FERC on May 14 granted Nevada Power an exemption simplifying the NV Energy subsidiary’s filing of its triennial updated market power analysis (ER24-1518).
In a March 15 filing, Nevada Power asked FERC to change its designation from a Category 2 to a Category 1 seller in the Southwest Region.
A Category 2 seller must regularly file updated market power analyses, while sellers in Category 1 are exempt from that requirement. For a Category 1 designation, a seller must own or control no more than 500 MW of generation in the region, and it also faces limits on owning or operating transmission facilities.
Nevada Power noted in its filing that even with a Category 1 designation for the Southwest region, it would still have a Category 2 designation in the Northwest region, and therefore would continue to file triennial market power analyses.
With Category 2 designations in both regions, Nevada Power would be required to file duplicate triennial updates six months apart, the company said.
“To be clear, unlike other entities that have filed to be relieved of or exempted from Category 2 status, Nevada Power is and will remain a Category 2 seller in the Northwest Region — its home reporting region — and will continue to submit full triennial analyses addressing the whole of Nevada Power’s horizontal and vertical holdings, including those holdings in the Southwest region,” the company said in its filing.
FERC denied Nevada Power’s request for Category 1 status in the Southwest region, saying the company was disqualified by its ownership of transmission facilities in that region.
According to Nevada Power’s filing, the company partially owns the El Dorado substation in the Southwest region and within the CAISO market, as well as the Navajo-Crystal-McCullough line and associated substations in the Los Angeles Department of Water and Power (LADWP) balancing authority area.
But FERC agreed to grant Nevada Power an exemption from the filing requirements for a Category 2 seller. FERC Order 697 allows the commission to evaluate exemption requests on a case-by-case basis.
“In our attempt to keep the Category 1 criteria as simple and straightforward as possible, we may have swept under Category 2 particular sellers whose circumstances make it unlikely that they could ever exercise market power,” FERC acknowledged in Order No. 697.
FERC ordered Nevada Power to submit a compliance filing within 30 days with a revision to its market-based rate tariff reflecting the exemption.
No interventions or protests were filed in the case.
Nevada Power filed an updated tariff in 2014 designating itself as a Category 2 seller in the Northwest and Southwest regions, and a Category 1 seller in the remaining four regions: Central, Northeast, Southeast and SPP.
At the time, the company owned or controlled more than 500 MW of generation in the Southwest region, but that’s no longer the case, the company said in its March 15 filing.
Before 2014, the relevant regions for the Nevada Power balancing authority area and for the BAA of its sister company, Sierra Pacific Power, were the Southwest and Northwest regions, respectively.
But the two BAAs were consolidated in 2014, when the One Nevada transmission line came online. Nevada Power’s home reporting area became the Northwest region under the consolidation.
National Grid introduced a pair of asset condition projects estimated to cost about $538 million at the ISO-NE Planning Advisory Committee on May 15.
The bulk of the cost, $491 million, would come from the refurbishment of a 115-kV line along the Vermont-New Hampshire border. The project would consist of replacing wood structures with steel poles, installing optical ground wire and moving part of the line toward center of the right of way to reduce tree damage.
The line was refurbished in 2008 but has since deteriorated because of damage from woodpeckers and exposure to the elements, said Rafael Panos of National Grid.
Some stakeholders expressed concern about the high cost of the project and the short lifespan of the previous refurbishment.
Abigail Krich, president of Boreas Renewables, asked whether National Grid has considered whether the line overlaps with needs identified in ISO-NE’s 2050 Transmission Study. The study identified the North-South interface along the southern borders of Vermont and New Hampshire as a high-likelihood area for overloads in coming decades.
“The region is planning to have conversations very soon about right-sizing projects like this one,” Krich said. “This is a really big project, and I’d hate to miss that opportunity.”
Panos agreed regarding the importance of avoiding a “subsequent rebuild” and said he would consult with the National Grid team about a potential overlap with the needs identified in the 2050 study.
Asset Condition Process Guide
Dave Burnham of Eversource Energy gave an overview of the draft asset condition process guide that was developed jointly by the New England transmission owners (NETOs).
The guide outlines how the NETOs monitor their assets, identify asset condition needs and select solutions. The document comes in response to requests from the New England states for more transparency and oversight on the asset condition process. (See States Press New England TOs on Asset Condition Projects.)
Burnham requested stakeholder feedback on the draft by May 29.
FERC Order 881
Brent Oberlin, executive director of transmission planning at ISO-NE, presented on how FERC Order 881 compliance will affect transmission planning. The order requires transmission providers to use ambient-adjusted line ratings to evaluate short-term transmission service and seasonal ratings for long-term service.
Oberlin noted the order does not require any changes to the ratings used in transmission planning but said ISO-NE intends to update its winter ambient temperature assumptions.
While ISO-NE’s winter planning assumes an ambient temperature of 50 degrees Fahrenheit, winter peak loads typically occur as the temperature drops, a trend that will increase with heating electrification, Oberlin said. To account for this, ISO-NE plans to assume 20 F for transmission planning.
Oberlin emphasized that ISO-NE has a lot of work to do to be ready for the July 2025 implementation date.
“We’re going to be coming in on two wheels to actually get this done,” he said.
ISO-NE on May 14 outlined for the NEPOOL Reliability Committee its work on a potential metric quantifying energy shortfall risk in the Northeast based on extreme weather to complement the traditional one-day-in-10-years loss-of-load expectation.
The so-called Regional Energy Shortfall Threshold (REST) is intended to be a “reliability-based threshold that reflects the region’s level of risk tolerance with respect to energy shortfalls during extreme weather,” according to the RTO. (See ISO-NE Details Proposal for Regional Energy Shortfall Threshold.)
As climate change causes extreme weather events to become more frequent, there has been growing concern that the widely used one-in-10 standard — requiring grid operators to procure sufficient resources so that its likely load is shed only one day in 10 years — is not enough to maintain reliability. (See related story, ERCOT Proposes ‘Multi-metric’ Approach for Reliability Standard.)
Once the REST is hit, ISO-NE would require certain measures based on possible 21-day extreme weather events. But the RTO still is working on the threshold’s exact value, what weather events would be used in the evaluation to set it and how often evaluations would be conducted.
ISO-NE told the committee that stakeholders prefer a metric based on expected unserved energy, defined as the expected amount of energy not supplied by the generating system during a certain period. It would consider the probability, magnitude and duration of an energy shortfall; percent of unserved load; customer impacts; and seasonal differences.
Jinye Zhao of ISO-NE said the RTO is considering a “maximum normalized seven-day energy shortfall,” which “would represent the system’s energy shortfall as a percentage of the system’s demand over rolling seven-day periods within the 21-day events.”
This metric would capture both the severity and duration of shortfall risks and would minimize the need for frequent major updates as demand and resource profiles change, Zhao said.
ISO-NE said it still is evaluating how it would establish the threshold for whichever metrics it selects and noted that it is “in the process of studying a number of additional 2027 winter events in order to help quantify a meaningful threshold.”
