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November 1, 2024

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PJM OKs 32% Cut in Elliott Penalties in Proposed Settlement

PJM has agreed to reduce its nonperformance penalties 31.7% for generators that could not meet their capacity obligations during the December 2022 winter storm.

A proposed settlement filed Sept. 29 by PJM and 81 other parties would resolve the bulk of 15 complaints generators filed against the RTO arguing that it had either improperly declared performance assessment intervals (PAIs) in regions where emergency conditions were not present or unjustifiably applied nonperformance penalties (EL23-53, et al.).

PJM did not admit to any wrongdoing or violation of its tariff in the settlement, and the agreement does not include any changes to the governing documents. The filing states that the settlement was either supported or not opposed by the “overwhelming number of active parties in the case.” (See Settlement Possible Between PJM And Several Generation Owners over Winter Storm Complaints.)

“These Winter Storm Elliott complaints had the potential to become the next ‘mega-litigation’ along the lines of the California Energy Crisis litigation or the Seams Elimination Cost/Charge Adjustment/Assignment litigation; instead, the settling parties have achieved a negotiated resolution that avoids years (or, in the case of the California Energy Crisis, decades) of litigation and now present that resolution to the commission for approval,” the filing said.

All 15 complaints would be resolved by the settlement except for portions of complaints by East Kentucky Power Cooperative (EKPC) (EL23-74) and Energy Harbor (EL23-63) to be decided by FERC. The settlement allows EKPC to pursue its request to modify its penalty charge rate and stop-loss rate.

EKPC argued that the Capacity Performance (CP) penalty rate and stop-loss limit are unjust and unreasonable by not being tied to the revenues market sellers receive through the capacity market — potentially resulting in resources being levied penalties larger than their capacity revenues. The complaint called for the commission to modify the penalty calculation to instead use the Base Residual Auction (BRA) clearing price, rather than the net cost of new entry (CONE) for both the charge rate and stop-loss. EKPC requested that the change be effective for the 2023/24 delivery year.

The PJM Board of Managers directed staff to revise the stop-loss to be based on the BRA clearing price as part of a larger reworking of the capacity market expected to be filed this month. The penalty charge rate would remain based on net CONE. (See PJM Board Releases Outline of CIFP Filing.)

The EKPC complaint also argued that PJM violated its tariff by not curtailing nonfirm exports during emergency conditions and that the company’s Bluegrass generator should be excused from penalties. EKPC agreed to drop both issues as part of the settlement.

The settlement asks the commission to “decide the merits” of Energy Harbor’s argument that PJM violated its tariff by assessing nonperformance charges against 300 MW of capacity that was unavailable due to maintenance outages. The company contended the capacity should be excused from penalties.

The settlement also includes an agreement that PJM will credit $4.4 million to Lee County Generating Station to resolve its complaint. The RTO will also extend collection of the company’s remaining penalty balance, and corresponding interest, to avoid depleting the collateral PJM holds to support Lee County’s exports to MISO.

Lee County’s complaint argued that it should not be subject to penalties, as it was on a forced outage at PJM’s request and would have been available during the PAIs if dispatchers had not requested that it go offline. In July, the commission approved a request from PJM and Lee County to defer the final six months of the company’s penalty billing schedule through June 2024 to avoid the company defaulting on its obligations in PJM and MISO (EL23-57).

The reduction applies to all market sellers assigned a share of the $1.8 billion in penalties associated with Winter Storm Elliott, including those that have already paid their penalties in full. Recipients of bonus payments — which are distributed to generators that overperformed during PAIs out of the pool of penalties collected — will be required to refund a portion of their allocation.

The penalty reduction is predicated on market sellers continuing to meet their payment obligations or already having paid off their penalties. If a party defaults or does not make a payment, the original full penalty will be reinstated with interest. Market sellers who opted for a longer nine-month repayment timeline, which comes with the tradeoff of being subject to interest, will have the interest due on their penalties recalculated to use the lower settled figure. Interest will not be due on the bonus payment refunds. (See “FERC Approves Alternative Billing Schedule,” PJM: Elliott Nonperformance Penalties Total More Than $1.8B.)

PJM will also re-evaluate the collateral each market participant must provide PJM to take into account the reduced penalties. Parties that have paid off their charges in full will have their collateral released under the settlement.

The settlement is contingent on FERC approval “without material modification or condition,” and it states that the filing will be withdrawn unless the settling parties agree to any modifications the commission may condition its approval on. The filing requests commission approval no later than Dec. 29 and use of the default comment period, which would make responses due Oct. 19.

“Timely commercial certainty is a core objective of the settlement, and that objective would be significantly undermined if the commission does not approve the settlement by the end of this calendar year,” the filing said.

On Oct. 25, the commission granted a tariff waiver PJM and several complainants requested to allow the RTO to delay collection of unbilled penalties and distribution of bonuses until the settlement is acted upon by the commission and can be implemented by PJM. The order stated that delaying billing would be “administratively efficient” by reducing the potential for rebilling and resettlement should the settlement be accepted and result in a change in the penalties due.

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CAISO Proposal Seeks to Address Interconnection Backlog

As CAISO grapples with an “unprecedented” surge in interconnection requests, the system operator has proposed prioritizing requests in zones where transmission capacity now exists or is under development.

The “zonal approach” is outlined in a straw proposal CAISO released Sept. 21 as part of its 2023 Interconnection Process Enhancements (IPE) initiative.

