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November 16, 2024

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GSA to Invest $2B in Low-carbon Building Materials

The General Services Administration (GSA) announced Nov. 6 that it will be spending just over $2 billion in funds from the Inflation Reduction Act (IRA) on low-carbon construction materials — concrete, glass, steel and asphalt — for repairs and upgrades on more than 150 federal buildings in 39 states, D.C. and Puerto Rico.

GSA Administrator Robin Carnahan rolled out the “Buy Clean” initiative in Topeka, Kan., where the Frank Carlson Federal Building and Courthouse will be getting a $25 million facelift with new windows and doors with blast-resistant aluminum frames and insulated low-embodied carbon (LEC) glass that will reduce the building’s energy use. Sidewalks and parking areas at the building will also be updated with LEC concrete.

Project design is to begin in fiscal 2024, with construction to follow in 2025, according to GSA.

Embodied carbon emissions are those generated by a material’s production, transportation, installation, use and disposal. LEC materials “have substantially lower levels of embodied greenhouse gas emissions,” according to a GSA fact sheet. The LEC concrete, glass, steel and asphalt used for the projects announced Nov. 6 could cut the federal buildings’ greenhouse gas emissions by 41,000 metric tons and create 6,000 jobs per year for the life of the projects, a GSA press release said.

“By incorporating clean construction materials in more than 150 projects across the country, we’re helping create … the clean manufacturing industries of the future and sending a clear signal that the homegrown market for these sustainable products is here to stay,” Carnahan said in the press release.

Federal demand for LEC construction materials is potentially huge. GSA manages more than 9,600 federal buildings, covering a total of 375 million square feet, in 2,000 communities across the country, according to the administration’s website. The government’s building stock ranges from courthouses, Internal Revenue Service offices, border stations and warehouses, to data centers and laboratories.

According to GSA, the IRA provided the administration with $3.375 billion to invest in federal buildings to cut emissions and spur innovation by buying and installing LEC materials. The administration has focused on concrete, glass, steel and asphalt because they are all carbon-intensive materials that together generate close to half of all GHG emissions from U.S. manufacturing.

They also account for 98% of the construction materials the government either pays for or funds for federal infrastructure projects, GSA said.

The price tag for the current round of projects includes $384 million for asphalt, $767 million for concrete, $464 million for glass and $388 million for steel.

Senate Majority Leader Chuck Schumer (D-N.Y.) praised GSA for getting the IRA dollars “out the door.”

“This funding helps create a market for low- and zero-carbon materials, further incentivizing industrial manufacturers to take advantage of other IRA programs aimed at helping them reduce their emissions,” Schumer said. “This ecosystem of incentives approach is part of what makes the IRA so impactful and resilient.”

What is ‘Substantially Lower’?

The Buy Clean initiative was launched to support President Joe Biden’s Federal Sustainability Plan, rolled out in December 2021. The plan set a 2045 target for federal buildings to cut GHG emissions to net zero, with an interim goal of 50% by 2032 and a 2050 deadline for net-zero federal procurements.

GSA collaborated with the Department of Transportation and EPA to develop a set of “interim determinations” for designating materials like asphalt, glass, concrete and steel as low carbon. The guidelines are being tested out on 11 projects during a pilot period that began in May.

A core issue was defining the “substantially lower” emissions required for LEC materials to qualify for IRA funding. EPA defined the term “as meaning a global-warming potential that is in the best-performing 20% … when compared to similar materials/products,” according to a December 2022 letter to GSA from EPA Deputy Administrator Janet McCabe.

If materials cannot be found that meet that “Top 20%” limit, EPA then set a second level of best-performing 40%, and a third level of “better than the estimated industry average,” both of which could still qualify for IRA funding.

EPA also is “working with the construction materials manufacturing industry and [nongovernmental organizations] to help track the climate impacts of their operations and to develop a labeling program that will clearly identify lower carbon construction materials in the marketplace,” McCabe said in the GSA press release.

According to the GSA fact sheet, the administration is continuing work on the 11 pilot projects and reports that “progress is being made to source LEC materials on these projects.”

More awards could be coming in the first half of 2024, the fact sheet says, but GSA decided to announce the current round of projects “to inform the market of the breadth of our plan, and to help position U.S. manufacturers, suppliers and installers to capitalize on this exciting opportunity.”

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Pioneering NuScale Small Modular Reactor Project Canceled

NuScale Power Corp. and Utah Associated Municipal Power Systems said Nov. 8 they had agreed to terminate the Carbon Free Power Project.

They said it appeared unlikely the project would have enough subscription to continue toward deployment. They now will work with the Department of Energy to wind down the project, which would have been built at DOE’s Idaho National Laboratory.

NuScale announced the news with its third-quarter earnings after the stock market closed Nov, 8. NuScale stock, which had been trading near a 52-week low, plummeted in after-hours trading.

The CFPP was to be the first NuScale small modular reactor to begin operation in the United States, with the first of six 77 MW modules to start generating power in 2029.

In its third quarter 8-K filing with the SEC, the company said it would transfer materials intended for the CFPP project to use with another customer.

NuScale had indicated in a March earnings call that the project was 25% subscribed to but needed to reach 80%.

During the conference call Nov. 8, company leaders said the goal proved unreachable.

NuScale CEO John Hopkins quoted the wisdom of the native peoples of the Great Plains: “Once you’re on a dead horse, you dismount quickly and move on to others.”