The RTO would rank all 4,680 possible 21-day weather events based on average system risk and select a top percentage of them to weigh against the threshold. It then would use the Probabilistic Energy Adequacy Tool (PEAT), developed with the Electric Power Research Institute, to quantify the selected set’s risks. (See ISO-NE Study Highlights the Importance of OSW, Nuclear, Stored Fuel.)
Regarding the assessments’ timing, the RTO said stakeholders have shown “a notable preference for seasonal assessments ahead of the winter and summer seasons,” as well as for annual PEAT assessments that look three to five years ahead.
“[ISO-NE’s] current thinking is that a seasonal assessment of operational peak periods for the energy shortfall risk against the REST criteria is most appropriate,” said Stephen George of ISO-NE. The RTO likely would perform these assessments two to four months in advance of a given season, he said.
“This timing would facilitate the use of the most up-to-date resource mix, demand profiles and fuel inventory assumptions,” while giving enough time to implement solutions to address shortfall risks, George said.
The RTO also is considering longer-term annual shortfall assessments to identify trends and upcoming risks, George added.
Once ISO-NE establishes the REST, it plans to embark on “a subsequent effort” to evaluate possible solutions to risks identified in the process, George said. Potential solutions include “market enhancements” and “responsiveness by end-use consumers.”
ISO-NE plans to provide more information on the REST at the July RC meeting and present a proposal in August, with the hope of presenting a final proposal by the end of the year.
Looking to protect the billions in private investment and thousands of new jobs spurred by tax credits in the Inflation Reduction Act, President Joe Biden on May 14 directed the U.S. trade representative to slap steep new tariffs on Chinese goods, including semiconductors, solar cells, battery components and electric vehicles.
Ranging from 25% on Chinese lithium-ion EV batteries and battery components to 100% on Chinese EVs, the tariffs could affect $18 billion in imports from the People’s Republic of China, according to a White House fact sheet.
“American workers and businesses can outcompete anyone — as long as they have fair competition. But for too long, China’s government has used unfair, nonmarket practices,” the fact sheet says.
Biden’s direction to U.S. Trade Representative Katherine Tai is authorized under Section 301 of the Trade Act of 1974, which allows the representative to investigate and act against foreign governments for “unjustified” or “discriminatory” actions that burden or restrict U.S. commerce.
Thus, a doubling of the tariff on Chinese solar cells, from 25% to 50%, is intended to “protect against China’s policy-driven overcapacity that depresses prices and inhibits the development of solar capacity outside of China,” the fact sheet says.
Global markets are glutted with cheap Chinese solar panels, which could increase available capacity to 1,100 GW this year — about three times expected demand — according to a recent report from the International Energy Agency.
In a separate announcement, Tai noted that the decisions to increase existing tariffs or impose new ones are the result of a mandated four-year review of the effectiveness of the tariffs already on the books. The report found that while current U.S. tariffs have prodded China to change some of its unfair trade practices, the country “has persisted, and in some cases become aggressive, including through cyberintrusions and cybertheft, in its attempts to acquire and absorb foreign technology, which further burden or restrict U.S. commerce.”
The report also found that the tariffs had helped spur production in the targeted industry sectors, while any related increases in consumer prices were mostly limited to goods subject to China’s own retaliatory tariffs.
The new increased tariffs target what the report calls China’s “big three” — solar, batteries and EVs — where Chinese exports have surged since 2022. They could go into effect approximately 90 days after publication in the Federal Register, which is expected next week, according to the U.S. trade representative.
Other tariffs on Chinese goods include an increase to 25% for lithium-ion batteries for stationary, non-EV storage and for natural graphite, a key battery component, neither of which will go into effect until 2026. Tariffs on a list of other critical minerals — such as cobalt, manganese, zinc and chromium — will jump to 25% this year, while those on semiconductors imported from China will double from 25% to 50%.
According to the report, the trade representative is also recommending 19 tariff exclusions for certain solar manufacturing equipment that is difficult to find outside China, which Solar Energy Industries Association CEO Abigail Ross Hopper quickly praised.
“A temporary tariff exclusion will help reduce production costs and incentivize increased investment in domestic manufacturing,” Hopper said. She also welcomed the delay on tariff increases for non-EV batteries, which she said “provides a runway for continued production and deployment of energy storage to meet growing demand for electricity.”
Spotty Record
The key questions now revolve around whether Biden’s decision could spark a renewed trade war with China, the extent to which the tariffs are calibrated to show the president as tough on China as the November election draws near, and the immediate impacts.
China responded quickly to the May 14 announcement, saying it “firmly opposes” the new tariffs, according to a statementfrom the country’s Commerce Ministry, reported by CNN.
“The increase in … tariffs by the United States contradicts President Joe Biden’s commitment to ‘not seek to suppress and contain China’s development’ and ‘not … seek to decouple and break links with China,’” the ministry said. “This action will seriously impact the atmosphere of bilateral cooperation.”
China would resolutely defend its rights and interests, and it urged the Biden administration to “correct its wrongdoing,” the ministry said.
As far as election-year impacts go, tariffs have had a decidedly spotty record as a spur to the domestic supply chain buildout needed to drive a clean energy transition in the U.S.
The Commerce Department’s International Trade Commission (ITC) imposed the first tariff on solar cells from China in 2012, followed by duties on solar cells from Taiwan in 2015. Under former President Donald Trump, the ITC imposed a 30% tariff on all imported solar cells, with the rate declining 5% per year for four years.
In 2022, the ITC imposed tariffs on solar cells and panels from several Southeast Asian countries — Cambodia, Malaysia, Thailand and Vietnam — where certain companies were found to be using Chinese components. Under heavy lobbying from the solar industry, Biden declared a two-year moratorium on those tariffs, which expires in June, and he has repeatedly said he will not extend the moratorium.
The bottom line is that solar tariffs have done little to provide the momentum needed for a major buildout of solar cell and panel manufacturing in the U.S. The ongoing tide of announcements was kick-started by the solar and advanced manufacturing tax credits in the Inflation Reduction Act.
At the same time, U.S. industry has been contending with supply chain and permitting issues and high interest rates, which could slow market growth. The residential solar market is expected to contract 13% year over year, according to industry analysts Wood Mackenzie.
On the upside, Elissa Pierce, a WoodMac research analyst, said she does not expect the increased tariffs to drive up prices of solar cells and panels in the U.S., due to the existing tariffs on Chinese imports.
“The U.S. imports very few of these products,” Pierce said in an email to NetZero Insider. “In 2023, just 0.03% of solar cell imports and 0.09% of solar module imports came from China, and this [minuscule] percentage continues to decrease even as Chinese module prices are bottoming out. In the first quarter of 2024, 0.02% of solar cells and 0.06% of solar modules were imported from China.”
‘Blunt Instrument’
The impact of Chinese imports on the EV market also could be negligible. While smaller, cheaper Chinese EVs are gaining ground in Europe, Trump-era tariffs — set at 25% — have kept them out of the U.S. market.
