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November 18, 2024

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Do Batteries or Transmission Produce Greater Benefits?

Adding battery storage to wind and solar resources increased generator revenues more than expanding transmission, especially in CAISO and ERCOT, but transmission expansion could relieve congestion in rural areas with plentiful wind and solar capacity, a recent study by the Lawrence Berkeley National Laboratory found.

The first-of-its-kind study assessed the benefits and drawbacks of transmission expansion and adding batteries to renewables in areas with transmission congestion. It looked at the findings from the perspectives of grid operators and generation owners.

“Both storage and transmission can increase grid flexibility, which is critical to the task of balancing system demand with uncertain variable renewable energy supply in real time, though they engage in different types of arbitrage,” the authors wrote.

“Storage shifts energy over time,” they noted. Optimally, batteries charge when electricity is cheap and discharge when prices rise. “Transmission shifts energy from one place to another,” moving lower-cost electricity to where it is needed to meet demand.

“Congestion occurs when transmission limits are reached and prevents low-cost resources from being fully utilized,” the study said. “Even [renewable energy resources], which have extremely low marginal costs of generation, curtail their output due to negative prices in some locations.”

Renewable resources and storage each affect transmission value, and “transmission capacity affects the commercial viability of generation and storage projects,” the study said. “So, understanding the dynamics of interplay between these asset types is essential to effectively plan for the changing grid.”

That is especially important because renewable generation and storage “are increasingly being built at the same locations in hybrid configurations,” it said.

For example, in CAISO, 99% of solar capacity entering the interconnection queue in 2021 was coupled with storage, it noted.

“These changes raise critical questions such as, ‘Will the shift towards hybrid plant deployment reduce congestion on the nearby transmission grid or will the shift necessitate additional actions to alleviate congestion?’” it said.

‘VRE-rich’ Areas

The study analyzed data from 23 locations on the U.S. bulk power system that experience significant congestion and have standalone solar and wind plants. The locations were in CAISO, ERCOT, ISO-NE, MISO, NYISO, PJM and SPP.

The findings from a grid operator’s perspective include:

    • Standalone wind and solar generators typically alleviate congestion near urban load centers and exacerbate congestion in rural areas with a high number of variable renewable energy (VRE) generators, which the study calls “VRE-rich” areas.
    • Standalone storage plants reduce transmission congestion in all areas.
    • Hybrid resources with renewable generation and storage alleviate congestion near load centers, but in VRE-rich areas, they can have different effects depending on their exact location and factors, such as whether batteries can charge from the grid.

For generation owners, the study found that:

    • Transmission expansion is generally a financial detriment to standalone wind and solar plants in load centers and a benefit to those in VRE-rich areas.
    • For hybrid resources in VRE-rich areas, expanding transmission typically increases revenue, but there are exceptions.
    • In VRE-rich areas, wind plants stand to gain “significantly more from transmission expansion,” while solar plants would benefit more from adding batteries.

“Solar plants in VRE-rich areas [could] expect to benefit from transmission expansion, but this benefit is dwarfed by the potential opportunity from installing storage, especially in CAISO and ERCOT, suggesting solar developers would be more invested in policies promoting hybridization than those focused on transmission,” the study said.

The solar plants in the study with the greatest per-MW revenue increase were in ERCOT ($200,000 to $380,000/MW-year) and CAISO ($50,000 to $91,000/MW-year) — both markets with a large share of solar generation.

The study’s authors said the results highlight the “different stakes that solar and wind developers have in local transmission expansion and how their priorities depend on a plant’s location and configuration.”

The results also “reveal previously unexplored ways in which policy, technology and contract terms related to hybrids can reduce the cost of congestion in local transmission systems,” the study said. “For example, policies incentivizing batteries at congested generation nodes may reduce congestion, since building storage alongside new VRE generators (either in hybrid or standalone configurations) is better, from a congestion perspective, than the standalone generator.

“Further, policies that allow hybrids to charge their storage component from the grid, instead of only from the VRE generator, result in lower costs due to congestion.”

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ERCOT Sets New Demand Mark, Will be Short-lived

ERCOT appears to have set another peak demand record on Monday, but if the grid operator’s projections hold out, the mark will be short-lived.