CAISO has been overloaded with interconnection requests resulting from the rapid pace of clean energy development in California as the state works toward a goal of 100% clean energy by 2045.

The most recent group of interconnection requests, Cluster 15, included about 544 requests totaling around 354 GW. That compares to 150 requests in 2020 and 373 requests in 2021.

CAISO said the increased number of requests is “unsustainable” and has overwhelmed existing processes.

“The ISO needs a significantly reformed structure to advance viable projects and prevent stagnant projects from hindering the progress of viable projects in the queue,” CAISO said.

In response, the straw proposal lays out a “significantly reformed interconnection process” aimed at promoting “rapid deployment of new generation for reliability, affordability and decarbonization.”

Zones, Scoring and Auction

CAISO calls the zonal approach a “central tenet” of its straw proposal. The ISO said its 2022/23 transmission plan took a zonal approach to planning for the resources in the portfolio provided by the California Public Utilities Commission for that cycle, “setting the foundation for the alignment of procurement and interconnection process enhancements.”

Under the proposal, projects in zones with available transmission capacity would be prioritized to move into the study process.

CAISO noted the importance of publicly providing information on the priority zones before opening an interconnection request window, such as a heatmap showing available transmission capacity. A heatmap is one of the requirements of FERC Order 2023, issued in July, regarding interconnection reform. (See FERC Updates Interconnection Queue Process with Order 2023.)

In another proposal, CAISO would use a scoring system in situations where the capacity of interconnection requests exceeds the available transmission capacity within a zone by more than 150%. Scoring criteria might include interest from an offtaker, permitting status and commercial readiness.

In some cases, CAISO would also conduct an auction in which winners would be prioritized and studied in a certain zone. The auction would occur when proposed capacity exceeds the capacity limit for a zone, after viability criteria are applied.

CAISO said an auction process may be needed “to achieve manageable queue volumes and preserve the competition of viable projects in each zone.” The ISO acknowledged that the auction proposal raised a number of stakeholder questions, including how the auction proceeds would be spent.

Interconnection Option B

The proposal also includes a process, called Option B, for requests to interconnect outside of priority zones. Those projects would be required to pay for needed network upgrades.

CAISO held a series of stakeholder meetings over the summer to come up with ideas for addressing the high volume of interconnection requests. (See CAISO Tries to Shake up Its Interconnection Process.)

Comments on the new straw proposal are due Oct. 12. After that, CAISO will release a second draft, followed by another round of comments. The proposal is expected to go to the CAISO Board of Governors for approval in February.

The straw proposal is part of Track 2 of the 2023 IPE initiative. Track 1 involved changes to the Cluster 15 study schedule that were approved by the Board of Governors in May.

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MISO PAC Considers Lower, $9B MTEP 23 Transmission Package

MISO’s Planning Advisory Committee is deciding whether to approve the MISO 2023 Transmission Expansion Plan, which has dropped to just under $9 billion within a month.

Last month, MTEP 23 stood at 578 projects totaling $9.4 billion. Now the annual portfolio clocks in at $8.96 billion across 575 projects.

At a special Sept. 28 teleconference, the PAC opted for an email ballot through Oct. 5 on whether to recommend the portfolio to MISO board members. The PAC’s vote is advisory and can be bypassed.

MISO’s Jeremiah Doner said transmission owners have reviewed projects, made adjustments and refined cost estimates since the final round of subregional planning meetings on MTEP 23 in September.

Doner said some projects have been postponed to later MTEP cycles. Most notably, MISO has deferred the $260 million third phase of Entergy Louisiana’s Amite South reliability project into MTEP 24.

MISO is conducting additional analysis on possible alternatives to the project, which was among MTEP 23’s most expensive, Doner said.

Despite the deferral of the Entergy project, MISO South’s 77 projects still account for 46% of MTEP 23 spending. MISO remains committed to its recommended, $1.7 billion, 500-kV Commodore-Waterford-Churchill loop project, which will replace both the first phase of Entergy Louisiana’s Amite South project and the Downstream of Gypsy reliability project, another Entergy Louisiana proposal. (See MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.)

MTEP 23 contains $1.2 billion in generator interconnection upgrades, $1.7 billion in baseline reliability projects and nearly $6 billion in “other” projects, which includes reliability projects based on transmission owners’ self-imposed criteria separate from NERC standards, such as projects responding to load growth or addressing the age and condition of existing facilities.

Doner said MISO is confident it has assembled a package of “efficient, cost-effective solutions to identified system issues.”

Sector Critiques

MISO’s Competitive Transmission Developers Sector said the RTO should have reviewed more projects for “more efficient or cost-effective regional project alternatives.”

“Such a review is required by the MISO tariff and FERC Order No. 1000, and the failure to consider alternatives may lead to the approval of transmission projects that do not efficiently solve these and other system needs, which ultimately increases costs to customers,” the developers said.

Doner responded that MISO already prioritized alternative analyses for proposed new lines and larger, expensive projects that may affect the entire system.

“Roughly 75% of MTEP 23 projects didn’t meet criteria for alternative solution analysis, as they address needs with no cost-effective alternatives,” he said.

The RTO’s Environmental Sector said the MTEP 23 report should mention MISO’s “struggles to manage” its 242-GW generator interconnection queue and should describe what resources it needs to complete studies on time.