But unilateral action on tariffs, such as Biden is taking, is a “blunt instrument” that cannot solve all the challenges presented by China’s buildup of market dominance in EVs, batteries and solar, said Avery Ash, executive director of SAFE’s Coalition for Reimagined Mobility.
Focusing on the EV and battery tariffs, Ash said, “Addressing China’s unfair trade practices and market manipulation is [an] essential defense but must be coupled with effective offense — in this case, a clear national commitment to and strategy for the U.S. to double down on the development and deployment of market-defining technologies in the automotive sector. We’ve made early progress to this end in recent years, but much more is needed.”
Abigail Hunter, executive director of SAFE’s Center for Critical Minerals Strategy, also warned of the limited impact of unilateral tariffs on critical minerals. “Common border tariffs through a multilateral coordination with allies will be necessary to prevent dumping, and to block Chinese exports from causing global price collapses,” she said. “While challenging, such efforts are worth advancing in light of the devastating global impacts of China’s work to corner the market from minerals to EVs.”
SAFE, formerly Securing America’s Future Energy, is a nonprofit focused on advancing clean energy and EV technology and policy.
What the tariff announcement cannot conceal is that despite ongoing announcements of new factories and billions in private investment, the domestic supply chain buildout for solar, batteries and EVs is frustratingly slow. The solar industry continues to depend on imports from Southeast Asia, and U.S. automakers have slowed their rollout of EVs as the domestic content provisions of the IRA have narrowed the number of models eligible for the law’s $7,500 EV tax credits.
WoodMac’s Pierce added that “U.S. solar manufacturers are still relatively dependent on China for other module components, such as glass and wafers. While these products are also subject to the Section 301 tariffs, it doesn’t look like the tariff rate on these will be increased.”
And according to a report from Solar Power World, the Commerce Department is weighing yet another petition from a group of U.S. solar manufacturers to proceed with tariffs on companies in Southeast Asia, which the manufacturers allege have been circumventing rules on Chinese content in certain solar panel components. Commerce has yet to rule on whether it will take any action on the petition.
Three years after a deadly winter storm nearly imploded the ERCOT grid, killed hundreds of Texans and caused billions in financial damages after blackouts lasted for days, stakeholders in the Texas market have begun working on a reliability standard that may be stricter than industry norms.
ERCOT is proposing a “multi-metric” framework that establishes thresholds on three criteria: frequency, duration and magnitude of loss-of-load events.
Its baseline recommendations would set a loss-of-load expectation (LOLE) frequency of once every 10 years; 14 hours of rolling outages during an event; and no more than 19 GW of load shed to maintain the ability to roll the outages (54584).
The grid operator said using maximum magnitude as a probabilistic measure addresses a key physical reliability constraint: how many megawatts can be effectively managed at one time for rotating load shed purposes. It included maximum duration because one reliability policy constraint is the acceptable length to customers of an outage event.
Pete Warnken, ERCOT senior manager of resource adequacy, told the Texas Public Utility Commission during a May 2 technical workshop that after Winter Storm Uri in 2021, it became clear that the industry’s normal one-in-10 LOLE wasn’t enough on its own. He said staff reviewed other grid operators’ reliability standards and dug into background materials to come up with their proposal.
“One overarching theme became apparent: Simply relying on the 0.1 LOLE industry standard was not acceptable, and any reliability standard for ERCOT needed to expand beyond this single metric,” Warnken said. “There is an expectation for the commission to establish a reliability standard for ERCOT and take action to ensure the reliability and needs of the region are met both in the near and long term.”
The 2021 storm came 10 years after a less severe cold weather event in 2011. The rolling outages during the week leading up to Super Bowl XLV, played in the Dallas-Fort Worth area, were shorter and less severe than Uri’s.
“It makes me think that at a basic level, we are hitting that one-in-10 standard, but we’re still getting the massive outages that we want to try to avoid,” Commissioner Jimmy Glotfelty said. “So, semantics. Two massive outages in 20 years, that’s one in 10.”
The commission and stakeholders generally supported ERCOT’s approach.
“I think what ERCOT is proposing makes sense,” PUC Chair Thomas Gleeson said, expressing more interest in what market participants had to say.
“This is probably the most important policy decision this commission is going to make in terms of the impact to the state and reliability for our system,” NRG Energy’s Bill Barnes said, adding that his company “strongly supports” the resource adequacy-based reliability standard.
“We feel that this is the missing piece of our market structure. For the most important reliability type of our grid, resource adequacy, up to this point it’s been a shoulder shrug and, ‘Let’s just see what we get.’ That’s why this is such an important decision,” he added.
Katie Coleman, representing Texas Industrial Energy Consumers and its large industrial users, said the standard could be a “useful tool” as a reference point to decisions on whether to increase the offer cap, change the shape of the operating reserve demand curve or add ancillary services.
“There’s a lot of judgment involved in a reliability standard. It’s extremely imprecise,” Coleman said. “We continue to have concerns about using it as a single reference point to move billions of dollars around through a capacity construct. So that’s our sensitivity, but not the reliability standard in and of itself.”
‘Reasonable Starting Point’
PUC staff have since filed a memo responding to several points made during the technical conference. It lays out the decision points staff say it needs to prepare a proposal for the reliability standard’s rulemaking.
The commissioners will use the memo as the basis for discussions during their May 16 and 23 open meetings. A final rule could possibly be published by June 13, and a final PUC vote taken on the rule in August.
Commission staff said they view ERCOT’s approach to a reliability standard recommendation to be a “reasonable starting point” and that a commission-approved standard is “essential to achieving long-term resource adequacy.” They said setting the LOLE at close to one event every 10 years is a “reasonable benchmark” that alternative values can be compared to.
“At a minimum, the commission-approved reliability standard should target a level of reliability that is comparable to other markets and regions across the country,” they said in the memo.
Staff also noted that adopting a reliability standard does not require implementing the performance credit mechanism (PCM), saying it is not the only tool that could be used to meet the standard. They suggested “alterations” to existing ancillary service products, new reliability products or changes to the scarcity pricing signals as other policy options that could be “tailored” to affect reliability standard metrics.
While staff agreed with using the industry’s one-in-10 LOLE standard, they found setting a firm megawatt value for the 19-GW magnitude metric is not appropriate as it is directly tied to the system’s operational capability. They suggested a 0.25% exceedance probability for magnitude and updating the metric on a predictable, scheduled basis that aligns with future load-shed capabilities.
Staff also recommended the duration metric be reduced to 12 hours, with a “more relaxed” 1% exceedance probability. They noted ERCOT’s emergency pricing program will kick in after prices have been at the high systemwide offer cap for more than 12 consecutive hours.
According to ERCOT’s cost analysis, a 0.1 LOLE is not enough to constrain the maximum magnitude to 19 GW; instead, it would require a 0.04 LOLE. The incremental system cost to achieve this increased reliability is between $195 million and $271 million per year above the amount that supports a 0.1 LOLE, staff said.