Demand averaged 81.56 GW on Monday during the interval ending at 5 p.m., according to preliminary data. That would break ERCOT’s current unofficial high for demand, when it averaged 81.41 GW July 13.

The grid operator’s six-day forecast indicates it will exceed 86 GW Tuesday, with average demand exceeding 83 GW through Friday. A high-pressure ridge and expanding heat dome have returned to the region and the southern U.S., diverting the jet stream away. Temperatures were forecast to be 5 to 15 degrees Fahrenheit above normal in much of Texas as excessive-heat advisories affect more than 100 million people from Washington state to Florida.

ERCOT says it expects to have sufficient generation to meet forecasted demand. It hasn’t called for voluntary conservation since June 20 and had more than 6.6 GW of operating reserves Monday afternoon. It did issue its third weather watch of the summer for Sunday through Tuesday due to the forecasted temperatures, electrical demand and potential for lower reserves.

The grid operator has averaged more than 80 GW demand for 18 intervals this summer. It reached the mark just once last year, setting a record that has been eclipsed 14 times already.

The clear skies again have led to near-record solar and renewable generation. Sun-powered resources averaged more than 12 GW for much of the afternoon; together with wind resources, they provided more than a third of ERCOT’s fuel mix for much of the day.

The U.S. Energy Information Administration says ERCOT’s solar and wind capacity will double by 2035, but it noted that without upgrades to the transmission system, its analysis finds wind and solar generation increasingly will be curtailed.

ERCOT had almost 10 GW of thermal outages on July 12. Staff use 8.3 GW as a high number in their modeling scenarios.

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MISO Monitor Again Sounds Alarm on Long-range Tx Planning

CARMEL, Ind. — MISO Independent Market Monitor David Patton appeared at this week’s Market Subcommittee meeting to again criticize the future resource mix assumptions the RTO is using to craft a second long-range transmission plan (LRTP) for its Midwest region.

Stakeholder reactions to his advice were mixed.

Patton has voiced concerns in this year’s State of the Market report over the capacity expansion model MISO is using to inform the portfolio, which could run the region several billion dollars. He said MISO isn’t considering enough future battery storage, hybrid resources, other dispatchable resource additions and grid-enhancing technologies as alternatives to an expensive transmission buildout. (See “LRTP Doubts,” MISO IMM Zeroes in on Tx Congestion in State of the Market Report.)

At the MSC’s meeting Thursday, Patton said battery storage is going to become “remarkably economic over time to reduce congestion caused by renewables.” He said MISO’s second transmission planning future’s projection that it will have 466 GW of mostly renewable nameplate capacity by 2042 is unrealistic. (See MISO Modeling Line Options for 2nd LRTP Portfolio.) MISO is anticipating having 31 GW of battery storage and 10 GW of storage-plus-renewable hybrid resources in that timeframe.

“Future 2 has almost no chance of happening, and yet we’re using it to plan tranche 2” of the LRTP, Patton said.

This is the first time Patton has raised concerns related to transmission planning in his report. MISO’s Board of Directors has wondered whether it’s appropriate for the Monitor to recommend a change in direction on transmission planning. Patton has argued that markets and transmission planning are inextricably linked.

American Transmission Co.’s Bob McKee and ITC Holdings’ Brian Drumm said Future 2 represents years of stakeholder debate and collaboration.

McKee asked whether Patton attended the stakeholder meetings to hash out the future planning assumptions. Patton said he “unfortunately” did not and wish he had.

“I’m all for consensus, but you can’t confuse consensus with fact. You can’t ignore that solar will have declining capacity value, and you can’t just imagine you’re going to keep building it and building it,” Patton said.

Michelle Bloodworth, of coal lobby group America’s Power, said she shared Patton’s concerns and that the second future should contemplate a realistic future resource mix.

Invenergy’s Sophia Dossin asked whether Patton has suggestions on how MISO can incent construction on batteries and hybrid resources.

Patton said the simple economics of MISO’s more attractive capacity accreditation for batteries, hybrid resources and natural gas plants will spur developers to build. He added that he isn’t expecting future bans on building new gas plants in every state in the footprint.

MISO will make a formal response to the recommendations in this year’s State of the Market report in December.