He said he was proud of the work done on CFPP over the years.

The company said about half the cost NuScale incurred in developing CFPP is not lost money — it’s effectively development spending that informs future business.

“The progress made here will benefit ALL of our future customers,” Hopkins said. “CFPP unequivocally has been a tremendous success for NuScale.”

NuScale’s 50 MW power module in January 2020 became the first SMR design certified by the Nuclear Regulatory Commission. Its 77 MWe module has been accepted for NRC review.

In its 8-K filing, the company said Standard Power has chosen the NuScale-ENTRA1 partnership to develop two SMR-powered facilities with a total of nearly 2 GWe. It said its RoPower project in Romania is advancing to the next phase of development with a key regulatory approval. And it said production of power module forgings continues.

NuScale reported a net loss of $58.3 million on revenue of $7 million in the third quarter of 2023, up from $49.6 million and $3.2 million in the same quarter of 2022.

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EVs, Data Centers to Fuel Load Growth, Forecasting Challenges

Electric vehicles and data centers are expected to be major contributors to load growth, but each has unique challenges when it comes to load forecasting, speakers said during a WECC webinar. 

“Forecasting is as unique as the industry itself,” said Shane Lunderville, business development manager for the Grant County Public Utility District in Washington. “So if it’s electrifying vehicles, if it’s data centers, if it’s manufacturing, each one is going to be different.” 

Much has been learned since Grant County got its first data centers in the mid-2000s, Lunderville said during the Oct. 2 webinar, part of WECC’s resource adequacy discussion series. 

But technology is always changing. The use of artificial intelligence is on the rise and work patterns have shifted since the COVID-19 pandemic, he said. 

“We all have Office 365 or Google, whatever; it’s all online-based,” he said. 

Data centers say the best they can do is give a five-year outlook, Lunderville said, but transmission and infrastructure development takes much longer. 

And data centers, which run constantly, don’t provide much opportunity for demand response, he said. 

But Amanda Sargent, senior resource adequacy analyst at WECC, said data center operators who are interested in carbon-free electricity might build centers with generation resources or batteries. 

“If there’s an opportunity to incentivize them to also build some of those resources at the same time, then there may be opportunities … during peak times to call on them for demand response,” Sargent said. 

Sargent also discussed load growth from EV charging, noting that the adoption of new technology often follows an S-shaped pattern, starting out slowly and then accelerating. 

“That’s going to play a really important role in being able to have more accurate forecasts — being able to follow how high those adoption rates are going to be for the sales of new electric vehicles and other kinds of technologies that are going to increase electric demand,” Sargent said. 

Phil Jones, executive director of the Alliance for Transportation Electrification, said some forecasting of EV charging loads will be fairly easy. 

Much of EV charging takes place at homes, where it can be influenced by incentives to charge off-peak. Opportunistic charging — where an EV driver stops off at a charging station — is harder to predict, he said. 

When it comes to electric truck fleets, some fleets will charge overnight using Level 2 chargers. Jones said that charging isn’t difficult for a utility to handle. 

But other trucks will charge as they travel along corridors, using DC fast chargers that could soon be providing 1 MW of power.  

Historical data on fleet charging is currently lacking, Jones said. But fleet operators are working closely with planners on the issue. Jones pointed to an effort from the Electric Power Research Institute (EPRI) called EVs2Scale2030. 

One piece of the initiative is to develop a nationwide map showing EV loads, grid impacts, utility lead times, workforce requirements and costs. (See EPRI Launches Cross-industry Initiative to Advance EV Adoption.) 

With load growth seemingly inevitable, panelists called for allowing utilities to build infrastructure further in advance. 

“Allow more flexible and sophisticated load forecasting for loads that don’t have a lot of historical data and based on that … allow utilities to build ahead of need,” Jones said. 

WECC’s discussion series will return in February with a new name and an expanded scope. The discussions, which will be called Reliability in the West, will take place the first Wednesday of each month from 11 a.m. to noon Mountain time. 

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Analysis Group Details Methodology of ISO-NE Capacity Market Study

WESTBOROUGH, Mass. — Analysis Group outlined the methodology of its study of major changes to the structure of ISO-NE’s Forward Capacity Market (FCM) at the NEPOOL Markets Committee meeting Nov. 7. The study will consider quantitative and qualitative effects of prompt and seasonal capacity market formats.

“These options are being evaluated in light of multiple changes to the region’s electricity system and markets arising in part from state policies aimed at decarbonizing the region’s grid, as well as technological innovation that increases performance and decreases costs of new technologies,” Todd Schatzki of Analysis Group told the MC.

A prompt market would reduce the time between the capacity auction and the capacity commitment period (CCP) from three years to just a few months, while a seasonal auction would split up the CCP into distinct seasons with separate auctions.

Working on a tight timeline — with draft results expected in December — Analysis Group is tasked with studying the tradeoffs associated with both formats. The study will consider prompt and seasonal constructs both separately and together and compare them to the existing three-year forward annual market.

Analysis Group will also consider other market design factors, including how the seasons are separated within a given year, whether seasonal auctions are held simultaneously or sequentially, and whether the transition to a new capacity market will be accomplished all at once or in multiple phases.

The quantitative assessment of auction outcomes associated with various constructs will look at the 2028/29 and 2034/35 CCPs, with a resource supply that “reflects resources that have recently bid into the [Forward Capacity Auction], as well as state-legislated procurements and additional assumed resources (to meet state environmental goals).”

