Energy Efficiency and Demand Side Management

Aggregators of distributed energy resources, known as DERs, will need to find “alternative methods” to deploy their products as long as barriers remain to the full implementation of FERC Order 2222, according to a new paper from Guidehouse Insights.

The Federal Energy Regulatory Commission issued the landmark decision in 2020, directing grid operators to enable DER aggregations to participate in wholesale markets. At the time, Order 2222 “was hailed as a game changer for DER,” according to Guidehouse. But in the three years since, “its full impact seems to be more mixed,” the white paper said.

Implementation timelines vary between regions, and experts say there are technology challenges that must be addressed for utilities to have resource visibility and access to market signals of what services are required.

Alternative approaches to integrating aggregated DERs into wholesale markets could include distribution-level programs or local flexibility markets, Guidehouse said. The firm noted a half dozen implementation challenges for FERC Order 2222, varying between regions, including minimum sizes for individual DERs to be able to participate in a DER aggregation that may keep some asset types on the sidelines, and single-node aggregation rules that require all DERs in an aggregation to be located within the same pricing node.

And some states simply do not allow third-party aggregations of demand response to participate in the wholesale electricity market, which can limit DER participation despite Order 2222. FERC in 2008 passed Order 719, which aimed to increase market participation of demand response, or DR, and which allowed states to determine whether retail aggregations of DR could participate in regional markets.

Thirteen states, mostly within the Midcontinent Independent System Operator territory, “restrict or fully prohibit”  participation, Guidehouse said.

“Third-party DR aggregations are essential to unlocking the full potential of aggregated DER,” the white paper said. But it is possible that a third-party, non-utility DER aggregation “created under the new FERC Order 2222 frameworks that includes DR could be prevented from participating in a wholesale market, even if it contains other resources for which states are not allowed to opt out.”

FERC is considering the possibility of removing the opt-out provision but that could come with unintended consequences, said Mike DeSocio, founder and CEO of Luminary Energy, a consulting firm focused on wholesale markets.

“Ultimately, removing any opt-out removes the states' control over DER jurisdiction for regulating the programs that impact their residents and could result in cost shifts to customers who are less well-off and unable to benefit from DER due to their housing/economic situation,” DeSocio said in an email.

DeSocio said there are costs that are incurred by utilities to support customer participation in wholesale markets including reliability analysis, metering configuration and support and coordination of customers' or aggregators' activities.

“The current electric wholesale and retail regulatory structure must operate in the best interest of the customers and FERC and state commissions must continue to demonstrate cooperative federalism for that to happen. Eliminating the 'opt-out' may just undermine that,” DeSocio said.

While challenges to DER integration are being worked out, Guidehouse’s paper said aggregators may be best served by looking to “alternative” ways the resources can participate in the energy system.

“Local flexibility markets” operating at specific points on the distribution grid could help to manage grid operations. Under such a system, an aggregator enrolls asset owners and submits bids to the marketplace to provide certain localized services, Guidehouse said.

“Local flexibility markets can facilitate competition among DER aggregators while maintaining grid reliability and lowering costs for operators and customers,” Guidehouse said. “The concept has been deployed by numerous distribution companies in Canada and Europe and is gaining traction with utilities in the US.”

In New York, National Grid is working with London-based Piclo on an “independent marketplace” that streamlines the ability of DERs to provide flexibility services, also known as non-wires alternatives.

Piclo and National Grid launched the system in 2022 and expanded their partnership in December. National Grid is seeking more than 100 MW of system-wide load relief solutions as well as 9.4 MW of “rapid load relief solutions” at specific local locations, according to the announcement last month.

Despite significant work by governments around the world to improve energy efficiency, China, along with some other regions, has seen a slowdown in energy intensity improvements, contributing to a lack of global progress on the metric, the International Energy Agency said Nov. 29 in an annual report on conservation efforts.

Achieving a net-zero global energy sector by 2050 — which IEA says is “essential” to limiting global warming to 1.5 degrees Celsius above preindustrial levels — requires annual energy efficiency improvements to double, from 2% in 2022 to more than 4% annually between now and 2030, according to the report.

But global energy intensity is on pace to improve by just 1.3% this year, IEA said, “well below what is needed to achieve this target.” Energy intensity is the primary metric IEA uses to track global efficiency improvements; it is the quantity of energy required per unit of output or activity.