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Nevada Exits US Climate Alliance

Gov. Joe Lombardo has removed Nevada from the U.S. Climate Alliance, saying the group’s objectives conflict with his goal of developing a diverse energy portfolio for the state that includes natural gas.

The decision came to light as Arizona Gov. Katie Hobbs announced this week that the Grand Canyon State had joined the Alliance. Lombardo made no official announcement of Nevada’s exit from the Alliance, but Nevada’s absence from the group’s membership roster was noticed following Hobbs’ announcement.

“While the goals of the U.S. Climate Alliance are ambitious and well-intentioned, these goals conflict with Nevada’s energy policy objectives,” Lombardo said in a July 5 letter to U.S. Climate Alliance Executive Director Casey Katims, stating his decision to leave the coalition.

“These objectives are focused on developing and maintaining a diverse energy supply portfolio and utilizing a balanced approach to electric and natural gas energy supply and transportation fuels that emphasizes affordability and reliability for consumers,” Lombardo wrote.

Lombardo laid out his energy policies in a March executive order, including the state’s “advancement of energy independence.” (See New Governor Seeks Shift in Nevada Energy Policy.)

Nevada’s previous governor, Steve Sisolak, brought the state into the Alliance in 2019. Sisolak, a Democrat, was defeated in his reelection bid last year by Lombardo, a Republican.

Lombardo’s office didn’t respond to a request for comment.

Falling Short of GHG Targets

Formed in 2017, the U.S. Climate Alliance is now a bipartisan coalition with 25 members. Alliance members have agreed to work toward the Paris Agreement goal of keeping global temperature rise at less than 1.5 degrees Celsius. They collectively set a target to reduce greenhouse gas emissions by at least 26% by 2025 and 50% by 2030, compared with 2005 levels, and reaching net zero in 2050.

The GHG reduction goals are similar to those included in Nevada’s greenhouse gas inventory, an annual report required by state Senate Bill 254 of 2019.

The most recent GHG report, released this year, shows Nevada slipping further from those targets. The report details the state’s GHG emissions through 2020, with projections through 2042.

Nevada’s targets used as a benchmark in the report are a 28% reduction in GHG emissions by 2025 relative to 2005 levels; a 45% reduction by 2030; and zero or near-zero emissions by 2050. But the report projects only a 21.4% reduction in GHG emissions by 2025 and a 22.7% reduction by 2030.

And those reductions are slightly less than projections in the state’s GHG inventory from a year earlier, which forecast a 22.5% reduction in GHG emissions by 2025 and a 23.9% reduction by 2030.

In 2020, Nevada’s net GHG emissions totaled 37.3 million metric tons of CO2 equivalent, a 24.4% reduction from 2005 levels. GHG emissions in 2020 were less than the 2019 levels of 40.6 million metric tons. The report attributes the 2020 decrease to impacts of the COVID-19 pandemic, particularly on the transportation sector.

The transportation sector was the largest contributor to GHG emissions in Nevada, accounting for 32% of gross emissions in 2020, followed by electricity generation, which accounted for 31%.

For projecting future GHG emissions, the report makes several assumptions, including future retirements of natural gas-fired electric generating units. But the Public Utilities Commission of Nevada this year approved NV Energy’s request to postpone retirements of several gas-fired plants, as well as construction of a new 400-MW gas-fired peaker plant. (See NV Energy Rejected on Plan to Replace Coal Plant with Storage.)

Next year’s GHG inventory will likely factor in the recent PUCN decisions.

‘Door is Open’

Evan Westrup, communications director for the U.S. Climate Alliance, said Lombardo’s decision to leave the Alliance was disappointing, but “our door is open” if he changes his mind.

“As unprecedented wildfire smoke, record heat and catastrophic floods sweep across the country, we need every state and every governor — no matter their politics — confronting this crisis,” Westrup said in an email.

Westrup noted that newly elected governors in other Alliance states have opted to remain in the coalition, including the governors of Massachusetts, Hawaii, Oregon, Maryland and Pennsylvania.

Christi Cabrera-Georgeson, co-deputy director of the Nevada Conservation League, credited Lombardo for signing bills this year that will create more accountability and transparency in utility planning and promote clean energy.

But Lombardo’s decision to leave the U.S. Climate Alliance “contradicts these efforts and cedes Nevada’s leadership on clean energy and climate,” she said.