Doner said MISO continues to work on its queue processing time. He also pointed out that MISO is sitting on 49 GW worth of new generation that’s on hold despite MISO having already studied it and signed off on interconnection. He said “limitations on new interconnections are due to factors outside of MISO’s control, such as construction delays and supply chain issues.”

The Environmental Sector also asked MISO to pay more attention to HVDC lines in MTEP reports and do more to explore the potential for battery storage in MISO’s future.

Doner said MISO agrees that HVDC lines could be necessary. He said MISO and stakeholders will discuss HVDC needs as part of the second portfolio under MISO’s long-range transmission planning.

Doner also said, “MISO will monitor market performance and interconnection processes for potential improvements as more storage is constructed.”

Sustainable FERC Project’s Natalie McIntire said though the Environmental Sector often provides substantial comments, MISO “rarely” changes or adds detail to its MTEP reports based on the sector’s suggestions.

MISO said it will publish the comments it received as an appendix to the MTEP 23 report.

MTEP 23 will enter its next review at an Oct. 17 meeting of the System Planning Committee of the MISO Board of Directors.

MTEP 24

Meanwhile, MISO transmission owners have already submitted project proposals for MTEP 24, which will use the RTO’s new, one-stop model manager. The model manager project aims for one system of record for all planning and operations models to eliminate redundant data entry and review.

MISO and vendor Siemens are working to synchronize data collection fields between MISO’s different model structures. At the Sept. 27 Planning Subcommittee, MISO’s Scott Goodwin said he expects a few hiccups as MISO transitions to the new model system for MTEP 24.

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MISO May Use Inaugural Near-term Congestion Study to Plan Smaller Tx Upgrades

MISO’s exploratory study on alleviating near-term transmission congestion has led the RTO to consider adding near-term economic benefits to its existing long-term economic planning.

Speaking at a Sept. 27 Planning Subcommittee, economic planning engineer Sean Rogers said that, as a result of this year’s inaugural near-term congestion study, MISO “will continue to explore how to adapt economic models and processes to identify near-term issues and solutions.”

MISO’s economic planning models are geared toward long-term horizons, not short-term congestion relief and economic benefits.

Rogers called the study a “starting point” for MISO to translate its long-term economic planning processes into a near-term model. He said over 2024, MISO will investigate how it can modify long-term planning models to “be more applicable for near-term use” and that the continuing evaluation will be part of the 2024 MISO Transmission Expansion Plan (MTEP 24).

Under this year’s purely informational study, MISO studied its top 10 most congested flowgates in its day-ahead market from 2021 to 2022. It assigned an unlimited kV rating on the flowgates in the study to pinpoint when hypothetical upgrades were beneficial over a five-year horizon based on adjusted production costs.

The study is for informational purposes only, so MISO isn’t recommending any transmission projects from its conclusions. However, planners said they may suggest projects after 2024’s study.

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. (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. Some stakeholders have expressed disappointment that the study hasn’t resulted in a new class of projects.

Nevertheless, MISO found that if Duke Indiana’s Cayuga 345/230kV transformer were upgraded in west-central Indiana, it could save $2 million annually in adjusted production costs. The facility racked up about $30 million in day-ahead congestion in 2022.

Southern Minnesota Municipal Power Agency’s Murphy Creek – Hayward 161-kV line could save a little more than $1 million per year with an upgrade, cutting into the $28 million in day-ahead congestion it accumulated in 2022.

All other hypothetical upgrades on MISO’s top 10 most congested flowgates saved less than $500,000 annually. Two showed negative benefits because of impacts on nearby facilities.

MISO found a contradictory, $5 million in additional annual costs when it studied an upgrade to Ameren Illinois’ Marblehead North 161/138-kV transformer. MISO said it will continue to examine the reasons behind the economic harms. The Marblehead flowgate accumulated more than $102 million in day-ahead congestion costs over 2022.

Some flowgate congestion cases were found to be linked to temporary outages. Congestion on Great River Energy’s Johnson Junction – Graceville 115-kV line in Minnesota — which surpassed $71 million in congestion costs in 2022 — was “directly related to the planned construction outage on the Johnson Junction to Morris line” from Oct. 1, 2021, to Feb. 1, 2022. Two other congested flowgates were linked to Duke Energy Indiana’s Cayuga Unit 1 outage.

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New Buildings May be The Next Climate Solution

The building construction sector has the potential to move from being a massive emissions source to a carbon sink, a new report said.

Driving Action on Embodied Carbon in Buildings, jointly released by RMI and the U.S. Green Building Council (USGBC), looks at challenges in reducing embodied carbon emissions in the building construction sector and the potential for reducing and even negating those emissions.

“In our lifetimes, we could see buildings move from being leading drivers of climate change to safely and durably storing gigatons of atmospheric carbon,” the report said. “There is a long way to go to achieve such an ambitious goal, but it is not as far-fetched as it may seem. Buildings currently account for nearly 50% of global material flows. Only a small percentage of that material would need to store carbon to become a leading climate drawdown solution.”

When looking at greenhouse gas emissions reduction, the focus is often on energy consumed by buildings’ operations and how it can be cut through energy efficiency. The International Energy Agency says operating buildings and the appliances and equipment in them accounts for more than one-third of global energy use and emissions, but that figure doesn’t account for the buildings themselves.

The carbon embodied in the buildings includes the carbon emissions from the energy used in extracting, processing and transporting materials, equipment and fixtures, and constructing buildings, as well as managing the waste at the end of the building’s life. The World Green Building Council estimates buildings’ material and construction accounts for 11% of global energy-related carbon emissions. And it is why everyone in the green building industry winces when another video of imploding, never-occupied high rises in China makes the rounds on social media.