ERCOT’s sensitivity variables include using weather years dating back to 1980 to ensure a “robust weather history” is accounted for. It also suggests a retirement assumption of 900 MW over the next several years and using combustion turbines for capacity, as the latter can be converted into any other combination of resource types.
American Electric Power’s Ohio utility is asking state regulators to create new tariffs forcing data center developers to pay for 90 to 95% of their projected electrical demand for their first decade of operation, even if they use less (24-0508-EL-ATA).
AEP Ohio filed the application with the Public Utilities Commission on May 13. Utility President Marc Reitter said in a news release that the company needs that level of commitment to make the investments required to supply the power-intensive facilities being planned in large numbers in its territory, particularly Central Ohio.
The proposals would apply to new data centers with a maximum monthly demand of at least 25 MW at a single location or mobile data centers, such as cryptocurrency mining operations, with a maximum monthly demand of at least 1 MW. Data centers that already have signed agreements with AEP at the time the proposed tariffs took effect would be subject to its existing general service tariffs, at least initially.
According to its filing, AEP’s peak demand in Central Ohio is approximately 4,000 MW, and it has signed binding electric service agreements for 5 GW of new data center load to come online by 2030. But more than 50 customers have submitted requests reserving over 30 GW of additional load.
“AEP Ohio’s current tariffs were not designed to address (and did [not] contemplate) either the current growth curve based on hyperscale data center development or the unique demands for serving this new class of data center customers,” it said.
There is also no RTO-controlled generation in Central Ohio, so AEP must import power over the 765-kV backbone system. Using existing transmission, the company will be able to import enough power to serve the new data centers with the 5 GW it has committed to, but serving additional data centers would require construction of new lines at great cost and time, it said: 120 miles of 765-kV line would take seven to 10 years and hundreds of millions of dollars to build.
In March 2023, AEP imposed a temporary moratorium on data center service requests in Central Ohio so it could analyze the likely impact of future data centers. It will keep the moratorium in place until its proposal is resolved.
The utility argued in its filing that state law requires it to serve all customers in its service territory, but not in a way that would be unreasonable or impose unjust risk for the company or its other customers.
Data centers would be billed for the greater of 90% of their contracted capacity or the highest previously established billing demand in the preceding 11 months. That would increase to 95% for mobile data centers.
The proposed tariffs would also:
require contracts for an initial term of at least 10 years;
include an exit fee for customers that leave early;
impose security and collateral provisions determined by AEP to protect against customer bankruptcy or other failure to meet financial commitments;
impose technical requirements such as a ban on intentionally or unintentionally cycling load in a way that unbalances system frequency; and
mandate participation in the PJM Emergency Demand Response Program and in any emergency event declared by AEP Ohio, with potential service disconnection if the customer does not respond.
In its request, AEP said it expects data centers to hold at least the top five spots on its list of largest customers by 2030.
“AEP Ohio has helped the state of Ohio attract thousands of new jobs and billions of dollars in investment because over the decades, AEP has built an extensive network of transmission lines to deliver the power these customers need,” Reitter said in the company’s statement. “This is one of the reasons data center developers targeted Central Ohio, and they continue to request large amounts of power. We need to ensure they can follow through with their commitments as significant new investments are made to serve them.”
BALTIMORE — Panelists during the General Session at PJM’s Annual Meeting last week focused on the evolving security and climate risks the electric industry faces, as well as the potential for technology and a culture of creativity to provide new solutions.
Delivering the keynote speech, Elisabeth Braw, senior fellow at the Atlantic Council’s Scowcroft Center for Strategy and Security, said hostile geopolitics are clashing with a globalized economy, putting companies across the world at risk of being caught in the crossfire.
Because cybersecurity threats are global and often have more to do with national policies than the actual targets, she said individualized efforts at preparation can go only so far. Instead, she recommended organizations work together to identify vulnerabilities and share strategies.
That coordination often should include the public as well: One mistake Braw said many working in critical infrastructure make is being too tight lipped about the risks they face and their mitigation efforts. She pointed to the cyberattack that interrupted Colonial Pipeline operations in 2021, saying the impacts of the attacks were manageable but that an underinformed public began panic-buying gas and compounding constraints on the pipeline.
Braw was joined on a panel about the intersection of risk management with national and world events by NERC Vice President Manny Cancel and Paul Williams, president of the Electric Infrastructure Security (EIS) Council. The panel was moderated by PJM Chief Risk Officer Carl Coscia.
Cancel said joining a regional information sharing and analysis center (ISAC) can allow smaller organizations, such as municipal electric providers, to develop the broad expertise and awareness that large utilities often hold.
Williams said resilience is possible only through working with the communities an organization is part of. Understanding which services are most important to customers, and which business functions are needed to maintain those services, is key. As the former head of the Bank of England’s Operational Risk and Resilience Division, he said ATMs may seem like a core need, but what truly is important to users is access to cash — an understanding that creates opportunities for building resilience even if ATM networks are disrupted.
Turning to climate risks, Cancel said the largest challenges are the siting, permitting and interconnecting of new generation and harmonizing the clean energy transition with reliability needs.
Maintaining the infrastructure the grid requires now and throughout the transition will require honest conversations with the public about what the costs will be, Williams said.
Innovation Potential and Challenges
Another panel on applied innovation largely focused on the double-edged sword of the rising capabilities of artificial intelligence.
Jonathan Glass, acting deputy director for commercialization at the U.S. Department of Energy’s Advanced Research Projects Agency — Energy (ARPA-E), said AI could speed research into new storage and generation technologies — as well as improve the process for interconnecting them — but the electric industry first will need to get over the hump of rapidly increasing load growth over the next few years as data centers come online.
Arshad Mansoor, CEO of the Electric Power Research Institute (EPRI), said AI development is in the “first mile of a marathon” that could see unprecedented load growth over the next few years, potential business that could flow to other nations if the electric sector cannot keep up. He said the next three to four years will be the most important in laying that groundwork, which will have to involve expanding load flexibility while new generation and transmission are built.
“The country, the region that can power this infrastructure will win the AI race,” he said.
Mansoor said there’s a disconnect between the personnel working in the electric industry and on the data center side and that more understanding between the two is needed. Forecasting data center demand is changing constantly as computational needs increase and breakthroughs are made in the efficiency of hardware.
Consumer behavior also could be part of the solution, said Arushi Sharma Frank, principal of Luminary Strategies, such as creating virtual power plants using electric vehicle batteries, home storage systems and smart meters to reduce load during peak periods and shift it to more economical times.
Perfecting such technologies will require creative thinking and data analytics skills, Frank said, a pairing that is in demand across industries. Loosening regulations around hiring and immigration could allow individuals working overseas to contribute.
FERC issued Order 1920, its long-awaited final rule on long-term regional transmission planning and cost allocation, during a special meeting May 13, but it could not fulfill hopes for a unanimous vote (RM21-17).