“This was a choice to prioritize utilities and their profits over everyday Nevadans who are already struggling to pay their energy bills amid record-breaking temperatures,” Cabrera-Georgeson said in an email. “By not prioritizing clean energy investments to diversify our job market and reduce greenhouse gas emissions, Nevada’s economy and environment will also suffer.”

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DTE, Activists Announce Agreement to Exit Coal by 2032

DTE Energy announced an agreement with Michigan officials and environmental and clean energy groups Wednesday to accelerate its emission-reduction efforts, add more renewable power and phase out coal use by 2032.

Under the agreement on DTE’s 20-year integrated resource plan, the utility will cut its power plant emissions by 85% in the next nine years, with the utility committing to net-zero emissions by 2050.

The proposed agreement (U-21193) will have to be approved by Michigan’s Public Service Commission, which is expected to consider it at its next meeting July 26. The PSC staff was among the parties to the settlement, along with Michigan Attorney General Dana Nessel and 21 environmental and clean energy groups and labor unions.

Coal Retirements

The deal will end the use of coal at the Monroe plant, the nation’s fourth-largest, by 2032, three years earlier than DTE had previously announced. In addition, DTE will convert its only other coal-fired generator, the Belle River plant in St. Clair County, to natural gas.

DTE will also close the gas peaker unit (11 MW) at the shuttered River Rouge coal plant and diesel peaker (5 MW) at the retired St. Clair coal plant in 2024.

The company agreed to begin conversion of Belle River within three years and to seek federal funding for the work under the Inflation Reduction Act.

Monroe Units 3 and 4 will be retired by the end of 2028 and Units 1 and 2 by the end of 2032, assuming no regulatory orders to keep them open or designation by MISO as system support resources. DTE said it will propose how to replace the power from the 3,400-MW Monroe plant in its next IRP, due in 2026.

The company pledged to offer retraining for employees impacted by the coal plant retirements and offer “economic development opportunities” for host communities.

Coal represented 77% of the company’s generation in 2005. For 2022, the company’s generation mix was 54% coal, 18% nuclear, 14% natural gas and 13% renewables.

15,000 MW of Renewables

The agreement was developed over two years of discussions. (See DTE CEO Hints at Accelerating Coal Plant Closures.)

There was some grumbling that the agreement was not as aggressive as Consumers Energy’s plan to end the use of coal by 2025. But overall, the advocacy groups were satisfied with the agreement.

DTE said the IRP also calls for developing more than 15,000 MW of renewable generation by 2042 and more than doubling its current storage capacity with the addition of 780 MW by 2030 and more than 1,800 MW by 2042. The storage plan will include 220 MW at the Trenton Channel Power Plant, a former coal plant.

Also, the company also will seek 150 MW of new demand response through competitive bidding in time for MISO’s 2027/28 planning year.

The IRP indicated no need for generation capacity in the next five years.

Nessel touted several other parts of the agreement:

    • $100 million in customer savings from securitizing at a lower rate more than $1 billion in early retired coal plant assets and reducing the return on equity on currently operating coal plants;
    • DTE’s donation of $8 million for energy efficiency and renewable projects for low-income customers and $30 million to reduce arrearages;
    • annual public disclosures of all contributions made by DTE and its regulated utilities that total $5,000 or more, including donations to tax-exempt 501(c)(3) and 501(c)(4) organizations;
    • increasing DTE’s cap on distributed generation from 1% to 6%; and
    • DTE’s allocation of at least $43.8 million to income-qualified electric energy waste reduction programs in 2024 and $53.8 million in 2025.

Activist groups said the agreement will reduce the health risks lower-income populations face from the power plants.

“This legal settlement commits DTE to an expeditious transition away from burning coal that is compelled by economics, public health and climate science,” said Earthjustice attorney Shannon Fisk. “With the Monroe coal plant — the third-largest climate polluter in the country — partially retiring in 2028 and fully retiring by 2032 (or possibly earlier), people in southeast Michigan will soon begin to breathe easier. Today’s settlement will accelerate the buildout of clean solar and wind power in Michigan, as well as battery storage, and it funds energy-efficiency programs.”

DTE CEO Jerry Norcia called the agreement “an investment in Michigan’s future.”