“Given the scale of the sector’s climate impact, it is imperative that owners, designers, builders, manufacturers and policymakers lead the market by prioritizing this issue,” the report said.

There are already cost-effective ways to reduce buildings’ embodied carbon. The report quoted an RMI study that showed it is possible to reduce the upfront carbon footprint of common building types between 19 and 46% with little to no added expense by making more informed materials choices.

Across all building materials, there are critical data gaps when it comes to measuring the lifecycle emissions of materials. “Currently, the most accurate data points exist for cradle-to-gate emissions in key building material categories including concrete, masonry, steel, aluminum, gypsum board, insulation, cladding, flooring, ceiling tiles and paint,” the report said. Emissions after “the gate” — transportation from the factory to the building site and construction itself — are less well understood.

Data gaps, however, are not a reason to delay action, the report said. “We know enough today to make meaningful decisions that reduce building embodied carbon emissions and should not let data gaps stop rapid uptake of low-embodied-carbon strategies in rating systems, policies and codes.”

Tackling The Big Three: Concrete, Steel And … Wood?

The potential to cut the embodied carbon of buildings in the future looks even better as innovations in the production of key building materials, especially energy-intensive concrete and steel, drive down their embodied energy. “Transition away from fossil fuel production of concrete and steel combined with the rapid decarbonization of the grid portends a future where the embodied carbon of these materials can approach zero emissions,” the report said.

Wood too has the potential to be improved, and it may not be as green as it may sound. “Wood used in building products has the potential to be a renewable and perhaps carbon-storing material that can help drive down embodied carbon emissions when efficiently substituted for high-impact materials. However, there are aspects of wood sourcing — such as forestry practices with poor climate outcomes, wider land-use impacts and energy-intensive product manufacturing — that can lead wood to have high emission and ecological impacts.”

Updates Can Double Embodied Energy

The embodied carbon from retrofits and renovations over the lifetime of a building may equal or exceed that of the initial construction, the report said, and is “poorly understood but could be a major driver of emissions if left unaddressed.” Avoiding, delaying or limiting the scope of updates, disassembling instead of demolishing and increasing materials recycling can all lower the impact of renovations.

Renovations, though, offer potential for carbon drawdown. “Interior finishes represent some of the best opportunities to incorporate carbon-storing, rapidly renewable, bio-based materials that are not subject to exterior weathering,” such as bamboo flooring and cellulose acoustic panels, the report said.

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MISO Demand Up, Prices Down During Bumpy August

Despite a maximum generation emergency and hot weather challenges, MISO’s reliability, markets and operational functions performed as expected in August, RTO officials said last week.

MISO hit its monthly — and yearly — peak demand of 125 GW on the evening of Aug. 23, according to its monthly operations report. MISO’s maximum generation emergency would come a day later, when load topped out at 123 GW. (See MISO: Could Have Employed Wait-and-see Approach for August Emergency.)

MISO averaged an 87-GW peak load in August, higher than 2022’s 84 GW. Average daily generation outages hovered around 37 GW, also higher than August 2022’s average of 33 GW. MISO issued operating notices about system stressors on more than half the days in the month.

The average price of natural gas and coal fell to $2/MMBtu during the month from $8/MMBtu a year earlier, causing real-time LMPs to drop to $33/MWh from $87/MWh last year.

MISO also recorded a 3.3-GW all-time solar generation peak Aug. 31, when panels supplied about 4% of total load around midday.

MISO will review the late August maximum generation event and the reasons behind it with stakeholders at its Oct. 3 Reliability Subcommittee and again at its Oct. 5 Market Subcommittee.

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DOE: Public-private Partnerships Key for Deploying Clean Tech at Scale

WASHINGTON ― For the U.S. — and the world — to cut greenhouse gas emissions to net zero by 2050, “we need in the next 27 years to transform the global economy on a size and scale that’s never occurred before in human history. That’s your charge,” White House Senior Adviser John Podesta told an audience of several hundred clean tech innovators and entrepreneurs at Deploy23 on Tuesday.

Podesta was one of a stream of administration officials and industry leaders speaking at the two-day event, aimed at fostering the deep public-private partnerships, innovation and private investment needed to scale clean energy technologies and curb the impacts of climate change.

The Inflation Reduction Act (IRA) and Infrastructure Investment and Jobs Act (IIJA) have provided unprecedented billions to incentivize clean energy investment, said Jigar Shah, director of the Department of Energy’s Loan Programs Office (LPO), which is dispensing a good chunk of those dollars in the form of loans to clean tech companies.

The LPO co-sponsored the event — officially Demonstrate Deploy Decarbonize 2023 —­ with the nonprofit Cleantech Leaders Climate Forum.

“We have an extraordinary group of companies who really are showing ambition” to fully use the opportunities in the two laws,” Shah said in a Wednesday interview with NetZero Insider. The problem is that “the United States is not known for the quality of its public-private partnerships.”

“The U.S. is sort of like — ‘we just signed a one-time contract, and we hope we thought of everything because revisiting the partnership every year is not our jam,’” he said. “We need to learn how to do things better and smarter.”

Energy Secretary Jennifer Granholm | DOE

Critical to those better relations is the effort of Energy Secretary Jennifer Granholm in recruiting a cadre of energy industry leaders — like Shah, a serial entrepreneur and investor before heading up the LPO — who have cultivated a more business-friendly vibe at the agency.