The order requires regional transmission planners, including ISOs and RTOs, to plan at least 20 years ahead of time using multiple scenarios while taking into consideration seven benefits:
avoided or deferred reliability transmission facilities and aging infrastructure replacement;
reduced loss-of-load probability or lower planning reserve margins;
production cost savings;
lower line losses;
lower congestion from transmission outages;
mitigation of extreme weather events and unexpected system conditions; and
capacity cost benefits from reduced peak energy losses.
Planners will have to give state entities six months to agree on a cost-allocation method, but they also have to propose a default method. They can decide to push through their default method and will not be required to file any alternative states come up with.
That ability to override state desires — plus the end of the separate consideration of economic, reliability and public policy lines — led to Commissioner Mark Christie dissenting on the entire order, while Chair Willie Phillips and Commissioner Allison Clements filed a joint concurrence.
“Not everybody is going to get everything that they want,” Phillips said during the meeting. “I don’t even get everything that I want, but that is the nature of these large proceedings and these large rules here at FERC. This rule cannot come fast enough. There is an urgent need to act to ensure the reliability and affordability of our grid. We are at a transformational moment for the electric grid with phenomenal load growth from a domestic manufacturing boom, unprecedented construction of data centers fueling an AI evolution, and ever-expanding electrification.”
The resource mix is at an inflection point with aging infrastructure needing replacement, and a higher incidence of extreme weather has cost consumers billions of dollars over the past decade, he added. Transmission expansion has not kept pace with the changes, falling to an all-time low in 2022, and much of that was “Band-Aid” fixes, Phillips said.
In addition to ending public policy as a separate consideration, Christie also criticized the final rule’s requirement that planners consider demand from large corporate customers favoring specific generation types to serve their operations.
“If we’re going to mix reliability projects with public policy projects, and these corporate-driven, preferred purchasing projects, then it’s only fair that state regulators have to have the ability to consent to the planning criteria, and especially the cost allocation in a big, big multistate RTO, like PJM,” Christie said in an interview. “That is absolutely essential. So that’s not in there now. There’s no requirement that states have to consent.”
The NOPR did not spell out what would happen if states cannot come to an agreement, instead asking for comment on the issue. Clements told reporters that the decision to have a federal backstop made sense based on the record.
“We need to have a federally jurisdictional backup if the states don’t come to agreement, and that is why we have a backstop ex ante approach,” Clements said. “States don’t have to use it; if they get together in a region and want to do something different — great.”
The point where state regulators and an RTO might split on cost allocation is not going to occur until after the rule is implemented, she said. “But I wouldn’t suggest it’s a wise approach,” Clements said of regional planners overriding states. “I think transmission providers want this to work as well and are looking forward to working with the states.”
Christie questioned why the majority even voted to let regional planners, including ISO/RTOs and groups of utilities outside them, override state cost-allocation preferences.
“If you don’t think they’d ever do it, then why wouldn’t you agree to give the states the ability to consent?” Christie said. “Because the fact is, they can ignore it.”
Phillips noted that he and Christie knew each other as members of the Mid-Atlantic Conference of Regulatory Utilities Commissioners before they came to FERC. He said he would never support a rule that tramples states’ rights in the planning process.
“There’s a lot that Commissioner Christie said that I simply do not agree with,” Phillips said. “But I do agree with this: The most important job of our commission is reliability. I’ve been saying that since Day 1. So let me be clear now, because this rule is about reliability and affordability: I have complete confidence that it will be legally durable and that it will be upheld.”
Another area where the three commissioners could not agree is whether the rule is reacting to the industry’s realities or actively seeking to drive the grid toward a preferred future.
“It is not our job to do resource planning,” Clements told reporters. “States, private actors — they engage in choosing what kind of resources they want to have. It is the commission’s job to facilitate reliability and affordability of the transmission system in light of the choices that states and other actors are making outside of the agency.”
Christie argued that the rule was being pushed out along with other policies the Biden administration favors. He noted in his dissent that he quotes several press reports linking the transmission rule to efforts to combat climate change.
“What this is doing here is attempting to enact a major policy agenda that has never been passed by Congress,” Christie said. “And that alone makes it a major question. So, it’s a very important point in my dissent that this is not within the authority of FERC under the Federal Power Act.”
The order will go into effect 60 days after its publication in the Federal Register. Transmission providers will be required to submit compliance plans for most of the order’s requirements within 10 months of the effective date.
FERC Pulls Back on ROFR Rollback
One aspect of the NOPR that drew considerable debate was the proposed partial rollback of Order 1000’s elimination of most federal rights of first refusal, which opened regionally planned lines to competition. The commission had proposed establishing a conditional ROFR when a utility works with a partner on a project.
The change was a major priority for utilities and their trade groups, including the Edison Electric Institute and WIRES Group, but it was opposed by competitive transmission developers, consumer groups and the Federal Trade Commission.
The commission required transmission providers to identify opportunities to modify in-kind replacement of existing facilities to increase their transfer capability, known as “right-sizing.” Utilities will get to keep a federal ROFR over such right-sized projects that are in their territories.
Order 1977 on Backstop Transmission Siting
FERC also issued Order 1977, which implements its new congressionally mandated authority to site transmission lines in a National Interest Electricity Transmission Corridor even when state regulators reject them (RM22-7). All three commissioners supported this order.
The order “includes a Landowner Bill of Rights, codifies an Applicant Code of Conduct as one way for applicants to demonstrate good-faith efforts to engage with landowners in the permitting process, and directs applicants to develop engagement plans for outreach to environmental justice communities and tribes,” FERC said.
The one major change from the proposal was that FERC will not let transmission developers file for its siting approval at the same time as a state is reviewing a line. They will instead have to wait a year.
The order will take effect 60 days after its publication in the Federal Register.
Initial Takes
Senate Majority Leader Chuck Schumer (D-N.Y.) held a press conference call while FERC was still meeting to praise the final rule.
“The clean energy incentives included in the Inflation Reduction Act have been a huge success,” Schumer said. “But much of that success would be lost without the ability to bring power from places that generate renewable energy to communities all across the country. A new historic advancement in our transmission policies has been desperately needed, and the rules released by FERC today will go a long way, a very long way to solving that problem. Simply put, these new rules will mean more low-cost, reliable, clean energy for the places that need it most.”
Many proposed bills have been introduced this Congress to address transmission and other permitting issues, with Senate Energy and Natural Resources Committee Chair Joe Manchin (D-W.Va.) and Ranking Member John Barrasso (R-Wyo.) trying to get a deal through to simplify building infrastructure. Schumer said such efforts will be hard to get past a divided Congress this year.
“I’ve told Joe Manchin it’s going to be virtually impossible to get something done,” he said.
For his part, Barrasso blasted “FERC’s partisan vote,” arguing it would only add to electricity’s growing costs.
“Today’s decision will force customers — often in rural states — to pay for new transmission lines even when those lines don’t provide any meaningful benefit to them,” Barrasso said. “It is the Holy Grail for liberal politicians in California and New York and corporate executives who want others to foot the bill for their climate obsession. I have no doubt the cost of energy will be at the top of every voter’s mind later this year.”