“We are grateful that 21 organizations from across Michigan have joined us in bringing our proposal one step closer to reality. This partnership and dedication have helped us build the best plan possible for our customers,” he said.

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MISO Intent on Marginal Accreditation and Requirements Based on Risky Hours

CARMEL, Ind. — MISO is holding to its plan to enact a widescale marginal capacity accreditation while announcing this week that it will swap risky hours for peak load to calculate its reserve margin requirements.

Officials at a July 11-12 Resource Adequacy Subcommittee (RASC) meeting said as part of MISO’s move to a probabilistic, direct loss-of-load accreditation for most of its resources, it will identify periods that have the highest potential for reliability risks in its loss-of-load modeling and set requirements from them. That process is set to replace MISO’s current practice of margin requirements established on peak load.

MISO also proposed a three-year transition to the direct loss-of-load accreditation, which will be based on generator performance during predefined tight operating conditions. The grid operator hopes to file the changeover with FERC in October or November. (See MISO Accreditation Impasse Persists at Workshop; MISO Stakeholders Debate Capacity Accreditation, RA.)

MISO’s Davey Lopez said staff will reach out to market participants in the coming months with accreditation results under a direct loss-of-load approach. He said MISO is working with Astrapé Consulting to estimate accreditation trends into the future under a transformed fleet. MISO plans to use results from its annual Regional Resource Assessment to publish forward-looking accreditation and planning reserve margin requirement estimates. (See MISO: 200 GW in New Capacity Necessary by 2041.)

“We will only make a filing after you all have seen both the…accreditation and the notional trend of what accreditation will look like under a different resource mix,” Executive Director of Market and Grid Strategy Zak Joundi pledged. He said MISO will build in its filing how it will share accreditation data from “a future-looking standpoint.”

Joundi said it makes sense for MISO to leverage the annually updated Regional Resource Assessment to predict the fleet mix MISO will be accrediting.

Joundi also said though MISO’s reserve margin calculations will be adjusted to focus on risky hours, they still will incorporate seasonal peak loads and still will solve to meet them.

“It’s just signaling that’s not where we’re seeing risk happening,” Joundi explained of MISO’s new calculation route.

So far, the accreditation change will not apply to load-modifying resources. Lopez said MISO plans to address LMR accreditation later.

MISO officials are wedded to the direct loss-of-load accreditation as stakeholders continue to have qualms with the lowered capacity credits for most resources and eventual near-zero capacity credits for solar generation that the design is likely to produce within a decade.

Stakeholders’ motion in spring to oppose a marginal approach to capacity accreditation passed with 31 members in favor, six voting against and eight abstaining from the email vote.

MISO’s Dustin Grethen said he “invited people to think of” MISO’s accreditation philosophy as what capacity is actually earned, versus the cruder, nameplate capacity-minus-forced outages MISO previously employed for its thermal resources.

During the May Resource Adequacy Subcommittee meeting, Joundi said MISO and stakeholders already have been debating accreditation design elements for the better part of two years.

“The way we landed on the proposal on the table was not by luck,” Joundi said, adding that MISO staff underwent months of analysis on the most beneficial accreditation design for the system. “We believe the current proposal…meets where we need to be to be ready for the future and is the most appropriate.”

Stakeholders pushed back on the timeline, saying that though discussions were held on accreditation concepts, MISO only settled on a draft design since early 2023.

Lopez said it just makes sense that accreditation should be directly derived from loss-of-load expectations.

“They’re in the same currency,” he told stakeholders at the May RASC.

MISO Independent Market Monitor David Patton said that MISO must continue its effort to assign realistic capacity accreditation to all units, despite stakeholder protest. (See MISO Accreditation Impasse Persists at Workshop.)

“There’s a lot of folks behind me that aren’t going to like an efficient accreditation regime because these resources are expensive to build, but if we’re not honest about that, we’re going to accredit resources that have no hope of meeting the planning margin,” Patton said during the spring MISO Board Week.

Patton said without an honest accreditation method, MISO runs the risk of not having “the resource base that we need to keep the lights on.”

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MISO Members Suggest Improvements After 1st Seasonal Capacity Auction

CARMEL, Ind. — In the wake of MISO’s first seasonal capacity auction, members have asked MISO to improve its generator outage rules, its preliminary data sharing and the registry tool used to track capacity.

