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November 8, 2024

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Dominion Energy Seeks Approval for Long-duration Storage Pilot

Dominion Energy on Monday asked Virginia’s State Corporation Commission (SCC) to approve a long-duration energy storage pilot project that it said would greatly increase the amount of time batteries can discharge power to the grid.

The utility wants to install two storage facilities at its Darbytown Power Station, a natural gas plant in Richmond. One will test zinc-hybrid batteries from Eos Energy Enterprises, and the other will test iron-air batteries developed by Form Energy that can discharge for up to 100 hours, compared to the average of just four hours for most standard lithium batteries on the market.

“We are making the grid increasingly clean in Virginia with historic investments in offshore wind and solar,” Dominion Energy Virginia President Ed Baine said in a statement. “With longer-duration batteries in the mix, this project could be a transformational step forward, helping us safely discharge stored energy when it is needed most by our customers.”

The SCC needs to approve the project, as does Henrico County. If approved on time, construction would start by late next year, and the two battery systems would be operational by late 2026.

Virginia’s Grid Transformation and Security Act of 2018 directed the development of battery storage pilot programs. Dominion has built three already in other parts of the state and has another three under development.

The proposal comes as Dominion is working to develop the largest offshore wind project in the country and continues to expand the second-largest fleet of solar panels in the country.

The batteries are meant to help improve the integration of renewable resources and cut the need for additional generation during times of high demand. Dominion also is seeking approval of two other battery projects; if the SCC authorizes them all, it will have 28.34 MW of batteries on its system, compared to 16 MW now.

Dominion evaluated proposals from more than 30 companies and picked Eos and Form because they have paths to commercial viability, as well as safety, the supply chain, efficiency and support from investors, it told the SCC.

Form’s iron-air battery is a 4.94-MW/494-MWh AC multiday system, while Eos’ zinc-hybrid is 4 MW/16 MWh.

“These technologies are expected to have lower thermal runaway risks than lithium-ion energy storage currently presents,” Dominion said in its application. “Additionally, recent history has shown significant pricing volatility and supply chain constraints for lithium-ion battery materials that could cause limits to the energy storage buildout plans.”

Competition for the raw materials for lithium-ion batteries with the vehicle market is getting increasingly fierce, which will significantly increase price volatility. The grid also is going to need long-duration energy storage to help balance the growing share of intermittent resources, Dominion said.

The Form system is made up of 128, 37-foot containers, while Eos’ is made up of 39, 17-foot containers. The two facilities also will require about 10 inverters and two transformers. Despite covering a total of 435,600 square feet, Dominion said the project will be largely hidden from neighbors on the existing plant’s site, so it does not present any environmental justice issues.

Form’s battery is made of iron, water and air. It works by using “reversible rusting.” While discharging, it takes in oxygen from the air and converts metal iron to rust, and while charging, the application of an electrical current converts the rust back to iron, and oxygen is released.

“We are pleased to partner with Dominion Energy on the innovative Darbytown Storage Pilot Project and look forward to delivering a 100-hour iron-air battery system that will enhance grid reliability and provide Dominion’s Virginia customers with access to wind and solar energy when and where it is needed over periods of multiple days,” Form CEO Mateo Jaramillo said.

Eos’ system can operate in three- to 12-hour discharge configurations. During charge and discharge, ions move through electrolytes to their respective electrodes to donate or accept electrons, creating a current flow through the battery’s bipolar stack.

“We are proud to have been selected for this critical project. Dominion understands that meeting our future energy needs requires multiple storage technologies,” Eos CEO Joe Mastrangelo said. “We’re excited to show Dominion how well our zinc-hybrid batteries perform.”

Dominion is asking to spend about $70.6 million on the project. That works out to $7,897/kW, which is a premium compared to the $1,325/kW standard batteries cost, according to U.S. Energy Information Administration data used in its 2022 Annual Energy Outlook, the agency’s most recent.

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Weatherization Practices Paying Off in Texas

The Texas Public Utility Commission’s executive director last week praised the efforts of the state’s regulatory agencies to push utilities to weatherize their facilities following the disastrous 2021 winter storm.

Speaking during the Texas Reliability Entity’s annual winter weatherization workshop, the PUC’s Thomas Gleeson said both the PUC and the Texas Railroad Commission (RRC), which regulates the intrastate natural gas and oil industry, have approved orders that have strengthened the electric grid and gas infrastructure against extreme weather.

“If you look at the acute onset issues that happened during Winter Storm Uri and also what you saw some of during Winter Storm Elliott, those mitigation tactics have worked,” Gleeson said during the Sept. 13 workshop. “We’ve performed better, and I think we can all agree that as we continue to learn more, we’ll continue to iterate all those rules to ensure that the grid remains reliable and resilient and progresses even further.”