“The private sector has heard that DOE wants to hear their opinions and is willing to be responsive to what they have to say,” Shah said. One example: The event featured several “Deploy Dialog” sessions, involving industry roundtables that were by invitation only and closed to reporters.

In a prerecorded message, Granholm stressed the central role of industry-government partnerships. The U.S. has a “not-so-secret weapon, which is a government that doesn’t think it alone has all the answers, and business that prides itself on problem-solving,” she said.

“It’s about more than just [research and development],” she added. “We are harnessing the potential of American industrial strategy — clear-eyed cooperation instead of blind heavy-handedness.”

At the same time, those partnerships will need to be built on “developing and embedding a culture of net-zero innovation in the marketplace,” said Anne Slaughter Andrew, chair of Cleantech Leaders Climate Forum, in a Wednesday morning keynote.

“Incrementalism doesn’t work; we have to go big. And what does this mean?” Andrew asked. “It’s not just encouraging the disruptive, new clean-tech companies and startup entrepreneurs. Legacy companies and institutions also must adjust, repurpose and realign their mission and their goals to coexist in a vibrant and integrated culture of innovation that is aimed at net-zero greenhouse gas emissions.”

“Change is no longer a decadeslong process. In fact, with the advent of AI-inspired research, change will happen continuously and faster than ever before,” she said. “Net-zero innovation has to become a core competency for every business, from startups to legacy corporations.”

Getting to ‘Fast Follow’

The figures have become a standard part of almost any energy-related presentation by a DOE or White House official. The various incentives and tax credits in the IRA and IIJA — more than $400 billion in total — mean the American clean-tech market is “wielding an economic bazooka,” Granholm said.

White House Senior Advisor John Podesta | © RTO Insider LLC

In the 13 months since President Joe Biden signed the IRA, about $150 billion in new private investments in clean energy manufacturing has been announced in red and blue states across the country, Podesta said.

“On top of that, utilities have announced more than $120 billion for clean energy generation, and over the last year, 4% of our total investment in structures, equipment and durable consumer goods was in clean energy,” he said. “That’s more than double what it was four years ago.”

But according to Jonah Wagner, the LPO’s chief strategist, the country still is lagging behind the $300 billion per year in private investment needed to meet Biden’s climate goals ― a 100% decarbonized grid by 2035 and net zero economywide by 2050.

The LPO itself has applications in for $143.9 billion in loans, 90% of which are for “mature technologies,” such as electric vehicles, batteries, solar and wind, Wagner said.

On Thursday, for example, the office announced it had finalized a $3 billion partial loan guarantee to Sunnova Energy Corp. for a project that “will make distributed energy resources (DERs), including rooftop solar, battery storage and virtual power plant (VPP)-ready, consumer-facing software, available to more American homeowners.” The loan is the U.S. government’s largest single investment in solar, and its first in virtual power plants, the announcement said.

But the projects LPO has in the pipeline are “weighted about 60-40 towards the emerging technologies that are proven but have not yet achieved commercial development,” Wagner said.

“We need all of these technologies to scale … through 2030 if we’re going to hit and achieve our goals, and … we need the private sector to lead,” Wagner said. “We need all of us in this room to work together to figure out how we’re going to get there.”

DOE officials highlighted the agency’s Pathways to Commercial Liftoff series, which includes reports on the barriers to scale and commercialization, and possible solutions, for emerging technologies such as advanced nuclear, green hydrogen and carbon capture.

DOE Under Secretary of Infrastructure David Crane | © RTO Insider LLC

DOE Under Secretary for Infrastructure David Crane, another of Granholm’s industry recruits, said the reports are intended “to get the private sector comfortable with … these maturing technologies by putting the information that we get out into the public domain. … The difference between immature and mature technologies is often access to information.”

The ultimate goal is replicability, Crane said. “We need to create a fast-following wave of private sector investment in these technology areas that don’t depend on federal money, and that needs to be in the trillion-dollar plus [range]. So, triggering that fast-following wave is important … in terms of innovators; that’s where the financiers come in and that’s where the dialog between us is important,” he said.

Crane, Podesta and Shah all talked about the critical role community engagement and community benefit plans will play in getting emerging technologies through the local permitting and approvals for projects essential for commercial scale.

Early engagement backed up by solid economic and community benefits are “how you create durable support for these kinds of policies, so that it doesn’t matter what administration is in place,” Shah said. “The American people continue to believe that we can actually manufacture here, that we can innovate here, that we can export to other countries.”

The ultimate motivation for DOE’s push for public-private partnerships is a shared sense of urgency, Crane said.

“This might be our last great opportunity to bend the curve on climate change while providing safe, affordable and reliable energy to the American public,” he told an auditorium full of industry executives. “So, I’m asking you, whatever you’ve got, I’ve got to have it now.”

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ISO/RTO Execs Talk Reliability and Resource Mix at House Hearing

Senior executives from all seven ISO/RTOs on Thursday discussed how the changing resource mix is impacting reliability during a hearing of the House Energy and Commerce Subcommittee on Energy, Climate and Grid Security.