MISO surveyed its members on what improvements it should prioritize before the 2024/25 Planning Resource Auction (PRA) in the spring. This week, the RTO said members had concerns over its 31-day outage threshold and said abiding by the rule is time-consuming and could produce a less reliable fleet. They also asked MISO to share preliminary PRA data sooner and better explain how it derives estimated capacity values. Finally, members singled out MISO’s nonpublic load forecast and resource registry for improvements, saying the current tool lacks a consistent naming convention, requires duplicative data entry of market participants and should have a dispute option for load and capacity values.

Stakeholders a year ago first requested better and more timely preliminary data ahead of the auction after the 2022/23 capacity auction laid bare a 1.2-GW shortfall across the Midwest region. (See “Stakeholders Ask for Data Improvements,” MISO Promises Stakeholder Discussions on Capacity Auction Reform.)

At a July 11 Resource Adequacy Subcommittee, Independent Market Monitor David Patton said he shared members’ concerns over the new 31-day limit on nonexempt unit outages in a season.

“One of our conclusions from administering mitigation and monitoring the market is it’s not an optimal structure,” Patton said. “When you have the 31-day grace period, it causes generators to move outages into two seasons.”

Patton said it’s “not great” to have generators avoiding penalties by nudging outage schedules so they straddle both spring and summer, where generator availability becomes critical. He underlined the drawback to the new outage rules in last month’s State of the Market report. (See MISO IMM Zeroes in on Tx Congestion in State of the Market Report.)

“We’d like outages to be taken based on when they’re the least costly to take and not be influenced by an arbitrary penalty structure,” he said.

Patton suggested MISO adopt more gradual penalties that account for the number of days a generator is unavailable so generator operators aren’t abruptly facing penalties at the 31-day mark that must be reflected in capacity offers.

Consumers Energy’s Erika Ward said she worried that generators will begin delaying maintenance to avoid outage penalties, risking catastrophic failures. But Patton said even without a capacity market, generator owners must balance missing out on payments versus undergoing necessary maintenance.

Executive Director of Market and Grid Strategy Zak Joundi said MISO doesn’t yet have a timeline on how it might adjust its outage limit.

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MISO FTR Underfunding Hits $60M in Spring, Improvements Coming in 2025

CARMEL, Ind. — MISO’s Independent Market Monitor this week reported that the RTO’s financial transmission rights market came up short by more than $60 million this spring.

At a July 13 Market Subcommittee meeting, IMM staffer Carrie Milton of Potomac Economics said the FTR spring underfunding can be chalked up to transmission outages that were shifted after the auctions and “topology” differences between MISO’s FTR market and its day-ahead market.

The IMM said it ultimately reported a transmission owner to FERC for failing to report planned transmission outages and acquiring undeserved FTRs.

MISO has become increasingly concerned over its congestion-hedging market’s underfunding in recent years. It has said there’s a growing discrepancy between awarded auction revenue rights (ARRs) and the footprint’s actual congestion patterns. As a result, load-serving entities hold a historically smaller share of FTRs, and the ARRs’ congestion value has fallen.

MISO has said it will adopt slow and measured modifications to its ARR and FTR market rather than enacting sweeping changes after a consulting firm found MISO’s market could use improvements to correct underfunding.

MISO favors a methodical approach where it makes one or two changes and then examines the impacts before revising further. The first change up for implementation is to adjust the rights allocation so it corresponds better to current network usage, rather than a more-than-10-year-old snapshot of the system. MISO doesn’t plan on introducing that change until 2025.

If enacted, the change would take care of London Economics International’s (LEI’s) most pressing recommendation that MISO’s market should be updated with new resource entries and retirements to better reflect transmission use. (See Financial Firm Finds MISO FTR Market Needs Work.)

MISO’s Jack Dannis has said MISO isn’t looking to rebuild its ARR/FTR process. He said a complete overhaul and redesign would be labor-intensive and unnecessary.

“We don’t feel that would align with LEI’s findings. They saw a lot of good in the market,” Dannis said during the April meetup of the Market Subcommittee.