The two commissions have added winter and summer weather preparedness standards for the utilities they regulate and have followed up with inspections to ensure compliance. ERCOT has inspected more than 1,100 generation resources and transmission facilities before the past two winters. Gleeson said only four inspected sites were forced offline or derated during Elliott.

Inspections for summer preparedness began in June. Gleeson said about 500 inspections of generation and transmission sites will be conducted and a final report issued in October.

Mysti Doshier, the RRC’s assistant director of critical infrastructure, said a “majority” of operators have achieved compliance at more than 99% of facilities when they were inspected. More than 99% of violations were resolved within 30 days.

A 28-year veteran with the RRC, Doshier said the department had four employees when she joined in 2020. It now has 99, two-thirds of whom are inspectors.

“Just like with you guys, whenever you’re talking about the amount of critical facilities or critical components that you had to identify,” she said, addressing her audience, “that’s the same thing with us. We go out to an oil lease and there’s 100 wells. … the critical components that we actually inspected were probably upwards of 30,000. We’ve got a great group of folks. These folks took on the challenge and they’ve done a really fantastic job.”

“There’s always something to be learned about how we operate in extreme conditions,” the Texas RE’s chief engineer, Mark Henry, said. “We saw, not unexpectedly, a number of unit issues much, much lower than what we saw in Uri, which is testament to the effectiveness of the actions that have been taken since … Uri.”

Henry said NERC’s recently revised guidelines for generation units’ winter readiness include a collection of recommended industry practices. Incorporating those practices is strictly voluntary, he said.

The PUC has added a rule this year for additional emergency preparation measures “reasonably expected to ensure sustained operation” at the 95th percentile minimum average 72-hour wind chill value, effective Dec. 1. That rule is stronger than NERC’s draft reliability standard (EOP-012-1) that requires generators with a commercial operation date after the standard’s effective date to use freeze-protection measures capable of the unit’s continuous operation for at least 12 hours.

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NY Policy Council Holds Inaugural Meeting to Discuss CGPP

New York agencies revealed updated modeling Tuesday indicating the state in 2050 could have a roughly 2 GW higher peak load but 4 TWh lower annual load than previously predicted (20-E-0197).

The Energy Policy Planning Advisory Council, which represents every energy sector and acts as an advisory board to the Public Service Commission, held its first stakeholder meeting to discuss the Joint Utilities’ updated Coordinated Grid Planning Process and begin to implement the state’s net-zero Climate Leadership and Community Protection Act.

The CGPP seeks to align New York’s transmission system development with its emissions reduction goals, while attempting to control costs and speed up processes as the state ramps up its energy production and consumption. The PSC kicked off this two-year, six-stage planning process after approving the CGPP in August. (See NY Creates Coordinated Grid Planning Process.)

While the PSC will finalize the CGPP’s framework, the EPPAC plays a key role in shaping the direction of the state’s grid planning by providing recommendations.

The Department of Public Service and the New York State Energy Research and Development Authority staff presented updated results from the integration analysis, showing 2050 peak load would increase roughly 55% and annual load increase 90% over 2020 levels.

NYSERDA’s IA is an economywide assessment supporting CLCPA implementation by modeling proposed emissions reduction and mitigation strategies and since has been modified to include updated reports from the Department of Environmental Conservation, as well as new sensitivity assumptions.

The updated outcomes show no significant impact on key topline cost and benefit metrics, but they do show some notable differences in predicted outcomes, including that New York’s economywide electrification is driving higher peak loads but that these are offset by efforts to decarbonize the building and transportation sectors.

These offsets are seen in the modeling through greater representation of building heating upgrades, increased electric vehicle infrastructure and better accounting of the effective load carrying capacity provided by certain renewables.

The IA has modeled only Scenario 2 of NYISO’s System and Resource Outlook, but staff emphasized this work is ongoing and they would return with more results from other modeled scenarios to help bound their assessments.

The CGPP has six stages, and the EPPAC is aligning multiple scenario forecasts and climate policy objectives, with the assumptions necessary to effectively develop its predictive modeling.

Elizabeth Grisaru of the DPS noted that the EPPAC operates on a tight timetable, with final CGPP recommendations due to the PSC for review July 1, 2025.

Therefore, the EPPAC is poised to meet twice a month with stakeholders to continue discussions.

Q&A

Stakeholders at the meeting had questions about both the updated CGPP modeling and staff’s presentation.