“The nation is facing an electric reliability crisis and the nation’s grid operators are not equipped to address that alone,” subcommittee Chair Jeff Duncan (R-S.C.) said. “Federal tax subsidies and state policies designed to prop up renewables and EPA regulations targeting coal and natural gas power plants continue to lead to premature retirement of the nation’s most dependable generation sources. As a direct result, grid operators have issued unprecedented warnings and pleas to conserve energy and prepare for blackouts.”

Democrats also seek to maintain reliability and keep electricity affordable, said subcommittee Ranking Member Diane DeGette (D-Colo.). Reliability will only become more important as climate change leads to more extreme weather, she said.

“As the impact of the climate crisis grows, reliability may literally be the difference between life and death,” DeGette said. “Losing power during extreme heat or extreme cold events is life-threatening. And so, we must ensure that we have the assets and infrastructure to ensure reliability even as the climate changes.”

Need for Planning

A common theme across most of the ISO/RTO testimony was that while the transition toward more renewables and generally a cleaner grid presents new reliability challenges, they can be overcome with enough planning.

“This is a monumental task, and it requires four critical pillars to provide a robust foundation for the transition,” said ISO-NE CEO Gordon van Welie. “New England will need to add significant amounts of clean energy, ensure we have sufficient flexible resources to balance the renewable energy, ensure that we have sufficient backup energy for those periods when renewables cannot perform and … further build out the region’s transmission infrastructure.”

New England was not alone in that perspective, with MISO Senior Vice President Todd Ramey testifying that the grid operator has seen no-carbon resources like wind go from 0% of its generation in 2005 to 25% today. He said the trend has been accelerating lately and MISO expects 85% of its generation will be from wind, solar or battery storage by 2040.

“The growth in weather-dependent resources has occurred in parallel with the retirement of significant amounts of dispatchable generators, primarily coal, gas and nuclear resources,” Ramey said. “These investment and retirement decisions in combination with the different operating characteristics of the new resources versus the retiring resources [have] reduced the reserve margins in the MISO footprint to the minimum required levels.”

Other markets are looking to the future and worry they might get down to the bare minimum levels of resource adequacy.

ISO-NE appears to have sufficient RA through this decade, van Welie said, with a look ahead to 2027 showing the system could handle projected demand thanks in part to growth in solar power, which helps even in the winter. The situation becomes more precarious in 2032, but van Welie said that could be handled with proactive planning.

PJM sees the same issues with growing renewables and retiring traditional power plants. Conventional plants not only contribute to resource adequacy, but also provide other grid services, said RTO Senior Vice President Stu Bresler.

“Policies and consumer choices are shifting the grid away from dispatchable emitting generation resources toward resources with little to no carbon emissions, much of which is intermittent generation like wind and solar,” Bresler said. “As generation resources retire, competitive markets have in the past and will continue to work to incentivize replacement generation.”

The market helped replace tens of thousands of megawatts of retiring coal plants with natural gas-fired units in recent decades and Bresler said that experience could be repeated with the shift to renewables; for now, the RTO has a healthy reserve margin of about 20%. That could be complicated by rising demand growth from data centers and longer-term issues such as electrification, coupled with a rapid retirement of additional dispatchable power plants due to federal and state policies.

Renewables are coming online, but at a slower pace than retirements, and they often lack the kind of critical services traditional power plants produce, Bresler said.

Ramey said MISO has about 50 GW of resources with approved interconnection requests that are, on average, running about two years behind schedule.

Developers of those projects have told MISO that many have run into supply chain issues and delays in the permitting process, he added.

‘Greater Coordination’

While most grid operators pointed to the reliability challenges around the timing of the changing resource mix, Neil Millar, CAISO vice president of transmission planning and infrastructure development, noted one of the issues those clean energy policies are seeking to address.

“Our reliability challenges have been primarily impacted by the wider range of extreme weather events that are largely attributable to climate change,” Millar said.

The rest of the Western Interconnection has been dealing with that same issue, but CAISO and other balancing authorities in the region have been able to support each other and make it through challenging conditions with relatively minor disruptions to service.

“Beyond greater coordination in resource commitment and dispatch to support transmission operations, significant opportunities also exist to coordinate resource adequacy programs, resource planning decisions and deployment of transmission infrastructure across the western region,” Millar said. “Working collaboratively with our partners in the West will allow us to unlock these opportunities for the benefit of customers.”

The grid’s transition has also left it more dependent than ever on the natural gas system. Rep. Frank Pallone (D-N.J.), ranking member of the full committee, asked whether the executives testifying supported the idea of a mandatory reliability regime for natural gas.

“I think it’s imperative that we have better oversight of the reliability of the gas system,” van Welie said. “Because I think we should stop thinking about these systems as independent of each other. They’re totally interdependent, and what impacts the one system will impact the other. So, I sort of find it ironic that we’ve got all of this oversight of the electric system as a result of the 2003 blackout, but the biggest single source of energy to the electric system doesn’t have comparable oversight.”

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House E&C Members Grill HECO CEO About Maui Fires

Members of the House Energy and Commerce Committee’s Oversight and Investigations Subcommittee spent nearly two hours Thursday grilling Hawaiian Electric Co. (HECO) CEO Shelee Kimura on her company’s response to last month’s deadly wildfires on the island of Maui but had to accept deferred answers to many of their questions.

Hawaiian Electric CEO Shelee Kimura | U.S. House of Representatives

Kimura was joined for the hearing by Hawaii State Energy Office Chief Energy Officer Mark Glick and Hawaii Public Utilities Commission Chair Leodoloff Asuncion Jr. However, much of the focus of the hearing was on Kimura and her company, which has been accused of contributing to the fires — if not starting them outright — by neglecting required maintenance and by failing to power down its power lines and other electric equipment despite warnings of fire risk from the National Weather Service.