MISO reported its year-end excess congestion fund disbursement was about $350 million in 2022, much larger than in previous years. The congestion fund is distributed back to transmission customers on a pro rata share after the year’s FTRs are fully funded. MISO said the larger amount in 2022 was due to a lower FTR shortfall last year, an increase in day-ahead excess congestion after hourly funding and an increase in monthly FTR auction revenues.

MISO issues the financial instruments based on transmission capacity; they are used by load-serving entities and other market participants as financial hedges against congestion charges in the day-ahead market. MISO funds FTRs through day-ahead congestion costs; an ARR is the LSE’s entitlement to a share of revenue from FTR auctions because of its historical use and investment in the transmission system.

Load-serving entities buy FTRs as a congestion hedge on the transmission system from their resources to load. They differ from the financial traders in the market, who seek profits.

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DOE Awards $90 Million for More Efficient, Resilient Building Codes

Only about one in three state and local jurisdictions across the U.S. have adopted the most recent ― meaning the most energy-efficient and resilient ― building performance standards, and the Department of Energy on Wednesday announced $90 million in grants to help some of the other two-thirds get up to code.

Funded by the Infrastructure Investment and Jobs Act, the awards are going to 27 projects across 26 states and Washington, D.C., “to ensure buildings meet the latest standards for energy efficiency,” according to the DOE announcement. “Modernizing energy codes is one of the most cost-effective ways to improve energy efficiency in homes and businesses and make communities more resilient to extreme weather events.”

The list of awardees range from organizations such as the American Council for an Energy-Efficient Economy (ACEEE), which will establish a National Building Codes Collaborative, to the University of Cincinnati, which will study cost-effective ways for Ohio’s large cities to design and implement efficient, equitable building codes.

Grants range from $1 million to ACEEE’s $9.6 million.

“Cutting emissions from buildings across America and ensuring they’re more energy efficient are critical components of President Biden’s plan to tackle the climate crisis and create cleaner, healthier communities,” Energy Secretary Jennifer Granholm said in the announcement.

The announcement comes as temperatures climbed into triple digits — and excessive heat warnings and watches were issued — in the Southwest, Texas and southern Florida.

According to DOE, the U.S. has about 130 million commercial and residential buildings that are responsible for 35% of the country’s total greenhouse gas emissions. The most recent building code — the 2021 International Energy Conservation Code (IECC) issued by the International Code Council — has been adopted by only five states, according to DOE’s Building Energy Codes Program: Vermont, Connecticut, New Jersey, California and Washington.

Half of the states are using codes that are more than 10 years old. The code is updated every three years, and work is underway on the version to be released in 2024.

An additional eight states are home-rule states, which have no statewide building codes; local jurisdictions determine what building codes are adopted. For example, in Colorado, Denver has adopted a “green” code that encourages energy-efficient, emission-cutting design and construction.

The impact of adopting more efficient codes can be significant. Homes built to current code are 40% more efficient than those built 15 years ago, DOE said. The department estimates that modernizing building codes across the country could save consumers $138 billion through 2040 while cutting GHG emissions by 900 million metric tons.

National Building Code Collaborative

Based on the list of awardees, the DOE funding is targeting regional and collaborative efforts with the potential to create replicable models that can be used in other jurisdictions.

ACEEE is working with the National Association of State Energy Officials and the Urban Sustainability Directors Network to establish the National Building Codes Collaborative, said Amber Wood, director of building programs.

“The big overarching view is that we intend the collaborative to basically … have webinars and technical assistance sessions where anyone and everyone is welcome,” Wood said in an interview with NetZero Insider. The goal, she said, is “advancing building energy codes … so we’re talking about new buildings as well as increasingly talking about building performance standards for existing buildings.”

In addition, ACEEE will be working directly with four states where the organization will provide staff “to help advance their energy code and build capacity,” she said. The states include home-rule state Colorado; Louisiana and Michigan, both of which have not updated their codes since the 2009 version of the IECC; and New Jersey, which has adopted the 2021 IECC but is getting ready for the 2024 update.

Wood says the roadblocks to building code updates may vary across states. “It depends on … how the legislation is set up. Is there opportunity to advance it?” she asked. “There’s obviously a lot of impact if you can get a whole state to go to a higher energy code, but there’s also a question of, can you get the localities to do that as well? How do you support both state and local jurisdictions to do this?”