A common theme centered on how resources like hydrogen, dispatchable emission-free resources and energy storage were treated in the CGPP’s modeling and whether assumptions for these technologies were CLCPA-compliant.

Raya Salter, executive director of Energy Justice Law and Policy Center, said she worried staff were getting ahead of the PSC in determining “what should and shouldn’t be considered zero emissions” and wondered if the modeled level of hydrogen penetration is consistent with the CLCPA. The PSC is debating what resources can assist the state in achieving its net-zero goals. (See Contentious Commentary on Zero-Emissions Path in NY.)

The IA models hydrogen as green hydrogen, meaning produced cleanly through electrolysis, but some attendees said they worried about whether the role of hydrogen was being overvalued in the modeling, in lieu of other renewables.

Nick Patane, senior project manager at NYSERDA, responded to this and similar hydrogen questions by clarifying that the model assumes 50% of hydrogen production occurs in-state and the other half is imported. He added that the IA models hydrogen as green hydrogen, meaning it is produced only cleanly through electrolysis.

Erin Hogan of the state’s Utility Intervention Unit and William Acker, executive director of the New York Battery and Energy Storage Technology Consortium, had questions about DEFRs, and its related technologies, and whether these resources are being modeled correctly.

Hogan asked whether the IA accurately predicts the expected lifetime of certain intermittents, such as batteries, and if they are modeled in the state’s future transmission system according to their expected lifetime. “We need to find a Goldilocks solution: We don’t want to build too much, but we don’t want to build too little, and we want to build it in the right place,” she said.

Following this theme of nuanced transmission planning, Acker noted it’s critical to accurately model DEFRs, since certain classes of these resources have different effects on the transmission and distribution system that must be accounted for when deciding where to install new resources or make system upgrades.

Kevin Steinberger, director of E3, which developed the modeling, responded that its model was built to be flexible to account for those resources, but added that his team has been comparing notes with NYISO to ensure compatibility.

Other stakeholders asked about the CGPP’s modeling itself: how it was built, what its long-term implications for the state’s climate goals are and whether more inputs would be added.

Hogan asked about the continuation of transmission costs and benefits beyond the model’s study period.

Jason Frasier, senior manager of transmission planning at NYISO, responded that the ISO’s Outlook, which is where the CGPP’s modeling scenarios are pulled from, does not explicitly model beyond its study period but does have a perpetual setting that assumes the metrics from the final year are carried onward.

Hogan and others also asked if more scenarios would be added to IA, which staff confirmed was the case and that two more scenarios would be included in the CGPP’s modeling, as well as other market sensitivities.

One final concern expressed throughout the discussion was the need for transparency and stakeholder collaboration.

Stakeholders sought to ensure they would be contributing meaningfully to the final CGPP product, and staff promised to ensure transparency where possible, though they did cite some instances where issues related to confidentiality may make this difficult, particularly as it relates to generator retirements.

Staff added that a dedicated EPPAC website would be created to make locating relevant materials easier.

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Treasury Issues Principles for Net-zero Financing, Investment

The U.S. Treasury Department on Tuesday published guidance for private-sector financial support of net-zero initiatives.

“Principles for Net-Zero Financing & Investment” is a collection of voluntary best practices for financial institutions that promotes consistency and credibility.

Treasury is using the principles to support mobilization of private-sector capital to address the effects of climate change and accelerate the green energy transition.

The agency said government plays a role in accelerating the transition, but the private sector will need to provide increasing amounts of capital and expertise to make it happen.

The nine principles center on Scope 3 greenhouse gas emissions — those indirectly included in a company’s value chain, typically the largest type of emissions for financial institutions.

The first principle reads:

“A financial institution’s net-zero commitment is a declaration of intent to work toward the reduction of greenhouse gas emissions. Treasury recommends that commitments be in line with limiting the increase in the global average temperature to 1.5°C. To be credible, this declaration should be accompanied or followed by the development and execution of a net-zero transition plan.”

The other eight principles drill down on ways to carry out these commitments, from transparency to environmental justice to credible metrics and targets.

Treasury Secretary Janet Yellen expanded on this point later Tuesday in remarks to the Bloomberg Transition Finance Action Forum in New York City.

“There is extensive evidence showing that the changing climate has significant financial impacts,” she said. “Without considering these factors, financial institutions risk being left behind with stranded assets, outdated business models and missed opportunities to invest in the growing clean energy economy.”

Counterpoint

As Treasury published its guidance Tuesday, Climate Impact Partners published a less-rosy picture of progress.

In its fifth annual report on the subject, the carbon reduction market company found that not one of the Fortune Global 500 Companies increased its 2030 climate commitments last year.