ISO-NE is requesting stakeholder feedback on the study by Nov. 13 and is planning to make a recommendation on a potential move to a prompt market at some point in the first quarter of 2024.

RCA Updates

Feng Zhao of ISO-NE presented updates to the RTO’s proposal for winter accreditation of oil and gas resources as part of its ongoing Resource Capacity Accreditation (RCA) project.

Under the updated proposal, “gas capacities will be modeled as an aggregated profile, and oil resources will be modeled as individually de-rated thermal units for the winter period,” Zhao said.

ISO-NE stakeholder process timeline | ISO-NE

The RCA project aims to “support a reliable, clean-energy transition by implementing methodologies that will more appropriately accredit resource contributions to resource adequacy as the resource mix transforms,” Zhao said.

The seasonal risk assessments that result from these models will then be used as resource accreditation inputs.

“The newly proposed gas and oil models better capture the characteristics of gas and oil energy limitations and historical performance in the winter period, and therefore are expected to yield a more accurate winter risk level,” Zhao added.

Retirement Rules

ISO-NE continued discussions on changes to the rules for retired resources looking to re-enter the FCM.

In August, the RTO proposed to eliminate investment requirements for retired resources seeking FCM re-entry. ISO-NE has said the requirements “could create a barrier to cost-effective and timely re-entry of FCM resources.”

Responding to stakeholder concerns about seller-side market power and cost-of-service impacts, ISO-NE is now proposing to treat certain retired resources that re-enter the FCM as existing capacity and require “clawback” provisions for resources retained by cost-of-service agreements (COSAs) that seek to re-enter the capacity market.

The changes are intended to prevent unintended incentives for resources retiring and then re-entering the FCM.

“Absent a provision requiring repayment, resources could uneconomically retire only to seek a (perceived) profitable retention agreement,” said Ryan McCarthy of ISO-NE. “If retained without a clawback provision, the resource can re-enter in a later period, benefiting from any capital expenditure compensation … received via the COSA.”

ISO-NE is targeting January for a vote by the MC on the proposal, followed by the Participants Committee in February.

IMM Quarterly Report

Summer wholesale market costs were down by 60% and energy costs were down by 64% compared to the previous summer, ISO-NE’s Internal Market Monitor found in its quarterly markets report.

The Monitor attributed this to the decline in average natural gas prices, which were 71% lower than in the summer of 2022. Average loads were also significantly lower than the previous two summers — and the lowest summer peak load since 2000 — in part because of cooler weather in the region.

The IMM also noted that nuclear generation decreased because of planned and unplanned outages, making up 17% of the region’s average output compared to 21% in the previous two summers.

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Maine Voters Reject Public Takeover of Electric Utilities

Maine voters have decisively rejected a proposal for a public takeover of the state’s for-profit electric transmission and distribution infrastructure.

The unofficial tally in the Nov. 7 referendum was approximately 70% opposed and 30% in favor with 99% of the vote tallied, multiple media reports indicated. The state had not posted official results by the close of business Nov. 8.

The proposed Pine Tree Power Co. would have been a nonprofit, consumer-owned utility focused on reliable, affordable service rather than shareholder profit.

Other mission goals included assisting the state with its climate action plan, improving internet connectivity, advancing environmental and social justice, creating transparent governance and supporting economic growth.

Another question on the referendum ballot Nov. 7 would have affected Pine Tree: A proposed requirement that any consumer-owned electric utility gain statewide voter approval to exceed $1 billion in total outstanding debt.

Voters approved that measure by a margin nearly as wide as their rejection of Pine Tree — 65% to 30% — according to unofficial results.

Rural electrification cooperatives, municipal electric districts and certain quasi-independent state entities also are subject to voter approval of debt exceeding $1 billion, under terms of the referendum.

Long-running Debate

The concept of a Maine public utility has existed for years, rooted in part in the low customer service and reliability ratings of Central Maine Power and Versant, Maine’s two investor-owned electric utilities. (For NetZero Insider’s in-depth pre-election look at the issues, see “In the Fight Over Maine’s Utilities, the Future of the State’s Energy Transition Goes to Voters.”)

But following through and creating Pine Tree has proved difficult.

In 2021, Gov. Janet Mills (D) vetoed legislation that would have directed a public takeover. Seven weeks before the 2023 referendum, she urged state residents to vote “no,” saying a takeover would result in years of litigation and create paralysis amid the urgent need to prepare the grid for the clean energy transition.

Also, she said, Pine Tree would debut with up to $13.5 billion in debt amid potentially high interest rates.

The parent companies of CMP and Versant spent heavily to sway public opinion against Pine Tree.

Arguing in favor of Pine Tree was an array of grassroots organizations focusing not just on high rates and poor performance under the current ownership but on the chance to address environmental and social concerns through public ownership.

Late Nov. 7, the group Pine Tree Power conceded defeat on the ballot measure, but not on the underlying issues. It said:

“Central Maine Power and Versant’s parent companies poured almost $40 million … into misleading voters rather than fixing their worst-in-the-nation service. They made clear that their priority will always be enriching their shareholders, not serving their customers. Thousands of Mainers are ready for public power. While we couldn’t overcome being outspent 37:1, we started a critically important conversation that does not end today. Our grassroots movement educated thousands about the savings, reliability and climate benefits of consumer-owned utilities.”