Wood also pointed to the other benefits of updated building codes, such as public health, comfort and resilience. “Energy efficiency and decarbonization are extremely important, [but] that doesn’t resonate with everybody,” she said. “So how can we talk about some of the real benefits that maybe can hit a broader audience?”

Energy-efficiency ‘Circuit Riders’

On a smaller scale, ClearlyEnergy, a software firm in Severna Park, Md., will receive $2.9 million to create “regional cohorts” that will work together to adopt building performance standards and energy-efficiency programs, with a special focus on small, rural and environmental justice communities.

The company has developed software that allows small towns or other jurisdictions to digitize compliance with building performance standards, making it easier for building owners to provide their data, said Carolyn Sarno Goldthwaite, vice president of customer engagement.

The company is helping D.C. implement its building performance standards and is also partnering with agencies in Pennsylvania and West Virginia, which will be setting up their own regional cohorts, she said.

The cohorts “will help small, rural, underserved communities set up and establish both benchmarking [and] building performance standards,” Goldthwaite said. “Oftentimes, jurisdictions don’t have enough staffing to manage these policies, so they don’t adopt them, and so our cohort approach is that they can leverage one another, and they can set up a regional framework [that] all jurisdictions could use.”

ClearlyEnergy will also be providing on-the-ground technical support in the form of building performance standards “circuit riders”: traveling staff who will “help building owners understand how they can reduce their energy consumption in their buildings,” Goldthwaite said.

“We don’t want them just to adopt a policy and have this tool. We want to make sure we’re supporting them to actually do the energy reductions within those buildings.”

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Federal Plans to Electrify Highway Corridors Advancing

A five-year, $5 billion effort to establish a nationwide network of public EV chargers along designated highway corridors is pushing ahead as planned, according to a report on the first year of the National Electric Vehicle Infrastructure (NEVI) program.

The effort, launched in February 2022, required states to file their EV charging plans by Aug. 1, 2022, a relatively quick turnaround.

The Joint Office of Energy and Transportation received all 52 state plans by the deadline and the Federal Highway Administration approved them within two months, “unlocking $1.5 billion in funding for states to begin building charging stations through the NEVI formula program,” the report said. (See States File Plans on Deadline for EV Charging Funds.)

(The Joint Office was created through the Bipartisan Infrastructure Law in 2021 to foster collaboration between the Department of Energy and Department of Transportation.)

The largest recipients of the $1.5 billion funding in 2022/23 were Texas, which received $147 million, and California, which was awarded $138.5 million.

The Joint Office’s analysis showed that “most states already have adequate funding to become ‘fully built out,’” with EV chargers every 50 miles along 75,000 miles of designated alternative fuel corridors. Those corridors include 92% of the nation’s 48,000 miles of interstate highways and a third of the 230,000-mile National Highway System.

“Once fully built out, up to $3.5 billion in funding could be available for EV charging beyond designated corridors,” the report said.

As of March, 679 charging stations in the corridors met NEVI requirements for distance between stations and had sufficient charging ports and capacity, the report said.

The multi-year effort still has room for improvement in the areas of procurement, station siting, cybersecurity, program evaluation and community engagement, it said.

“These topics will be emphasized in technical assistance provided by the Joint Office,” it said.

Among the issues still to be worked out is the type of chargers required at NEVI sites.

There has been increasing concern that the North American Charging Standard (NACS) connectors used by Tesla are quickly becoming the national standard while federal NEVI guidance requires charging stations to be equipped with the rival combined charging system (CCS) connectors. (See EV Charging Efforts Ramp up on West Coast.)

In the past two months, automakers including Ford, General Motors, Mercedes, Rivian and Volvo have announced they plan to adopt Tesla’s NACS connector as Tesla begins opening its Supercharger network to non-Tesla vehicles.

Another question is how the U.S. will install the vast number of chargers needed to support a switch to electric vehicles.

While NEVI’s $5 billion is meant to jump-start the effort, a study by the National Renewable Energy Laboratory estimated that the U.S. needs 1.2 million public charging stations to support 33 million light-duty vehicles by 2030, the report noted. That will require 28 million charging ports, both public and private, and cumulative investments of $53 billion to $127 billion, it said.