Only 3% added 2050 commitments and 34% remain without climate commitments of any kind, the study reported.

There were some bright spots: More than 75% of companies now report emissions, and those that do report emissions earned a bit more in 2022 profits than those that do not.

Operational emissions of companies with a target in 2030 or sooner decreased 7% in 2022, compared with a 3% increase for companies without a target.

“The lack of climate commitments from some of the world’s largest companies is concerning as we get closer to 2030,” Climate Impact Partners CEO Sheri Hickok said in announcing the study. “At this critical juncture, we need companies to lean in, not pull away. The good news is that we have found clear markers for the companies making the most positive impact on emissions today, serving as an example for others to follow.”

The companies tracked are the largest 500 companies in the world — realizing $41 trillion in 2022 revenue, employing more than 70 million people and accounting for more than a third of the world’s gross domestic product.

As such, they hold significant influence on suppliers, customers, other businesses and governments, Climate Impact Partners wrote.

As the organization was preparing its report, 22 attorneys general from Republican states were taking steps that could discourage concerted emissions-reduction efforts as potentially illegal.

Tennessee Attorney General Jonathan Skrmetti sent a letter requesting information from signatories to the Net Zero Financial Providers Alliance emissions reduction commitment.

This may violate state and federal laws including antitrust and consumer protection statutes, Skrmetti wrote on Sept. 13.

Although many signatories are direct competitors, “they nevertheless commit to using their market influence to enforce their collective climate agenda in the broader economy and to ‘[w]ork in coordination’ with other UN-convened ‘Net Zero’ groups. Further, these pressure tactics are backed up by substantial market power,” he wrote.

A disclaimer included in the NZFPA commitment — “The parties making this Commitment do so subject to any legal, regulatory, professional standards and professional or ethical obligations that apply to them” — does not alleviate the concerns of the attorneys general, Skrmetti wrote.

Also signing his letter were the top legal officials of Alabama, Alaska, Arkansas, Idaho, Indiana, Iowa, Kansas, Kentucky, Louisiana, Mississippi, Missouri, Montana, Nebraska, New Hampshire, Ohio, Oklahoma, South Carolina, Utah, Virginia, West Virginia and Wyoming.

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MISO Postpones Meeting for More Analysis on Entergy Expedited Substation Work

MISO announced it’s pushing back a scheduled meeting to discuss three new substations proposed by Entergy for expedited treatment in the RTO’s annual planning cycle.

The grid operator said it needs the pause to conduct more analysis on the trio of expedited projects to serve new load interconnections near Jackson, Miss., before it can recommend the projects move ahead.

Entergy proposed three new substations for the fast-growing industrial area of Madison County in August. It sought MISO go-ahead to build two new 230-kV substations to serve 267 MW in load apiece and a 500/230-kV substation to cover 537 MW in new load.

Entergy wants to bring the 230-kV substations online by early 2025 and 2026. The utility envisions the 500/230-kV substation to be operational by mid-2027.

But MISO said the “size and complexity” of the new projects means it was forced to postpone its Sept. 22 South Technical Study Task Force meeting, where it was due to discuss study results with stakeholders. MISO studies expedited project requests for adverse impacts on its system.

MISO said its review uncovered transmission issues were the proposed substations to be built. The RTO said its expansion planning team now must work with affected transmission owners to resolve the issues and said it will schedule a new task force meeting once it can complete its review.

MISO has been fielding numerous and more complex out-of-cycle requests for projects that can’t wait to begin construction until the early December approval typically reserved for the MISO Transmission Expansion Plans (MTEPs).

The grid operator has said the surge in expedited project review requests means it needs to modify its expedited study procedures so its planners won’t be overwhelmed. (See MTEP 23 Catapults to $9.4B; MISO Replaces South Reliability Projects.)

MISO also said it expects load growth driven by large industrial and commercial interconnections to continue for the foreseeable future. (See MISO: Expect More Expensive Annual Transmission Packages.)

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Report Extols the Benefits HVDC Lines Offer the Grid

The U.S. is behind Europe in deploying HVDC transmission technology, according to a report released Tuesday by the Brattle Group and DNV for clean energy and transmission advocates.

“The Operational and Market Benefits of HVDC to System Operations” noted that 300 GW of HVDC capacity has been installed worldwide, with an additional 150 GW in the planning stages, most of it in the last decade. The report was sponsored by the American Council on Renewable Energy, Allete, Clean Grid Alliance, GridLab, Grid United and Pattern Energy Group.