Before the election, Pine Tree proponents said utility takeovers often take more than one attempt to achieve and said they would continue to press the issue in Maine if voters did not approve it this time.

Yet another of the eight questions on Tuesday’s ballot will have direct bearing on any future effort. By a huge ratio — 86% to 14% by unofficial tally — voters approved a ban on foreign governments and their entities spending money to influence elections or referendums in Maine.

Versant is owned by Enmax, a private corporation whose sole shareholder is the city of Calgary, Alberta. CMP is part of Avangrid, which is part of Spanish utility Iberdrola. “Maine not Spain” has been a recurring slogan in debate over Pine Tree, but the largest shareholder of Iberdrola is not Spain — it is Qatar, through its sovereign wealth fund.

Proposed Structure

Under the wording of the referendum, seven of Pine Tree’s 13 board members would have been elected and six would have been designated experts.

Starting Jan. 1, 2025, the state Public Utilities Commission would have directed takeover of any utility that met the criteria laid out by the referendum.

Upon takeover, Pine Tree Power would have had to retain the utility’s employees and would have been liable for property taxes on its infrastructure. It would have been exempt from state income tax, however, and its debt also would have been exempt from state taxes.

The new company would have had to cover all of its expenses with rates and charges — it would not have had access state funds and its debt would not have been a state liability.

In her Sept. 20 message urging residents to vote down the takeover proposal, Mills said she is committed to improving utilities’ quality of service and holding them accountable for it. But she challenged Pine Tree as a means of accomplishing this and pointed to its proposed structure.

“Question 3 creates a governing board of elected individuals — in other words, politicians — with no particular credentials,” Mills said. “Electing people only injects a level of politics and partisanship into the delivery of our electricity. That’s the last thing we need, and, hey, I’m talking as a politician.

“And what would this governing board of politicians be in charge of? Well, they would be required to contract with an operator to run the transmission and utility’s assets. An operator that has ‘familiarity with the systems to be administered.’ So, somebody who looks a lot like CMP and Versant. So, what we are really talking about here is adding a layer of bureaucracy and politics and partisanship over the existing structure of CMP and Versant and I just don’t see how this improves anything.”

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2023 Elections Bring Billions for Texas Gas, Dem Wins in Virginia, NJ

Voters Tuesday overwhelmingly approved a nearly $10 billion fund for gas generation in Texas, while handing Democrats victories in legislative elections in New Jersey and Virginia that have implications for energy policy there. 

Texas’ Proposition 7 passed by a vote of 1,641,453-886,991, gathering nearly 65% of the votes. (See $10B Fund for Gas Plants on Texas Ballot.) 

The proposition sets up the Texas Energy Fund (TEF), a $7.2 billion low-interest loan program intended for the development of up to 10 GW of natural gas plants. Some $5 billion will be set aside for 20-year, 3% interest loans to build new generation with at least 100 MW of fully dispatchable capacity. Power plants that come online before June 2029 are eligible for bonus payments. 

Another $2.8 billion will be dedicated to grants for infrastructure improvements in non-ERCOT regions and to strengthen resiliency by setting up microgrids at hospitals, fire stations and other critical facilities. 

The fund is a result of legislation sponsored by state Sen. Charles Schwertner (R). “Glad to see the voters supported Proposition 7 to ensure Texans have the electric generation they need to keep their lights on during extreme weather conditions,” he said in a statement. 

The Texas Public Utility Commission will oversee the TEF and provide the grants and loans to finance the construction, maintenance, modernization and operation of the state’s electric facilities. 

Stoic Energy’s Doug Lewin, who frequently comments on the ERCOT market, cast doubt on the PUC being able to function as a bank, saying the commission has “no expertise gauging default risk.” 

The PUC’s executive director, Thomas Gleeson, said staff have been working since early summer to prepare for the fund’s implementation. Application and award processes still are being developed, but the commission already has created a webpage with more information on project eligibility and the types of grants and loans available. 

“With voter approval of the fund, we will push forward developing the program and design transparent processes to ensure the administration of the TEF is timely, fiscally responsible and effective,” he said in a release. 

The PUC must begin accepting loan applications for projects within the ERCOT region by June 1, 2024, and must make initial disbursements for approved loans by Dec. 31, 2025. 

NJ Democrats Win Handily Amid Clean Energy GOP Attacks

Democrats strengthened their hold on the New Jersey legislature in Tuesday’s elections, retaining control of both legislative houses despite Republican efforts to paint Democratic Gov. Phil Murphy’s clean energy program — especially its offshore wind (OSW) projects — as excessive and expensive. 

With final results still to be confirmed, Democrats are expected to hold at least 24 seats in the 40-seat Senate and 51 of the 80 seats in the Assembly, adding at least five seats to their current 46. 

The string of victories followed a campaign in which Republican candidates sought to tap into opposition to the wind projects, especially focusing on whale deaths on the Jersey Shore. In one example, the Republican State Leadership Committee (RSLC), a national group that seeks to help the GOP win in state races, produced two advertisements on the issue, one of which concludes with the slogan “Save the Whales. Dump New Jersey Democrats.” 

The election came two years after voters re-elected Murphy by a much narrower margin than expected, prompting speculation that the result reflected voter disapproval of his aggressive clean energy strategy. Anjuli Ramos-Busot, director of the Sierra Club New Jersey Chapter, said Tuesday’s results showed the opposite. 