House Democrats welcomed the final rule, with Reps. Sean Casten (D-Ill.) and Mike Levin (D-Calif.), co-chairs of the Sustainable Energy and Environment Coalition’s Clean Energy Deployment Task Force, calling it a vital step toward a fully clean economy. Despite Schumer’s doubts, they said they would like to pass additional legislation on transmission — especially their own Clean Electricity Transmission Acceleration Act.
“This rule takes steps towards ensuring our grid is meaningfully planned and the costs of the necessary transmission buildout are fairly distributed by those who will benefit from the new capacity,” they said in a joint statement. “Americans today are already bearing the costs of an improperly planned grid; transmission planners have thus far not adequately accounted for the new forms of cheap, clean energy that are being deployed on the grid at an accelerating pace. A reliable, affordable and clean grid is only achievable with proper, comprehensive and forward-looking grid planning.”
Americans for a Clean Energy Grid praised the rule, saying it ensures the grid will be planned in a proactive and comprehensive way.
“Now, it’s time to implement this rule,” ACEG Executive Director Christina Hayes said. “Regions must develop their compliance filings over the next few months so that transmission can be planned and developed as soon as practicable. We look forward to working with and supporting the interested parties as they move forward with the next steps in compliance and build out the 21st-century grid.”
Advanced Energy United welcomed the rule, saying it would help lower consumer bills by making a more efficient grid and opening access to cheap power.
“Families and businesses are paying the price for utilities’ and grid operators’ failure to address our critical electricity infrastructure needs,” CEO Heather O’Neill said in a statement. “Building more multistate transmission lines unclogs the traffic jams on America’s electricity superhighways and unlocks our ability to keep up with our growing energy needs. This FERC order sends the message that transmission planning needs to change and recognizes that states deserve a central role in ensuring a reliable electric grid built for the future.”
EEI was not as enamored as the clean energy trade groups, citing disappointment with the decision not to roll back Order 1000’s ROFR provisions, among other issues.
“Additionally, the failure to provide regional flexibilities for evaluating project benefits in the final rule will lead to longer compliance processes and, ultimately, could slow the development of much needed transmission projects,” EEI Vice President of Regulatory Affairs Phil Moeller said in a statement. “A one-size-fits-all approach does not work, as different regions have different needs and different states have different policies.”
Environmental groups generally praised the final rule, with Sierra Club Executive Director Ben Jealous saying it “follows the letter of the law” and will save ratepayers money.
“As President Biden’s Inflation Reduction Act continues to usher in the clean energy future through deployment of solar, wind and battery storage, this transmission standard will allow utilities to deliver Americans clean, affordable electricity, even in the face of rising demand and extreme weather caused by climate change,” Jealous said in a statement. “With the standard now in place, FERC must be vigilant to ensure strong implementation in order to maximize the benefits for reliability and consumers.”
For much of its early history, Boston was a city expanding into the sea.
A hilly peninsula prior to colonization, the city began the labor-intensive process of removing its hilltops to fill in the surrounding coves, marshes and mud flats at the end of the 18th century.
The summit of Beacon Hill, adjacent to the Massachusetts State House, was carted off in the early 1800s, while Mount Vernon and Pemberton Hill, which formed the peninsula’s “Trimountain” landmark alongside Beacon Hill, fared even worse. In the words of Boston historian Walter Muir Whitehill, “the hills have all but disappeared.”
Today, more than half the city is built on a landfill foundation of former hilltops and assorted city waste. As a result, a major portion of Boston’s streets, bars, apartments and power infrastructure are located just above historical flood lines.
Boston topography 1630 to present | The Boston Public Library
The outward expansion has enabled Boston to become the city it is today but also has made it especially vulnerable to the rising tides that threaten to force the city into retreat.
By 2100, the sea level around Boston is projected to rise by two to five feet, according to a 2022 report by the University of Massachusetts Boston.
The report projected precipitation intensity to increase by 20 to 30%, while sea level rise likely will push up groundwater levels and increase groundwater salinity along the coast. If emissions continue at current rates, 100-year flooding events could become annual occurrences by the end of the century.
“Risk-averse end users of these projections should consider the possibility of sea level outcomes above the likely range, especially under higher GHG emissions,” the UMass report noted. “For long-term planning and long-lived coastal assets, we stress that sea level will continue rising beyond 2100 under all GHG emissions scenarios.”
Rising Costs of Resiliency, Recovery
In Boston and throughout the broader region, climate-fueled extreme weather events already are stressing essential energy infrastructure.
“We see a lot of concern about the ability of the grid to withstand even current — not to mention future — storms, sea level rise and other climate impacts,” said John Walkey, director of climate justice and waterfront initiatives at the environmental justice nonprofit GreenRoots.
As climate change accelerates, “all our past planning and forecasts go out the window,” Walkey said.
Massachusetts’ electric utilities have incurred major costs associated with storm recovery in recent years. Eversource, one of the state’s two major electric distribution companies, is seeking to recover about $339 million in costs associated with three storms that occurred between 2021 and 2022, including $176 million from a single 2021 Nor’easter (D.P.U. 22-143).
Over the past decade, Eversource’s contributions to its storm fund, which is intended to stabilize the impacts of storm costs on ratepayers, have increased from about $5 million to $31 million annually (D.P.U. 22-22).
In the fall of 2021, Eversource reported its storm fund had a $122 million deficit, which the company attributed in part to increasingly frequent storms “due to weather patterns and meteorological characteristics associated with climate change.”
In a recent interview, Massachusetts Department of Public Utilities Chair Jamie Van Nostrand emphasized it’s the utilities’ responsibility to prepare their systems for increasing pressures from climate change.
With more frequent and severe extreme weather events and increasing property values, elevated storm costs are “not necessarily a matter of the utilities being imprudent,” Van Nostrand told RTO Insider. “But we’ll also be looking closely at, ‘Could that have been avoided? Could you have designed your system in a way that would have been more resilient?’”
In 2022, Massachusetts passed a bill requiring the state’s electric utilities to file electric-sector modernization plans (ESMPs) with the DPU every five years. The bill requires the utilities to detail how they plan to upgrade their systems to facilitate the clean energy transition and mitigate climate damage. (See Mass. Utilities Submit Grid Modernization Drafts.)
The utilities filed their final plans in January, which the DPU should rule on in late August, Van Nostrand said.
“Even without that specific statutory directive, I think that part of our job is to put the utilities on notice that we’re watching, and we want you to take [climate resilience] into account,” Van Nostrand said, adding that utilities will “run the risk of a prudence disallowance” if they incur costs that could have reasonably been avoided by proactive climate mitigation.”
The utilities’ ESMPs outline major investments to meet increasing peak loads and enable the transition to more distributed generation. Eversource estimates it will need to build 17 new substations and upgrade 26 substations by 2035.
“It’s very timely that we’re looking at the climate change resilience piece,” Van Nostrand said, “because we’re going to be installing a lot of substations, upgrading a lot of substations, and we want to make sure the utilities are mindful as they’re making all these investments.”