“HVDC transmission has evolved dramatically over the last five to 10 years,” Brattle Group Principal and co-author Johannes Pfeifenberger said on a webinar hosted by ACORE. “HVDC offers higher capacity, longer distance [and] lower loss transmission on a smaller footprint, which really are key advantages.”

Connecting HVDC lines to the standard AC grid requires converters, and the newer voltage-sourced converters, which can be switched on and off by an external control signal — unlike the historically more common line-communicated converters that can only be turned on by an external signal — greatly enhance HVDC’s capabilities, Pfeifenberger said.

Europe has led the way in deploying modern HVDC technology with VSC converters recently, with about 50 GW of projects in operations and another 130 GW planned over the next 10 years. North America accounts for only 3% of the technology’s use and 30% of planned projects, most of which have been proposed by merchant developers.

“It’s pretty straightforward if you want to move power over long distance: DC is a much more efficient way to do that in terms of right-of-way cost and controllability,” said Grid United CEO Michael Skelly, whose firm has proposed a number of HVDC projects to connect the three interconnections.

In the mid-2000s, when Texas was considering the Competitive Renewable Energy Zone lines to bring wind power to market, they considered HVDC; Skelly said now there might be a “little bit of buyer’s remorse.” With how much growth ERCOT has seen in recent years, HVDC might make a comeback, he added.

The one domestic market the report highlighted as fully embracing HVDC technology is CAISO, with Pfeifenberger noting that the Trans Bay Cable in the San Francisco area is the first VSC HVDC project in the world.

“Because they were the first operator of a VSC-based HVDC line, the Trans Bay Cable, they really like the technology; they have optimized it into the market; they’re fully co-optimizing controllable transmission with generation in the day-ahead in real-time markets,” Pfeifenberger said. “They’re optimizing transmission across the entire West now. And they are developing a specific way to integrate merchant transmission lines into all this market optimization.”

The report is full of anecdotes about European countries starting to knit their grids together with new HVDC lines. Germany is linking up its wind-rich north and solar-rich south with major projects. Italy, which has HVDC subsea cables connecting Sicily and other islands, is now expanding its use similarly to its northern neighbor. Other examples abound around the continent.

HVDC works better than AC lines when it comes to burying transmission, said DNV Vice President and report co-author Cornelis Plet.

“Whenever power needs to be transported over more than 50 miles by underground cable or maybe 300 to 400 miles per overhead line, HVDC is the only technical, feasible option,” Plet said.

In addition to the ability to be out of sight, HVDC technology also requires a smaller footprint so it can help get transmission built in urban areas where new rights of way are very hard to procure, he added.

Another reason Europe has been building out so many lines is the growth of offshore wind, as DC lines can operate underwater. Now a major question on the continent is whether the HVDC lines should operate as single entities or be stitched together in an HVDC grid that overlays the AC system, Plet said.

One issue with the rapid growth in Europe is supply-chain concerns, as the manufacturing base — while currently sufficient — would be strained to try to meet an uptick in demand from North America as well, he added.

“The U.S. must build a similar project pipeline and, importantly, take advantage of the significant planning and operational experience that has already been gained with modern HVDC systems,” Plet said.

Another hurdle to getting HVDC or other major transmission needed to expand renewable power and address climate change is the current permitting process, said Rep. Sean Casten (D-Ill.), Congress’ chief FERC booster.

The lack of transmission is one of the two main problems with renewables, the other being that it “is too damn cheap,” Casten said on the webinar.

“You’ve generated this problematic resource that is super cheap: Whether it’s wind, whether it’s solar, you have effectively zero marginal cost,” Casten said. “And on the other end of that wire, you have a person or an entity — maybe it’s an RTO, maybe it’s a utility — who has an entire pile of assets that are dependent on earning $50, $60, $70/MWh, and you want to put $30 power into that market.”

That gives the entities who would receive that cheaper power a clear economic disincentive to do so, he added. The politics of defending high prices are not good, so opponents come up with spurious arguments like transmission causes “eagle cancer,” Casten quipped.

Casten and Rep. Mike Levin (D-Calif.) are working on a bill that seeks to be the Democrats’ opening position on transmission permitting. The two are trying to make sure the industry’s profit motive is aligned with transmission expansion to bring renewables to market, get the right participants in the planning process and then smooth out the siting and permitting processes.

“Let’s not make it harder to permit a transmission line than it is to permit a natural gas pipeline, which it is as long as we have only one authority responsible for one of those,” Casten said.

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Champlain Hudson Converter Station Breaks Ground in NYC

Two key pieces of New York City’s clean energy future are taking shape along the East River waterfront.