“The elections reflect that in reality New Jerseyans continue to vote for a clean energy agenda and environmental protections,” she said. “Clean energy transition won, clean air won and energy independence won.” 

Jeff Tittel, the former director of the state Sierra Club, said the long-term impact of the election on clean energy initiatives remains to be seen. Under pressure, some Democratic candidates backed away from supporting the initiatives during the campaign, and he questioned where those Democrats would stand in the future. 

“The question becomes how much willpower does the legislature have to now move forward on a lot of green energy proposals, given the fact that many of them were getting beaten up for the last couple of months,” he said. “Some of them, in order to kind of deflect, said we’re moving too fast on electrification, or they agree that offshore wind shouldn’t get any more subsidies, or that we slow down on EVs.” 

“Will they go back and be where they used to be on supporting green energy?” he asked. “Or because they made certain statements during the campaign, will they be more hesitant?” 

Virginia Voters Hand Democrats Slim Majorities in Both Houses of the General Assembly

Virginia Democrats won enough seats to flip control of the House of Delegates and maintain their majority in the Senate, two years after losing the lower chamber and the governor’s office to Republicans. Gov. Glenn Youngkin (R) will finish out the last two years of his term with slim majorities for the Democrats in both houses. Initial results have the Senate split 21-19 with the House split 51-48, with the Republican candidate leading in one close race that had yet to be called late Wednesday. 

A big motivator for voters this fall was abortion, with Youngkin backing a plan to limit abortions to the first 15 weeks of pregnancy, instead of the current law that allows abortion until the end of the second trimester. The majority of voters siding with Democrats on that issue showed they were rejecting extremism, said Advanced Energy United Policy Director Kim Jemaine. 

“I think you can essentially extrapolate from that, also, that voters are looking at some of the decisions made by Republicans in the General Assembly over the last couple of years and say that voters are also viewing climate denial and obstruction of clean energy policies in the bucket of extremism,” she added. 

She said she hoped Republicans will stop proposing bills curbing clean energy policies such as the Virginia Clean Economy Act (VCEA) of 2020, and the new Democratic majority can work with Youngkin on issues such as energy efficiency and expanding distributed generation. 

A Day 1 priority for the legislature should be filling the two empty seats on the three-person State Corporation Commission, which has operated with Chairman Jehmal Hudson as the only member for most of this year, Jemaine said. In Virginia, the General Assembly (both the Senate and the House) elects the regulators for six-year terms with the governor only able to make temporary appointments if the legislature is out of session. 

“I think folks were waiting for the outcomes of their elections to move forward there,” Jemaine said. “And so, this presents an opportunity for Democrats to appoint judges that will hold [Dominion Energy] accountable and ensure that those decisions are in alignment with the VCEA.” 

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FERC-NERC Elliott Report Calls Winter Outages ‘Unacceptable’

FERC and NERC’s final report on the December 2022 winter storm laid out “an unacceptably familiar pattern” of extreme cold temperatures leading to widespread generation outages across the Eastern Interconnection.  

The report issued Nov. 7 noted that North America’s electric grid and natural gas infrastructure “continue to be severely challenged during extreme cold weather events” despite repeated warnings after multiple recent similar storms. 

The December 2022 event — known as Winter Storm Elliott — began with a bomb cyclone and extratropical cyclone, both indicating a storm associated with a rapid drop in pressure, that moved from the upper Plains states eastward and reached the Eastern U.S. by Dec. 23. An “unprecedented” amount of generation failed during the event, reaching more than 90 GW in coincident unplanned outages. 

Most of the entities that shed load were in the Southeast U.S., the report said, including the Tennessee Valley Authority, Louisville Gas and Electric/Kentucky Utilities, Duke Energy Progress and Duke Energy Carolinas, and Santee Cooper. Other entities did not shed load but had to issue energy emergency alerts, such as PJM, Southern Co., MISO, SPP and ISO-NE. All affected entities “experienced significant unplanned generating unit outages, derates or failures to start within their footprints.” 

The report noted that, similar to previous cold weather events, entities had warning of the coming frigid weather “well in advance” and many had “issued cold weather preparation notices to their generation and transmission owners and operators.” Temperatures were not as low as in the winter storms of February 2021. However, wind speeds were higher in many places, leading temperatures to drop faster than in 2021. For example, TVA “reported a drop of 46 degrees [Fahrenheit] in five hours.” 

Natural gas declined significantly during the event, due in part to freezing of gas wellheads and other equipment which could not be repaired quickly due to poor road conditions. The report called the gas production decline the greatest since the 2021 storm, with production at the Marcellus Shale and Utica Shale formations falling by up to 54%. Fuel supply issues at natural gas facilities accounted for 20% of the 3,565 generating unit outages and derates during the event (by MW); fuel issues for other resources came to just 4% of the total.  

Other leading causes of outages and derates included mechanical and electrical issues (41% by MW) and freezing issues (31%). The report noted that FERC and NERC “had provided multiple prior recommendations and follow-up activities regarding steps for winter preparedness,” and that most affected generator owners had plans of their own in place for extreme weather. Nevertheless, more than 75% of the generating units that failed due to freezing issues did so in temperatures above their documented minimum operating temperatures. 