While storm costs are often driven by downed trees and branches, large flooding events can pose a significant threat to substations.
National Grid, Massachusetts’ other major electric utility, noted in its ESMP filing that flooding in its Rhode Island service territory in 2010 forced the company to remove eight substations from service and caused “significant customer outages and loss of high-value substation equipment.”
The company wrote that it used Federal Emergency Management Agency (FEMA) flood maps to analyze its substation fleet in the aftermath of the events to identify vulnerabilities.
“Flood mitigation efforts have been implemented at approximately 40 substation locations with approximately 20 additional projects planned,” National Grid wrote.
Elli Ntakou, Eversource’s manager of system reliability and resiliency planning, said the utility assesses risk based on FEMA flood data and sea level rise projections from the City of Boston and the National Oceanic and Atmospheric Administration.
“Especially for sea level rise, we want to be comprehensive,” Ntakou said.
Elevation in East Boston
Sea level rise resiliency has been one point of contention in the lengthy fight over Eversource’s proposed substation on the banks of Chelsea Creek in East Boston, which has led to demonstrations and arrests of protesters attempting to stop construction.
Environmental justice organizations and residents have argued Eversource failed to conduct adequate community engagement on the project and have expressed concern that future climate-driven flooding could inundate the substation, endangering the surrounding neighborhood.
GreenRoots and the Conservation Law foundation have a pending legal challenge before the Massachusetts Supreme Judicial Court regarding the Energy Facilities Siting Board’s (EFSB’s) approval of the project (EFSB 14-04A).
“We don’t feel as if they really prepared for the lifespan of this facility, [or] they prepared for the lifespan of a transformer,” said Walkey of GreenRoots, adding that substations can last for more than a century.
Eversource considered sea level rise over a 40-year equipment lifespan and selected a design flood elevation — “the lowest elevation at which the Substation equipment should sit on the site” — of four feet above the 500-year flood line.
Eversource said the substation “was approved following a comprehensive, yearslong public review process” and that the company “comprehensively demonstrated that the project is designed to mitigate flood risks well beyond any flood study for the project.”
The EFSB ruled Eversource “appropriately addressed risks associated with sea level rise” and added that “building the substation at a higher elevation would likely add costs to project development and provide unclear benefits.”
Future Uncertainty
One major challenge of planning for coastal flooding is the high level of uncertainty associated with projecting future emissions, as well as how largescale earth systems will react to different warming scenarios.
While Boston is likely to experience sea level rise of two to five feet, “that’s really all we can say, because it depends on the emissions of greenhouse gases,” said Paul Kirshen, professor of climate adaptation at UMass Boston and a lead author of the UMass climate impacts report.
“If we can get to net zero by 2050, it could only be two feet. If we keep on the rate we’re going, it could be five feet,” Kirshen said.
Projection of a hundred-year flood with three feet of sea level rise | City of Boston
He added there is an “outside chance” that sea level rise could reach up to 10 feet by the end of the decade, depending on the degree of melting on ice sheets in Greenland and Antarctica.
“It’s a low probability,” Kirshen said, “but that would obviously be a real game changer.”
Climate change also could increase the potential for low-probability, high-consequence compound flooding events in which river flooding coincides with a storm surge, Kirshen said.
“We’re at the confluence of three rivers — the Mystic, the Charles and the Neponset River — and there’s always the possibility of those rivers being flooded from precipitation at the time that we get a major coastal storm,” Kirshen said. “Not only would you get flooding from the ocean from the storm surge, but you’d also get the Charles River and the Mystic River overflowing their banks.”
To help account for the changing climate risk profiles, in recent years the DPU has mandated that newly sited projects reassess their climate vulnerability every five years and take any additional necessary mitigation measures.
“It just makes sense if you’re installing energy infrastructure that’s going to have a lifespan of 30, 40, 50 years,” said DPU Chair Van Nostrand. “We’re always getting more information, and if anything, I think the information we’ve gotten is a little bit scarier. … Sea level rise might be even worse than we were thinking.”
Some environmental organizations and legislators are looking to require even more comprehensive climate resilience planning from the utilities. One bill reported favorably out of the legislature’s Telecommunications, Utilities and Energy Committee would require the state’s investor-owned utilities to submit a climate vulnerability assessment and adaptation plan every five years.
Johanna Epke, staff attorney at the Conservation Law Foundation, said current requirements have provided limited visibility into how the utilities are planning for climate impacts.
“They’re not required to file any of their modeling or any of their assessments,” Epke said. “We want that out in the public space, we want to be able to scrutinize that, and we want to have experts in the advocacy community comment on that.”
Van Nostrand said he thinks the DPU already has the statutory authority to require climate vulnerability assessments as part of the ESMP process.
“As a result of the 2022 climate law, we will be making specific findings on climate vulnerability assessments when we issue the August order on this first round of ESMPs,” Van Nostrand said. “Apart from that, we can also rely on our broad regulatory oversight powers to be able to say, ‘We think that it’s part of utility practice that you perform this kind of a study and manage your system in a way that manages risks.’”
WASHINGTON ― Gene Rodrigues, who heads the U.S. Department of Energy’s Office of Electricity, managed to get through a thundering, seven-minute keynote at the Alliance to Save Energy’s Policy Summit on May 8 without even one de-rigueur mention of the Inflation Reduction Act, Infrastructure Investment and Jobs Act or President Joe Biden’s economic agenda.
Rather, he came to the summit to deliver a ringing endorsement of ASE’s new campaign to convince the energy industry, state regulators and Capitol Hill lawmakers that “demand is the new supply.”
In the past, the energy industry “looked at everything from one end of the microscope,” said Rodrigues, who spent a large chunk of his 23 years at Southern California Edison working on demand-side initiatives. “If you need more reliability, if something goes down and you just need more power, if you need to ensure that everyone has access to the benefits of energy, then you … just build more. We need more, bigger plants. We need more transmission corridors. We need, we need, we need. That is the most inefficient way to think about solving the problem.”
Creating a net-zero economy ― with electrified buildings, transportation and industry ― will mean major increases in energy demand, so using a full array of demand management strategies and technologies will be not only critical, but “obvious,” he said. “It is a basic concept of efficiency, of ensuring that the steps we take are economic, impactful and they reach every single American no matter where he or she resides … It is an expression of common sense.”
ASE CEO Paula Glover similarly framed the combination of aggressive efficiency and demand management as “the backbone of any energy transition that we aspire to have that is going to be equitable, reliable, resilient and affordable.”
Demand is the new supply means “transforming energy demand into … dynamic, responsive supply. [It] is necessary and has to start now,” Glover said in her opening remarks at the summit. “This approach is crucial for stabilizing our grids and distributing energy more equitably across communities.”
Conference panels and speakers presented different approaches to growing demand management as supply, from the consumer and regulatory paradigm shifts needed to scale virtual power plants to new research from Lawrence Berkeley National Laboratory (LBNL) showing the impact of efficiency on regional load curves.