The converter station for the Champlain Hudson Power Express and the Brooklyn Clean Energy Hub both hosted ceremonial ground-breaking ceremonies in the past week.

Both will play an important role in keeping the lights on in the city, but the need is more pressing for the CHPE facility in the Astoria neighborhood of Queens. NYISO has warned that further delays in the transmission project could worsen the reliability margin deficit the city faces starting in 2025.

Gov. Kathy Hochul (D), U.S. Department of Energy Deputy Secretary David Turk, Premier of Quebec Francois Legault and dozens of other officials gathered Tuesday to mark the start of work on the project.

CHPE is a 339-mile underwater and underground HVDC line that will carry up to 1,250 MW of power generated by Quebec hydropower plants to New York City. After more than a decade of planning and review, construction of the line began early this year.

Now, work has begun on the converter, which will occupy a former fossil fuel site. Six tanks that once held 12 million gallons of No. 6 oil were removed in the weeks before Tuesday’s event, along with nearly four miles of piping.

Hochul said in a news release: “The transformation of a fossil fuel site into a zero-emission facility highlights the world of possibilities we have to reduce our dependence on fossil fuels, mitigate the impact of climate change and accelerate our collective progress of shifting our power grid to go green.”

New York Gov. Kathy Hochul speaks Tuesday at the site of the Champlain Hudson Power Express converter station under construction in New York City. | New York Governor’s Office

CHPE also will move New York state closer to its 2030 goal of 70% renewable power generation and will help fill the gap created by the mandated peaker plant retirements that NYISO has warned will create a deficit.

“The importance of the Champlain Hudson Power Express project to maintaining grid reliability and enabling the transition to the grid of the future cannot be overstated,” NYISO President Richard Dewey said in a news release. “By delivering 1,250 megawatts of clean, renewable hydropower to the New York City metro area, this project plays a key role in the move to electrify the economy and meet the state’s ambitious clean energy goals.”

Seven miles south, in Brooklyn’s Vinegar Hill neighborhood, Con Edison broke ground Sept. 12 on its Clean Energy Hub.

The facility eventually could serve as the interconnection point for up to 1,500 MW of the 9 GW of offshore wind power that New York state hopes to have online by 2035.

But there already is a pressing need for the Clean Energy Hub as a means of maintaining reliability, because the surrounding area is placing greater demand on the grid with electrification of buildings and transportation.

Con Edison expects demand in certain neighborhoods to exceed the existing infrastructure’s capacity by 2028.

“The Brooklyn Clean Energy Hub represents a major milestone in the clean energy transition and will strengthen our grid’s reliability,” Con Ed CEO Tim Cawley said in a news release. “This project will offer a critical plug-in point to connect with offshore wind, while creating good jobs, supporting economic growth and advancing New York’s climate goals.”

The CHPE station stands in an area with multiple fossil-fired generating stations and resulting poor air quality. Con Ed’s Hub also occupies the site of a former fossil-fire facility.

Neighborhood activists cheered the conversions.

Costa Constantinides, CEO of Variety Boys and Girls Club of Queens, said: “Today is a great day for the energy transition away from fossil fuels here in Astoria. For too long our community has borne the brunt of fossil fuel production and the health impacts that have turned our neighborhood into ‘Asthma Alley.’”

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NIPSCO Proposes New Gas Plant; Ind. Consumer Advocate Displeased

Tensions are building over Northern Indiana Public Service Co.’s proposal last week to build a new natural gas peaking plant at its R.M. Schahfer Generating Station.

NIPSCO filed for permission with the Indiana Utility Regulatory Commission (IURC) to install a 400-MW, $643.7 million natural gas plant (45947). According to NIPSCO, the plant would be in service at the end of 2026 and replace two soon-to-be retired coal units at the Schahfer station. The utility intends to transfer the retiring units’ interconnection rights on the MISO transmission system to the new plant.

The utility is also proposing to use construction while in progress (CWIP) ratemaking, which would allow it to start billing customers for the plant prior to construction and commercial operations.

The Citizen Action Coalition of Indiana, an environmental and consumer advocate, says the new plant will be costly, unnecessary and detrimental to the clean energy transition.

Ben Inskeep, program director at CAC Indiana, said NIPSCO’s proposal means it has “backtracked” on its 2018 integrated resource plan, which saw no need for new fossil fuel plants.