The Maui fires began Aug. 8 and have burned more than 3,000 acres on the island, including the historic town of Lahaina. According to Maui County’s latest update last week, the Lahaina fire was 100% contained, the Kula fire was 96% contained and the Olinda fire was 90% contained. Last month, estimates of the death toll stood at 113, but that number has been revised down to 97.

HECO and parent company Hawaiian Electric Industries are facing several lawsuits over their alleged role in the fires. Plaintiffs include the company’s shareholders, Maui County and residents of the island; several of the suits are seeking class-action status. (See Hawaiian Electric Faces Multiple Lawsuits over Wildfires.)

Questions About Handling of Risk

Throughout Thursday’s hearing, committee members pressed Kimura to explain HECO’s actions on the day the fires began and how the utility responded to the disaster, but the CEO repeatedly claimed not to recall specifics of the day’s events. Asked by subcommittee Chair Morgan Griffith (R-Va.) about HECO’s awareness of high winds Aug. 8, Kimura said the utility was aware of forecasts predicting 35-45 mph winds but could not recall when or if HECO learned the wind was gusting up to 80 mph. She promised to provide the information to the committee later.

Rep. Morgan Griffith (R-Va.) | U.S. House of Representatives

Griffith compared the weather situation to officials in his home state preparing for snowstorms, noting that “even before the first flake drops, if they see significant weather, they shut the school systems down.” He reminded attendees that a downed power line was known to have ignited a fire near Lahaina the morning of Aug. 8 — although, as Kimura pointed out, this fire was marked extinguished by firefighters and the main Lahaina fire started hours later — and asked Kimura about HECO’s readiness.

“Already, because of the invasive plants, because of the wooden poles, because the lines weren’t insulated, [the area] was at risk,” he said. “These are all risks that were known — what was the decision-making process not to de-energize or turn the power off on these lines during that critical period?”

Kimura attempted to begin her answer with a reference to HECO’s creation of its wildfire mitigation plan in 2019. Griffith cut her off, saying that while he appreciated the “history” he was “trying to figure out what happened that day back in August.” However, the chair relented when Kimura explained that the decisions about whether to de-energize “were made years before as part of … our protocols,” when HECO concluded that a public safety power shutoff (PSPS) program such as those in California would not work in Hawaii’s “very unique” conditions and implemented “other protocols.”

Griffith asked if the utility would be reconsidering those protocols and possibly creating a PSPS program in light of the fire. Kimura conceded that HECO was “absolutely reexamining our protocols” but reiterated that the cause of the afternoon fire in Lahaina still has not been determined. She also reminded Griffith that the lines in the area were not energized when the afternoon fire started; however, when he asked how long the lines remained a danger to the public after shutoff, she again could not provide the answer, promising to supply it to him later.

Wildfire Protocols Questioned

Asked by ranking member Kathy Castor (D-Fla.) for more detail on HECO’s wildfire protocols, Kimura said they included disabling the setting that would automatically reclose a circuit in the event of a fault, so lines would not re-energize. Castor asked how quickly the utility implemented this protocol after becoming aware of the wildfire risk; Kimura said she could not recall specifically but believed it happened the morning of Aug. 8.

Kimura also could not recall when she first learned the line in the Lahaina area was down. Asuncion told Castor he was informed of fallen lines “basically on the afternoon of the 8th.”

Energy and Commerce Committee Ranking Member Frank Pallone (D-N.J.) asked Kimura about HECO’s participation in Maui County’s investigation into the fires. Noting that “it’s still important for the fire investigators to determine the role of these power lines,” he asked if the utility planned to cooperate with investigators. Kimura said HECO was “fully cooperating,” as well as running its own investigation.

Pallone followed up on her response, asking if HECO would commit to make the results of its investigation public. Kimura said only that the investigation would “take many months to get done” and that she was “sure that there will be more to talk about once we know the results.”

“Is there any reason why you wouldn’t make it public? You seem to be hesitating a little bit,” Pallone said.

“I think it’s just too early to speculate on what that is going to look like in the future,” Kimura replied. “We’re very focused on finding out what happened there, [and] to make sure that it never happens again.”

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ERCOT Technical Advisory Committee Briefs: Sept. 26, 2023

ERCOT stakeholders on Tuesday approved a protocol change to the minimum state of charge (SOC) for energy storage resources participating in two of the grid operator’s ancillary services.

Staff are proposing to change the minimum SOC requirements for ERCOT contingency reserve service and nonspinning reserve service to slope from the full hourly amount of MW down to zero at the end of the hour. ERCOT says this will resolve the nodal protocol revision request’s “stranded energy” issue during scarcity conditions, which caused the Board of Directors to remand it back to the Technical Advisory Committee.

The directors sent NPRR1186 back to the committee during its August meeting, asking staff and members to address stranded energy associated with the proposed minimum SOC requirements for ECRS and non-spin during scarcity situations. The measure is seen as a stopgap until real-time co-optimization is added to the market in several years. (See “NPRR1186 Remanded to TAC,” ERCOT Board of Directors Briefs: Aug. 30-31, 2023.)

Dan Woodfin, ERCOT | ERCOT

“I think it solves the problem we were asked to solve,” Dan Woodfin, ERCOT’s vice president of system operations, told TAC on Tuesday.