Incremental unplanned generating unit megawatt outages, derates and failures to start by cause in the total event area. | FERC

Recommendations Include Gas Reliability Actions

The report provided 11 recommendations for preventing similar events in the future, which the authors acknowledged were “built on previous analyses and findings” from cold weather events over the past decade.  

The first recommendation is to finish implementing the revisions to NERC’s reliability standards suggested in the FERC-NERC joint report on the winter storms of February 2021. The report’s authors noted that “while some changes were implemented in response to previous … events, generators and natural gas supply and infrastructure remain vulnerable to extreme cold weather.” (See FERC Approves More Extreme Weather Rules.) 

Additional recommendations for generator reliability include implementing “robust monitoring” by NERC and the regional entities to ensure compliance with reliability standards and to determine if gaps exist. The report also called for NERC to initiate a technical review of the causes of unplanned generation outages related to mechanical and electrical issues during the event, along with a study by NERC, FERC and the REs to examine the “overall availability and readiness of blackstart units … during cold weather conditions” across the entire U.S. 

But perhaps the biggest recommendation of the report was the call for Congress and state legislatures to pass legislation establishing “reliability rules for natural gas infrastructure necessary to support the grid” and local gas distribution. Elaborating on this point, the authors outlined potential structures similar to the ERO, with regional natural gas communications coordinators fulfilling a role similar to the electric grid’s reliability coordinators. 

Natural gas supply and demand, with temperatures in the northern U.S., for the month of December 2022. | FERC

In a joint statement, NERC CEO Jim Robb and FERC Chair Willie Phillips endorsed this idea, repeating calls for a gas reliability organization that they made when the report was previewed at the commission’s September open meeting. Their support for such an organization echoes a similar call issued by the chairs of NAESB’s Gas-Electric Harmonization Forum earlier this year. (See NAESB Forum Chairs Push for Gas Reliability Organization.)  

“As the report lays out, we narrowly dodged a crisis last year. Had the weather not warmed up on Christmas Day, it is highly likely that natural gas service would have been disrupted to New York City,” Robb said. “The unplanned loss of generation due to freezing and fuel issues was unprecedented, reflecting the extraordinary interconnectedness of the gas and electric systems and their combined vulnerability to extreme weather.” 

In a statement, Todd Snitchler, CEO of the Electric Power Supply Association, said EPSA takes the report’s findings seriously and is “committed to improving power system performance in all weather and demand scenarios.” He added that “power generation outages involving all types of resources … must be addressed and corrected.”  

“The report reveals that no market model, region of the country or fuel type is immune to the challenges experienced during Elliott. A well-designed competitive power market, however, is the best foundation to serve power needs reliably and efficiently,” Snitchler said. “Areas of the country served by competitive power markets fared comparatively well during the storm when it came to resource adequacy … [while] regions served by public power and vertically integrated entities were subject to more than 5,400 MW of load shed at various times during the event.” 

NERC and FERC plan to hold a webinar for industry on the report’s recommendations “at the end of November,” the joint statement said. The date for the webinar has not been set. 

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FERC Accepts ISO-NE Order 2222 Compliance Filing

FERC last week accepted ISO-NE’s third compliance filing for Order 2222, ruling that the RTO’s proposal does not pose prohibitive barriers to market participation for distributed energy resource aggregations (DERAs) (ER22-983-004).

The commission directed ISO-NE to make an additional filing within 90 days to address outstanding issues related to its metering proposal.

At the beginning of March, the commission accepted and rejected parts of ISO-NE’s first 2222 filing, prompting a series of compliance filings from the RTO. (See FERC Gives ISO-NE Homework on Order 2222.) The second and fourth filings that followed went uncontested and were accepted by FERC in late October (ER22-983-003 and ER22-983-005).

The third filing focused on metering rules, market participation models, small utility opt-in requirements and coordination among the RTO, aggregators and utilities.

The filing was challenged in May by Advanced Energy United, PowerOptions and the Solar Energy Industries Association. The groups argued that the metering requirements in ISO-NE’s proposal are prohibitive to DERAs.

“ISO-NE has failed to make any adjustments to facilitate participation by DERs located behind a customer meter, leaving in place a barrier recognized by the commission in its compliance order, and has failed to justify the metering and telemetry provisions that underlie this barrier as directed by the commission,” the groups wrote. “The impacts of ISO-NE’s failure to incorporate behind-the-meter DERs into wholesale markets will only grow as penetration increases.”

For metering DERs, ISO-NE provided three options: retail delivery point metering, submetering with reconstitution and parallel metering.

The organizations said submetering with reconstitution and parallel metering are not viable options for most DERs, and metering resources at the point of interconnection would prevent those behind the meter from responding to price signals during times of peak demand. The organizations said this would “limit ISO-NE’s visibility into their availability, fail to optimize demand flexibility and undermine competition.”

ISO-NE wrote in its compliance that these configurations “minimize overall costs, are consistent with the metering requirements of all non-demand response resources and loads in New England, and ensure a just and reasonable allocation of wholesale power costs.”

FERC sided with ISO-NE, writing that its proposed options are necessary to prevent double counting.

“No party has identified less burdensome alternative metering configuration options that would also address the need to avoid double counting and inequitable cost shifting,” FERC wrote. “However, we encourage ISO-NE to continue to work with its stakeholders to consider additional metering options in the future, including for DERAs to utilize alternative submetering configurations.”

FERC gave ISO-NE 90 days to submit an additional filing that identifies the DERA as the entity responsible for submitting meter data and specifying a deadline for submitting data.