The report said the lower improvement rate in 2023 reflects stronger energy demand growth.

“The world’s climate ambitions hinge on our ability to make the global energy system much more efficient,” IEA Executive Director Fatih Birol said in a statement. “Doubling energy efficiency progress this decade is critical.”

The United States is on track to post a 4% improvement in energy intensity this year, and the European Union will likely achieve about a 5% gain, according to the report.

U.S. efficiency experts say despite the 4% improvement in energy intensity, “a massive ramp up of programs and policies” is still needed to keep advancing efficiency. A large part of the United States’ improvement in energy intensity this year is due to temperature fluctuations and high gasoline prices, Steven Nadel, executive director of the American Council for an Energy-Efficient Economy, said in an email.

“Fortunately, recent efforts such as enactment of the Inflation Reduction Act and implementation of many new appliance standards in coming years will help, but much more will be needed,” Nadel said.

Despite elevated energy savings in the U.S. and Europe, IEA found “a strong post-pandemic resurgence in China’s economic growth of around 5% is forecast in 2023, along with a similar rebound in energy demand.” Those estimates suggest “the overall level of energy intensity in China is not expected to change this year.”

It takes more energy to fuel gross domestic product in China than in the U.S. or European Union, IEA said, and “this shift in the balance of economic activity ... helps explain the slowdown in global energy intensity progress in 2023.”

There is a “strong global focus among policy makers” on energy efficiency, IEA said, However, “efficiency policy momentum builds, but global energy intensity progress slows.”

Ultimately, efficiency is needed to address climate change, facilitate the transition to renewable energy, and help address affordability concerns, IEA said. “Faster action on energy efficiency means more avoided energy demand, which is essential to accelerating the substitution of fossil fuels for renewable energy,” according to the report.

Schneider Electric and Enel echoed IEA’s call for greater focus on energy efficiency.

"Balancing investment in renewables with energy efficiency and the reinforcement of the grid is fundamental for the energy transition,” Frédéric Godemel, Schneider Electric France’s executive vice president of power systems and services, said in a statement.

There are two major trends shaping power grids today, according to Director of Enel Grids and Innovability Gianni Armani.

"On the one hand, the energy transition involves increasing electrification of consumption, alongside the growth of renewable energy production, especially distributed generation,” Armani said. "On the other, climate change poses new threats to infrastructure and requires investments and new regulatory frameworks for grid planning and development."

Google has used its carbon-intelligent computing platform, built to shift energy use at its data centers to times when clean energy is more readily available, to respond to energy crises around the world, according to an October blog post by the company.

The tech giant plans to continue piloting the software as a demand response mechanism in partnership with grid operators, said Savannah Goodman, data and software climate solutions lead for Google.

Demand management and other efforts to improve energy efficiency at data centers could have a significant impact on the grid, according to Baosen Zhang, an associate professor of electrical and computer engineering at the University of Washington.

Google's efforts to achieve 24/7 clean energy could have benefits beyond its goal of eliminating carbon emissions from its operations, according to the company's latest dispatch.

Google reports that it used its carbon-intelligent computing platform to respond to extreme weather events in Oregon, Nebraska and in the Southeastern U.S. in collaboration with utility partners in those areas. The company also used the software to reduce electrical demand and support energy security in Europe by reducing its power consumption from 5 p.m. to 9 p.m. during Europe's December 2022 to March 2023 energy crisis.

Developed in 2020, Google's carbon-intelligent computing platform allows the company to direct its data centers to perform non-urgent computing tasks when renewable energy resources are more widely available to reduce its carbon footprint. But as demonstrated over the past year, the platform can also be used to respond to local grid events to maintain reliability, the company said.

“The demand response capability leverages the technical foundations of this platform to deliver targeted energy reductions at specific data centers based on an event request from a local grid partner — typically during the system wide peak load,” Goodman said. “In other words, demand response is a new capability that leverages existing technical infrastructure to serve a new set of use cases and objectives.”

Google continues to work with grid operators to test and expand its demand response capabilities, Goodman said.

Google isn't the only large tech company testing demand response initiatives, Zhang said. With more utilities implementing rate structures that penalize power use during peak hours and reward customers for having more flexible power needs, data centers have begun to optimize their operations in response.