However, Woodfin said ERCOT is concerned that a battery participating in nonspin may by completely discharged for future hours and not be able to charge as needed. He said staff will recommend to the board that more NPRRs be drafted to add compliance and financial penalties related to failures to provide ECRS or nonspin under a mechanism that applies to other resources.

“We’ve got to make sure that we’re enforcing the right level of compliance around that,” he said. “Potentially, we would disqualify resources for repeated failure to perform or if they don’t perform when they’re deployed during a grid emergency or other event. We’ll put a little more structure around it before then.”

Woodfin said the change to failure-to-provide would only add “additional consideration that are the unique technical characteristics of batteries.” He promised fleshed-out NPRRs for the board’s December meeting.

Public Utility Commissioner Jimmy Glotfelty called into the meeting to gently dispute Woodfin’s contentions. He said ERCOT staff are “barking up the wrong tree,” and he encouraged them to think differently about the issue.

“You want to control when you want to control them … which is you want [batteries] to look like a coal plant,” Glotfelty said. “If you’re doing these penalties associated with this, why do you even need to know the state of charge? You’re putting bootstraps and suspenders on something that is not necessary, because the penalty structure within ERCOT will be enough for the market to solve this problem.”

Woodfin responded that ERCOT doesn’t want to “just assess whether someone has the capability of providing the service when we actually need it.”

“We’re spending a whole lot of time and effort on an interim measure that should be resolved with [real-time co-optimization],” Glotfelty said. “You’re not going to get any more reliability about the fact that whether you know a state of charge or not, and it’s discriminatory. So y’all can go about your process, but as it comes down to me at the commission, that’s where I stand.”

Baker Botts attorney Juliana Sersen, representing storage developer Eolian, reiterated her client’s stance opposing NPRR1186 in its current form. Eolian has been joined by other storage developers in pushing back against the measure.

“Even if the battery does not fail to provide or if the battery’s [qualified scheduling entity] moves its ancillary service resource responsibility to another resource, we continue to believe that such compliance metrics are unnecessary and discriminatory,” she said.

TAC endorsed the NPRR in a 29-1 vote. Competitive retailer AP Gas & Electric was the lone member to vote against the motion.

IBR Change Set Aside

The committee agreed with ERCOT staff to table a nodal operating guide revision request after Woodfin said the version approved by a TAC subcommittee does not resolve the reliability risk as originally intended.

“We feel that additional data would be helpful to further consideration by TAC and the board,” he said. “We want NOGRR245 to include requirements that improve the reliability of the system, maintain the current reliability … but do so in a way that’s technically feasible and that we’re not asking folks to do things that they just technically cannot do.”

Staff said they intend to issue requests for proposals to inverter-based resources (IBRs) and the original equipment manufacturers to provide comments for TAC’s Oct. 24 meeting.

The NOGRR would replace the current voltage ride-through requirements for intermittent renewable resources (IRRs) with IBRs’ ride-through requirement. The change would be consistent with or beyond requirements identified in the new Institute of Electrical and Electronics Engineers (IEEE) standard for IBRs’ interconnection and interoperability.

Eric Goff, holding NextEra Energy Resources’ proxy for much of the discussion, urged TAC to consider changing the compliance date for new resources to earlier than 2024 while providing some exceptions based on details to be determined. He also called for tightening up the technical feasibility sections.

“We’re happy to work on additional changes,” he said.

“I always believe we come up with a better product when we work together,” ERCOT’s Stephen Solis said.

LP&L’s Final Transition Delayed

Oncor’s Debbie McKeever, chair of the Retail Market Subcommittee, told TAC the final 30% of Lubbock Power & Light’s load, about 201 MW, is on track for a mid-December transfer into ERCOT.

The transfer hinges on FERC’s approval of a settlement agreement between LP&L and Xcel Energy subsidiary Southwest Public Service Co. (SPS), which has long held a contract to serve the city’s load.

Last month, an administrative law judge certified an uncontested settlement offer between LP&L, Xcel, Golden Spread Electric Cooperative and several New Mexico cooperatives. LP&L and SPS agreed to pay the cooperatives $6.38 million, while the Lubbock utility will pay SPS either $77.5 million in a lump sum or six annual installments of $14.95 million for early termination of a partial requirements agreement (ER23-1144).

The commission is expected to rule on the settlement by early December.

LP&L moved 70% of its load out of SPP in 2021, six years after it announced its intentions to join ERCOT’s competitive market. Texas regulators approved the transition in 2018. (See Six Years in the Making: LP&L Migrates Load to ERCOT.)

RTC+B Group Gets Leadership

The TAC’s unanimously approved combination ballot resulted in the approval of leadership for the Real-time Co-optimization + Battery Task Force. ERCOT’s Matt Mereness will chair the group, and CPS Energy’s David Kee will be vice chair.

The ballot also included tabling a planning guide revision request (PGRR105) that would add DC tie resources to the list of resources required to meet the minimum deliverability condition and the 2023 major transmission element list.

It also included one NPRR and a system change request (SCR) that, if approved by the board, would:

    • NPRR1184: clarify ERCOT’s management of the interest it receives and is owed to counterparties for posted cash collateral and require staff to credit counterparty collateral accounts for interest every month. The NPRR also requires ERCOT to report the interest calculation.
    • SCR824: increase the attachment file size and quantities allowed within the resource integration and ongoing operations system.