydrogen and RNG would be marginal, and that a dependence on these fuels would increase the overall costs associated with reaching net-zero emissions.

They also highlighted concerns related to the safety of blending significant quantities of hydrogen into the gas system, along with the public health impacts related to combustion.

“The commonwealth should not fund fuels like hydrogen that pose significant safety risks, when safer appliances like heat pumps are available,” Andee Krasner wrote on behalf of Gas Transition Allies’ Hydrogen and Biogas Working Group. “Hydrogen ignites more easily and has a wider explosive range than natural gas. … It can embrittle steel pipes, and hydrogen has higher permeation rates for elastomeric seals and plastic pipes.”

Krasner added that “biofuels and green hydrogen made using renewable energy have an important role in the future but should be reserved for hard-to-electrify industrial processes. They should be produced preferably on-site or, if not, then as close to the end use as possible to minimize leakage and pollution.”

The Coalition for Renewable Natural Gas — whose members include fuel producers that specialize in RNG, as well as fossil fuel producers, including Shell, Chevron, BP, and pipeline companies such as Kinder Morgan and Enbridge — argued that RNG could cover a major portion of the state’s gas needs.

“The portion of renewable gas serving Massachusetts’ gas system will increase even as total system throughput declines, eventually leading to a smaller gas system which transports only 100% clean fuels to targeted end uses,” the coalition wrote. “Given expected declines in gas system throughput, the use of renewable gas need not lead to net pipeline expansion, beyond connecting these new supply sources to existing load.”

The coalition said RNG from waste sources in Massachusetts such as landfills, manure and wastewater treatment could cover about 10% of existing residential gas demand, 11% of commercial demand or 26% of industrial demand in the state; gasification of organic matter such as agricultural and forestry residues and energy crops could nearly double this total.

While most fuel suppliers focused on alternatives to fossil fuels, Canadian fossil fuel producer Irving Oil argued that the standard should incentivize some fossil fuel heating systems.

“End-use fuel switching should be eligible as a means to comply because a lower-carbon fuel (i.e., heating oil to natural gas) is still an improvement in emission reductions and shouldn’t be discredited,” the company wrote. “Energy-efficient heating systems, including but not limited to combined heat [and] power systems that may use portions of fossil fuels should also be incentivized.”

The RAP report directly discouraged incentives for fuel switching, saying that new pipeline buildout “both adds to the fixed costs of the pipeline grid and delays the ultimate conversion of the building away from fossil fuels,” while the state’s Commission on Clean Heat concluded that “the installation of new fossil fuel equipment and services should not be supported under the CHS.”

Protecting Vulnerable Communities

Public comments from stakeholders largely agreed that the CHS needs to be designed in a way to protect lower-income residents as the costs of the transition mount.

The city of Boston said that the standard should incentivize co-benefits including air quality, workforce development, equity and resilience, and called on the DEP to take on a robust public engagement process.

“Addressing the challenges of climate change presents opportunities for advancing the wellbeing of our residents, communities and economies; a holistic approach to designing programs like a clean heat standard will help identify and take advantage of such opportunities,” wrote Mariama White-Hammond, Boston’s chief of environment, energy and open space.

The environmental group coalition called for substantial adjustments and protections for low-income customers, who represent a disproportionate share of residents of color in the state.

“Perpetuation in the medium to long term of the unmanaged transition off of gas that is already underway will be an inequitable disaster for low- and moderate-income [LMI] gas customers,” the group wrote. It also advocated for targeted protections for renters to prevent gentrification caused by building upgrades.

“Without protections for renters, landlords can use incentives subsidized by ratepayer or tax dollars like a CHS or Mass Save for building upgrades as a pretext for rent increases that force out low- and moderate-income renters from relatively affordable housing units.”

The state’s Commission on Clean Heat recommended that the DEP require fuel providers to “include a specified percentage of credits generated in LMI and [environmental justice] populations and households in their annual compliance filings.”

National Grid wrote that it supports this recommendation, along with dedicating funds from alternative compliance payments to support environmental justice communities.

The DEP will hold its first virtual public meetings on the CHS on June 20 at 10 a.m. and 6 p.m.

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DOE to Award $46 Million to 8 Commercial Fusion Developers

After decades of funding research to one day harness the power of nuclear fusion, the Department of Energy this week announced grants to help startups develop commercial fusion reactors.

The agency on Wednesday announced $46 million in “milestone-based” grants to eight competing companies across seven states. 

The winners were drawn from a much larger group that applied for the funding when DOE announced the grant program last fall. The grants will be delivered in increments over time as the companies achieve development milestones initially negotiated with DOE.

Noting that $5 billion of private capital is invested in predominantly U.S.-based fusion companies, Energy Secretary Jennifer Granholm said the Biden administration believes commercialization can occur within a decade.

“And so we’ve launched this milestone-based fusion development program, where private companies are going to team up with our labs and with universities and others to work through the scientific and technological challenges with the goal of designing a fusion pilot plant within the next five to 10 years,” Granholm said.

Arati Prabhakar, director of the White House Office of Science and Technology Policy, said the question is not how to achieve that 2030 target but how to meet the administration’s 2050 goals of eliminating greenhouse gas emissions.

She said the partnerships DOE is developing with the grants will be crucial to commercializing fusion.

“I love a big, aggressive, barely feasible goal because it forces you then to figure out what does it actually take to get there. I’ve really been excited watching DOE ask that question about fusion. Having the scientific basis that tells us that we can do this is necessary, but it’s very, very far from sufficient,” Prabhakar said.

“There’s so much more work that has to be done to turn this into something that is a commercial capability that’s consistent, safe and reliable,” she added. The work deals with thermal, materials and radiation issues that much more advanced technology won’t remove the need for, she said.

The companies receiving grants are:

  • Commonwealth Fusion Systems (Cambridge, Mass.)
  • Focused Energy (Austin, Texas)
  • Princeton Stellarators (Branchburg, N.J.)
  • Realta Fusion (Madison, Wis.)
  • Tokamak Energy (Bruceton Mills, W.Va.)
  • Type One Energy Group (Madison, Wis.)
  • Xcimer Energy (Redwood City, Calif.)
  • Zap Energy (Everett, Wash.)