Electrification without aggressive efficiency could result in summer peak demand not only increasing, but shifting to later in the evening, said Andrew Satchwell, deputy leader in LBNL’s Energy Markets and Policy Department. Produced in partnership with The Brattle Group, the study also found roughly half the regions studied could see a shift from summer to winter peaking due to the inefficiency of “a lot of electric resistance building heating,” Satchwell said.
But the study also showed that a combination of aggressive demand- and supply-side measures could slash greenhouse gas emissions in the building sector to 91% below 2005 levels by 2050 without any major increase in building electricity use. Further, leveraging building efficiency and flexibility could provide $100 billion in power system savings per year by 2050, which could offset more than a third of the costs of grid decarbonization.
“We see a strong potential for energy efficiency to reduce emissions in the near term, while the grid is still decarbonizing, that then enables later reductions from … electrification under a harmonized grid,” said Aven Satre Meloy, a computational research scientist and engineer at the Berkeley Lab.
Calling the study a “clear-eyed view of the economic case” for demand-side measures, Rodrigues ended his keynote with a call for industry stakeholders to “work on both ends of the scale to balance the grid. Demand is the new supply does not push anything off the table,” he said. “For those who believe in all-of-the-above, it’s just a way to work smart; work smarter, not harder.”
The LBNL-Brattle study found that by combining electrification with aggressive efficiency, the U.S. could reduce CO2 emissions from the building sector 91% below 2005 levels by 2050. | Lawrence Berkeley National Laboratory
Start Right Now
While utility executives frequently say that the least expensive kilowatt-hour is the one you don’t use, demand-side initiatives in general have not had a strong profile in the energy transition.
In its 2023 Utility Scorecard, the American Council for an Energy Efficient Economy found that the nation’s 53 largest utilities had decreased their spending on efficiency by 4.9% in the five years since ACEEE’s last utility rankings. That cut in spending resulted in a 5.4% decrease in energy savings and a 19% drop in peak demand reductions. On average, the ranked utilities spent 2.2% of their revenue on energy efficiency.
According to a January 2024 tally from the International Code Council, 13 states have adopted the latest, 2021 International Energy Conservation Code for residential buildings, while only 11 have adopted IECC 2021 for commercial buildings. Two more, Maine and Massachusetts, have adopted the 2021 updates as “stretch” codes.
IECC codes are updated every three years. Six states still are using the 2009 code.
The LBNL-Brattle study finds an aggressive approach to efficiency and demand flexibility will be vital for the U.S. to have any chance of hitting Biden’s goal of cutting economywide GHG emissions to net zero by 2050 without major increases in demand and grid impacts.
The scale of such efforts could be daunting. The building sector accounts for 35% of U.S. carbon dioxide emissions and 74% of electricity sales, according to LBNL. The study looks at a range of scenarios tracking the effects of cutting emissions and electricity consumption through various combinations of electrification and low, moderate and aggressive energy efficiency and demand management.
LBNL’s most aggressive scenario would require 98 million to 141 million fossil fuel or electric-resistance water heaters to be replaced with heat pump water heaters by 2050, as well as high-efficiency retrofits for building envelopes on 109 million existing homes and up to 43 billion square feet of commercial space. Advanced HVAC controls also would be needed for more than 75% of homes and 50% of commercial buildings.
And, Satre Meloy said, “It needs to start happening right now in order to achieve that very dramatic or very favorable building-centric future in 2050.”
Electrification with no or low efficiency would cut CO2 emissions but almost certainly would result in increased electricity demand, the study finds. The effects of moderate and aggressive efficiency are more variable; emissions would go down, but electricity use could rise or fall, depending on a range of factors.
One example, the study’s aggressive efficiency scenario factors in “breakthrough” technologies ― such as super-efficient building envelopes and energy management systems ― are in the research and development phase but expected to reach commercial scale and price points by 2030 or 2035.
Increasingly rigorous building efficiency codes and standards also will be needed, Satre Meloy said. “Failing to do these things is substantially reducing the total avoided emissions” by 40% to 58%, he said.
The effects on the grid also could be substantial, with “inefficient electrification” leading to increased peak and shifting demand patterns, Satchwell said. In Texas for example, the study found that efficient electrification could drive the state’s summer peak below a business-as-usual level. For a winter-peaking system in the Northwest, efficiency could cut in half any increase due to electrification.
Efficiency and flexibility mitigate electrification load increases in both summer- and winter-peaking systems. | Lawrence Berkeley National Laboratory
Shifting the Paradigm
So, what it will take to get building efficiency and demand flexibility technologies ― like virtual power plants ― to commercial scale and well-integrated into distribution systems? The discussion during a panel on scaling VPPs centered more on paradigm and regulatory shifts than the technologies themselves.
For Jessica Granderson, director of LBNL’s Building Technology and Urban Systems Division, buildings are an “underexploited resource” and the “central hub in the transfer of clean electrons in our energy transition to and from that clean grid.”
“Our buildings have built-in storage already, right in the mass of the building, in the fabric of infrastructure, in the chilled and hot water that we’re using to serve those loads,” Granderson said. “We have the technologies, the communications and the standards now [that] we didn’t previously have to access that built-in storage and exercise it dynamically.”
Mary Sprayregen, global head of regulatory affairs and global market development at Opower, sees a major misalignment between projections of growing residential energy efficiency and demand management and the current reality that about 8% of households are enrolled in utility demand-response programs.
“And that number has not changed over the last several years despite all the attention we are drawing to it,” Sprayregen said. “How do we engage these untapped resources in everyday houses in a way that everybody can participate, but … that is not necessarily controllable, and it’s not necessarily device-based, but it’s behavior-based?”
Opower designs and runs such programs for utilities.
Marisa Uchin, chief strategy and growth officer at Franklin Energy, called for a reimagining of the power system “because we have distributed resources on the supply side hidden on the demand side. We have the opportunity to create the VPPs or to create sources of power that are … on a different size and scale” and can be “distributed any place where potentially demand and supply chains are complex.”
But technology changes at the residential level generally are driven by comfort, upfront cost and a crisis ― the breakdown of a major appliance ― Sprayregen said.
Granderson agreed but called for “changing that paradigm to something that is like where our decisions are system-optimal, and I think, we have to be really cognizant and intentional that that is the change we’re looking to drive. … So, we’re going to think about the ways we combine those solutions to reach everyone in different markets and contexts.”
Another major hurdle for Sprayregen is designing appropriate incentives for utilities to accelerate deployment of efficiency and demand flexibility. Regulatory decision-making is rooted in an inherent conflict between “capital expenditures versus operational expenditures,” she said. “So, how do we get past that?”
Sprayregen, Granderson and Uchin agreed artificial intelligence will be the next critical tool for optimizing the system impacts of energy efficiency and demand management.
“When it comes to policymakers, specifically utility regulators, there has got to be a pathway where software solutions are on par with capital expenditures,” Sprayregen said. “We’ve got to level that playing field.”