Also at issue was ISO-NE’s rule changes to incorporate DERAs into its participation models used in the RTO’s energy and ancillary services markets. ISO-NE’s initial filing modified aspects of the RTO’s five existing models, while adding two models specific to DERAs.

In March, FERC ruled that ISO-NE “failed to demonstrate that its proposed energy and ancillary services market participation models for [DERAs] accommodate the physical and operational characteristics of behind-the-meter [DERs], because behind-the-meter DERs participating under those participation models may be unable to provide all services that they are technically capable of providing through aggregation.”

The commission’s ruling in March, along with the protest comments, specifically took issue with ISO-NE’s existing Binary Storage Facility and Continuous Storage Facility participation models. In its ruling last week, FERC accepted ISO-NE’s clarifications and revisions, agreeing that the requirements of the models apply to all resources looking to participate.

In a statement to RTO Insider, an ISO-NE spokesperson said the RTO is pleased with the ruling, adding that the changes will “ensure distributed energy resource aggregations are metered accurately and the services they provide are not double counted.”

Sam Ressin of Advanced Energy United said the organization is disappointed with the ruling and “concerned that ISO-NE’s proposal, once implemented, will result in barriers to participation that will prevent most behind-the-meter DERs from contributing to the reliability and affordability of New England’s electric grid.”

In a concurring statement, Commissioner Allison Clements expressed her disappointment with ISO-NE for its decision not to use the filing to enable the full range of DR benefits from DERs.

“In essence, ISO New England chose to do the minimum required by law,” she wrote, noting that the RTO was clearly permitted by FERC to establish alternative DR metering options. “Rather than examining the full suite of options that may facilitate participation of DERs in its markets, ISO New England focused its further compliance filing solely on non-demand response resources.”

Clements added that all supply and demand resources should be considered as options to improve reliability in the region, saying it is “lamentable that ISO New England has failed to examine this path for facilitating more robust resource participation.”

Commissioner Mark Christie dissented with the order, citing the comments he issued in his previous dissent on FERC’s response to ISO-NE’s Order 2222 rehearing request. Christie had said Order 2222 created “nothing short of an incomprehensible quagmire bearing a substantial price tag.” (See FERC Responds to ISO-NE Rehearing Request on Order 2222.)

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Parties Preview FERC Review of EPA Power Plant Rule

FERC will host a discussion Thursday on the potential impacts of EPA’s proposed rule for power plant emissions as part of its annual technical conference on grid reliability, and parties have laid out the arguments they want addressed at the forum. (See EPA Power Plant Proposal Gets Mixed Reception in Comments.) 

The think tank Energy Innovation Policy & Technology released a report and hosted a webinar arguing that EPA’s proposal can be met while maintaining reliability. 

The rule would require fossil fuel-fired power plants to install emissions-mitigation technologies depending on when they plan to retire and how often they run. Coal plants that want to keep operating beyond 2040 need to install carbon capture and storage (CCS) technology that eliminates 90% of their emissions, Harvard University Environmental & Energy Law Program Executive Director Carrie Jenks said on the webinar. 

Baseload natural gas plants would either need CCS or blended hydrogen, though the rule would require less investment for plants that run on an intermediate basis or as peakers, Jenks said. 

The rule would effectively retire uncontrolled coal plants and largely leave a system with natural gas and storage balancing higher levels of renewables, which is already largely the case in California, New England and the U.K., said GridLab Executive Director Ric O’Connell. 

“Adding clean resources and using the gas fleet as a balancing resource is a pretty well-known playbook,” O’Connell said. 

Sens. John Barrasso (R-Wyo.) and Shelley Moore Capito (R-W.Va.) — the ranking members of the Energy & Natural Resources and Environment & Public Works committees, respectively — wrote FERC a letter urging it do more than the tech conference. The senators, whose committees oversee FERC and EPA, had urged the commission to hold the tech conference this summer. (See GOP Senators Call for FERC Conferences on EPA Power Plant Rule.) 

“Unless the EPA withdraws or significantly revises its proposed Clean Power Plan 2.0, the EPA will unnecessarily and significantly increase risks to electric reliability,” the senators said. “It will also increase dramatically the costs of generating electric power and make electricity less affordable for American families.” 

If FERC does not bring to bear its expertise and fact-based analysis “to dissuade the EPA” from continuing with the rule, it would be partially responsible for the resulting blackouts, they added. The senators urged FERC to gather comments and submit that record to EPA before the rule is finalized. 

While the rule does have requirements on how long uncontrolled natural gas plants can run if they operate more than 50% of the time, as long as EPA allows averaging, that should not be an issue, Jenks said during the webinar. 

Power plants can run at their full capacity during emergencies, such as Winter Storm Uri in February 2021 or the 2014 polar vortex, and then make up the difference in the rest of the year, she said. 

Another worry that opponents have brought up is the lack of “essential reliability services” such as frequency response, regulation reserves, operating reserves and voltage regulation that are provided for free because of the way traditional power plants work, said O’Connell. Grids do not need all their power plants to provide such services, with O’Connell saying a grid like MISO with about 200 GW of supply needs an “order of magnitude less” than that. 

“It turns out that clean resources, especially batteries with grid-forming inverters, can absolutely provide essential reliability services,” O’Connell said. “In fact, batteries have been providing regulation services in PJM for a long time now, closing in on a decade.” 