“One of the troubling aspects of NIPSCO’s certificate of public necessity and need filing for up to 442 MW of new gas turbines is that it is inconsistent with its current IRP,” Inskeep said in a statement to RTO Insider. “NIPSCO’s 2018 IRP found that no new fossil gas resources were needed. NIPSCO’s 2021 IRP included a preferred plan that has ‘up to 300 MW’ of new gas. However, NIPSCO unilaterally and without stakeholder input conducted additional analyses after it completed its 2021 IRP that it now claims supports its decision to increase its new natural gas capacity by 47% relative to its most recent IRP.”

NIPSCO insists the gas-fired plant is necessary and said its addition was previously contemplated in its 2021 IRP. The utility said by the time it retires all its coal-fired generation in 2028, renewable energy will begin to dominate its energy mix, and it will need a source of flexible generation during peak energy use and extreme weather conditions in the winter and summer.

NIPSCO spokesperson Tara McElmurry said the utility requires a new gas-fired peaker to “support system reliability and resiliency, along with public safety, as part of a cleaner and more balanced energy mix for the future.”

“NIPSCO is committed to creating a reliable, sustainable supply of energy that will serve customers — both now and in the future,” McElmurry said in a statement to RTO Insider. The peaker will run only when necessary and act as a “bridge for the generation gaps of more intermittent energy sources.” She said NIPSCO’s goal to achieve net-zero carbon emissions by 2040 remains unchanged, and it will have the option to convert the plant’s fuel source to hydrogen in the future.

In testimony to the IURC, NIPSCO Vice President of Power Delivery David Walter said he is aware “some stakeholders would prefer that NIPSCO only implement renewable generation resources going forward.” However, he said that is not the most prudent option and that the plant will be “at least partially responsible for unlocking the long-term customer savings that are expected from NIPSCO’s overall generation transition.”

NIPSCO said its need for a peaking plant was emphasized through an updated portfolio analysis this year that “incorporated market shifts and changes” since its 2021 IRP. The utility included the effects of inflation, MISO’s new seasonal capacity market design and availability-based capacity accreditation, passage of the Inflation Reduction Act, and portfolio needs under the clean energy transition.

But Inskeep said NIPSCO shouldn’t be spending “exorbitant sums of ratepayer dollars to build more fossil fuel infrastructure that will hardly ever operate.” He said he is unconvinced NIPSCO needs a “massive expansion of natural gas” and that it did not adequately consider energy storage with grid-forming inverters, demand response or purchases from the MISO markets before it issued a request for proposals for thermal generation only.

NIPSCO maintains that using its existing facilities and some existing equipment at the Schahfer station will save customers money.

Inskeep also said CAC is “highly alarmed at the extraordinary expense” of the new units and the direction NIPSCO is taking on construction and financing.

NIPSCO rejected all three bids in response to its RFP. It was ultimately unable to land on an affordable engineering, procurement and construction agreement with an outside party, and plans to self-build the project.

Inskeep said the self-build prospect is a risky bet for ratepayers. He pointed out that, according to staff testimony, NIPSCO has not ventured into self-building a gas plant before. He also criticized NIPSCO’s plan to use CWIP, saying it is inappropriate for utilities to pass costs onto customers before they even incur them.

“Ratepayers will be paying for the gas turbines before they are used and useful, and even if they never generate any electricity. CWIP has a notorious reputation in utility ratemaking for harming ratepayers by shifting project risk from utility shareholders onto ratepayers,” Inskeep said.

NIPSCO can file to charge customers in advance of the project under a “clean energy” designation because the Indiana legislature passed a bill this year allowing utilities to use the financing option when they construct new natural gas plants that displace coal.

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ISO-NE Sees Little Shortfall Risk for 2032

There is little risk of energy shortfall in the summer of 2032, ISO-NE told the NEPOOL Reliability Committee (RC) on Tuesday, building upon the RTO’s previously released 2032 winter results that gave mixed signals on the system’s reliability.

ISO-NE told the RC the shortfall risk for the summer of 2032 appears to be similar to that of summer 2027. (See No Shortfall Anticipated for Summer of 2027, ISO-NE Says.)

“No energy shortfall was observed in any of the summer 2032 events; only one hour of 30-minute reserve shortfall was observed in one July 13, 1979, case and in one July 26, 1984, case,” Stephen George of ISO-NE said.

These results are part of ISO-NE’s ongoing “Operational Impacts of Extreme Weather Events” study, which the RTO developed in conjunction with the Electric Power Research Institute.

ISO-NE’s baseline winter 2032 analyses projected worst-case energy shortfall risk to decrease in 2032 compared to 2027 in most scenarios. However, a sensitivity analysis — which considered an additional range of factors — showed increasing risks for 2032 compared to 2027.

The baseline analysis indicated winter shortfall risks significantly decreased with the presence of the New England Clean Energy Connect (NECEC) transmission line, while the Everett Marine Terminal actually increased shortfall risk in most of the scenarios modeled. ISO-NE said it expects the 1,200-MW NECEC line to be in service by 2032, while the future of Everett remains in limbo. (See Narrow Set of Options for Retaining Everett LNG Terminal.)

“In terms of magnitude and probability, baseline studies of 2032 winter events indicate an energy shortfall risk profile similar to that of the 2027 winter event studies,” ISO-NE said in August about the 2032 winter modeling.

However, the RTO noted that the “sensitivity analysis of 2032 worst-case scenarios indicate an increasing energy shortfall risk profile between 2027 and 2032,” adding that the increased risk “is particularly observable with the 2023 CELT (Capacity, Energy, Loads, and Transmission) load forecast.”

The 2023 CELT forecast increased the projected electricity demand for the 2031/2032 winter by about 10% compared to the 2022 CELT projection. (See ISO-NE Increases Peak Load Forecasts.) The baseline analyses were run using the 2022 CELT data.

The winter 2032 sensitivity analysis used the worst-case weather event modeled in the baseline analysis, while varying the levels of resource retirements, electricity demand, imports, stored fuel inventories and forced outages. ISO-NE told the RC that sensitivity analysis results for the summer of 2032 will be shared at a future meeting.

These reliability findings come as ISO-NE grapples with increasing levels of variable renewable generation coupled with a massive expected increase in electricity demand stemming from electrification. ISO-NE expects the regional grid to transition from a summer peak to a winter peak at some point in the coming decades, in part because of heating electrification.

EMT, which is the only LNG import terminal in New England, is propped up by the expensive Mystic Agreement, which will expire after this winter. ISO-NE’s quantitative analyses have not shown that the terminal is necessary for grid reliability, but the RTO has maintained the facility may be needed in the future in the face of rising winter demand and reliability concerns.

“I think it would be extremely unwise were we to let that facility go until we know where we are with regard to these variables,” ISO-NE CEO Gordon van Welie said at a FERC forum on winter reliability in June. (See NE Stakeholders Debate Future of Everett at FERC Winter Gas-Elec Forum.)

ISO-NE is conducting another round of sensitivity analysis for the winter of 2032, which will consider a range of factors and assumptions based on feedback from NEPOOL stakeholders. These added sensitivities will include varying levels of renewable generation, battery storage, behind-the-meter solar, demand response, imports, and gas, oil and nuclear resource retirements.

The RTO will discuss the results of this additional sensitivity analysis at the November RC meeting.

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ERCOT Expects Sufficient Capacity this Fall

ERCOT said Tuesday that it expects to have sufficient capacity to meet peak demand under normal conditions during the two-month fall season that begins in October.

According to the Texas grid operator’s fall seasonal assessment of resource adequacy (SARA), demand is expected to peak at 69.65 GW, a welcome relief after load averaged more than 80 GW over 227 hourly intervals during what has been brutal summer weather. The SARA indicates 99.73 GW will be available to meet demand in October and November.

That includes 3.99 GW of energy storage resources that have been invaluable in meeting record summer demand. A little over 1 GW of storage is assumed to be able to provide energy during the highest fall net load hours (total load minus wind and solar generation).

ERCOT said the estimated storage capacity is a proxy for what it expects during tight reserve hours and an interim availability assumption until a formal capacity contribution method is adopted in future SARA reports.

Solar energy, which played a key role during this summer’s tightest hours, is expected to contribute 11.66 GW during peak periods this fall with a 64% seasonal rating. Wind energy is expected to contribute 12.69 GW during those periods; it has seasonal capacity factors ranging from 31 to 41%.

The assessment includes a base scenario and three elevated and three extreme risk scenarios reflecting alternative assumptions for peak demand, unplanned thermal outages and renewable output. The most severe extreme risk scenario — a combination of high peak load, high unplanned thermal outages (more than 18 GW) and extreme low wind output — results in a high risk of rotating outages. An elevated risk scenario with low renewable output results in a capacity shortfall of 2.44 GW and close to a Level 1 energy emergency alert.

The grid operator said the SARA does not reflect pending changes that will come when the Texas Public Utility Commission approves a protocol revision (NPRR1176) that modifies the EEA level triggers.

The fall assessment marks ERCOT’s final SARA report. It is being replaced with what the grid operator calls the monthly operational assessment of resource adequacy (MORA). The revised report will be posted two months before the reporting month, beginning with the December assessment on Oct. 2.

The first MORA will be produced manually but will eventually transition into a multi-tabbed spreadsheet that will include a link to an interactive dashboard.