California is already rapidly decarbonizing its generation fleet, and CAISO is looking ahead to meet the state’s goals of eliminating emissions from electricity by 2045, said Cristy Sanada, regulatory affairs senior manager for the ISO. 

“The state policies have driven kind of where California is right now,” Sanada said. “California was very early to move on RPS standards and battery mandates. And, you know, we’ve already surpassed a lot of those early kind of RPS targets that were set out.” 

California’s own policies are driving the grid there to change more than a pending EPA proposal, but O’Connell noted that more is at play than just policy when it comes to the energy transition. 

“Let’s look at a state like Texas that doesn’t have any kind of clean energy goals at all, right?” O’Connell said. “Last year, wind energy exceeded both nuclear and coal and provided 25% of Texas’ electricity. Solar came on really strong this year. We saw a huge amount of solar being installed – it’s likely going to be 10% of the state’s electricity next year, if not more. And so, this is happening in states and locations that aren’t necessarily policy-driven like California. It’s really economically driven.” 

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MISO Stakeholders Split on Sloped Demand Curve Proposal

Stakeholders appear divided over MISO’s proposal to use a downward sloping demand curve in its capacity auction, with criticism aimed mostly at a provision to allow utilities to opt out of the auction for three years at a time.  

MISO at the end of September filed for FERC permission to replace its vertical demand curve used in its capacity auction with a sloped demand curve that assigns value to excess capacity (ER23-2977). (See MISO South Support for Sloped Demand Curve Wanes on Opt-out Provision.) Stakeholders’ comments on MISO’s filing rolled in last week.  

Consumers Energy filed in support of the sloped demand curve and said it should take care of the auction clearing capacity prices at either very close to $0/MW-day or near the cost of new entry, and drive “proper” grid investments.  

The Michigan-based utility said MISO’s “current model struggles to provide adequate price signals and investment incentives and fails to promote efficient resource planning or accurately reflect the reliability value of incremental capacity.”  

The Kentucky Public Service Commission also supported the sloping demand curve, saying it would allow excess capacity “to be assigned value commensurate with its reliability contribution along the downward slope of the curve.” 

The Electric Power Supply Association called the new curve “a key element in the ISO’s efforts to address the region’s resource adequacy challenges and support reliable operations.” Calpine also chimed in, saying the curve will yield more accurate capacity prices.  

However, the Sierra Club, Natural Resources Defense Council and the Sustainable FERC Project said while they agreed with most aspects of MISO’s plan to implement the sloped demand curve, they took issue with MISO’s plan to impose an “X% adder” on load-serving entities that opt out of the auction altogether. The adder will require those LSEs to secure more capacity than strictly necessary to meet MISO’s one-day-in-10-years system reliability standard. The adder will be based on how much excess capacity is procured through the auction using the sloped demand curve in previous years. 

The trio said the adder introduces “an artificial financial disincentive against LSEs utilizing the opt-out mechanism, undermining the suite of choices available to LSEs, and it will impose significant artificial costs on ratepayers.”  

In a joint protest, the Public Utility Commission of Texas and the Arkansas Public Service Commission likewise said MISO’s opt-out provision will penalize LSEs. Entergy and Cleco joined in criticism of the opt-out provision and advocated for allowing LSEs to partially opt out of the capacity auction with a portion of their load.  

The Louisiana Public Service Commission said MISO’s requirement that LSEs procure beyond the 1-in-10 standard if they wish to opt out of the auction “all but guarantees” LSEs will choose to participate in MISO’s auctions. The commission said the demand curve won’t incent new capacity, just “shift dollars around among existing capacity, while requiring LSEs” to acquire more capacity than necessary to meet loss-of-load expectation standards.  

Other stakeholders struck a harsher tone against the whole of MISO’s proposal.  

The Mississippi Public Service Commission said MISO’s narrative that a downward sloping demand curve is necessary for reliability is untrue. It said the price signal that the sloped demand curve is designed to evoke is unnecessary because most MISO utilities are vertically integrated and can roll the costs of generation needed to meet resource adequacy targets into their rate bases.  

“The premise — that ‘incremental capacity’ above that needed to satisfy the one day in 10 years loss-of-load expectation standard — is pure ex cathedra hokum,” the commission told FERC. “Energy from installed capacity, not capacity that clears an auction, is what serves load and provides reliability. Efforts in MISO that establish appropriate energy pricing, including scarcity pricing, market monitoring that prevents physical and economic withholding, and the desire to profit from existing generation investment will motivate generators to produce electricity, irrespective of whether those generators cleared in the Planning Reserve Auction.”  

American Municipal Power, Missouri Joint Municipal Electric Utility Commission, Southern Minnesota Municipal Power Agency and WPPI Energy asked FERC to completely reject MISO’s proposal, saying they doubted the changes are necessary.  

“MISO has not justified that these dramatic changes to its resource adequacy construct are warranted. Nor has MISO acknowledged or justified largely eliminating critical auction clearing price mitigation that protects against excessive prices, or explained how its various revisions can be implemented in a coherent, just and reasonable manner,” the utilities said. 

They said they didn’t see how FERC could allow MISO to clear its auction beyond the current limit of 1.75 times the cost of new entry for generation. They also said MISO’s opt-out provision is murky and its proposed opt-out deficiency charge for LSEs that fail to come up with the adder amount of capacity is “unduly punitive.”