And while it can be difficult to calculate exactly what this will mean in terms of carbon emissions — a question that multiple companies are tackling — Zhang said he sees significant potential in demand management programs and other initiatives to reduce electrical use at data centers.

Data centers may represent a mere fraction of the nation's total energy use, he said, but energy use by data centers is growing rapidly while demand from the rest of the economy remains relatively flat. And data centers typically have more flexibility in terms of when they need energy compared to other large, industrial customers, Zhang said.

Utah is the most energy-efficient state and South Carolina is the least, according to data published Oct. 17 by personal finance site WalletHub.

The survey looks at both home and vehicle energy efficiency and compares states based on an aggregated score. Rounding out the top five most-efficient states are Massachusetts, Vermont, New York and Rhode Island. 

In last year’s WalletHub survey Massachusetts was the most energy efficient. South Carolina’s position is unchanged.

“The average U.S. family spends at least $2,000 per year on utilities,” according to WalletHub, citing data from the federal government. “Heating and cooling of spaces alone accounting for more than half the bill,” the site said. Add to that, the average consumer spent another $3,120 on motor fuel and oil, the report found.

After South Carolina, the least energy-efficient states are West Virginia, Alabama, Mississippi and Arkansas.

The home efficiency scores were developed by comparing energy consumption with heating degree days; for vehicle efficiency, WalletHub divided the annual vehicle miles driven by gallons of gasoline consumed to determine vehicle-fuel efficiency. Alaska and Hawaii were not included in the survey.

Energy efficiency is increasingly viewed as a tool to reduce energy use, monthly bills and greenhouse gas emissions. 

“The future is full electrification of homes, which will allow grids to work with demand-response strategies to balance needs across consumers,” said Georg Reichard, head of the Department of Building Construction and an associate director in the Myers-Lawson School of Construction at Virginia Tech. 

Reichard provided commentary to accompany WalletHub’s survey and said the government should be supporting consumers and businesses in making homes and buildings more efficient.

“Those investments are still rather steep but have merits for a broader community. So, such incentives have a broader impact that goes beyond the individual homeowner and thus are good examples of incentive policies to help a market transformation,” Reichard said.

But a new report from national business group E2 and nonprofit E4TheFuture indicates efforts to improve energy efficiency may face a workforce shortage. The groups released their annual “Energy Efficiency Jobs in America” report on Oc. 13, showing 2.2 million workers in the energy efficiency sector last year — but while the workforce grew 2% in 2022, employment still has not recovered to pre-pandemic levels when there were 2.4 million efficiency workers.

“More than 84% of energy efficiency businesses are reporting difficulty in finding employees,” said Phil Jordan, vice president at BW Research Partnership. The group oversaw research efforts and compiled the employment report’s data. “Federal, state and local policies can help strengthen workforce development and apprenticeship programs for the energy efficiency sector.”

Energy efficiency jobs include a wide range of positions including in manufacturing and sales, installation and repair, architecture and accounting. States experiencing the highest percentage growth in energy efficiency jobs were: Nevada, New Mexico, Oklahoma and New Jersey, according to the employment report.

“By passing policies that speed up building decarbonization and electrification, we can create even more of these savings and jobs, while simultaneously reducing emissions and the impacts of climate change,” E2 Executive Director Bob Keefe said.

Beginning in 2024, Duke Energy will offer a “tariffed on-bill” energy efficiency program to customers in North Carolina that supporters say will be one of the first-of-its-kind for an investor-owned utility.

The program will provide customers with access to upgraded heating and cooling appliances, home retrofits like insulation and air sealing, heat pump water heaters, and HVAC duct repair or replacement. The improvements will be paid for through a charge on the customer’s bill.

“Tariffed on-bill programs have dramatically increased access to energy efficiency upgrades and demand-side management resources across the country in electric cooperative territories, but investor-owned utilities have been slow to adopt them,” Shelley Hudson Robbins, project director at the nonprofit Clean Energy Group, said in a statement.

The North Carolina Utilities Commission issued an order in August approving the program for Duke Energy Progress and Duke Energy Carolinas, and the utility on Oct. 1 began implementing new rates to cover implementation.

The North Carolina Sustainable Energy Association, Clean Energy Group, Southern Environmental Law Center and Southern Alliance for Clean Energy say the “innovative” program will help customers, including low-to-moderate income residents, access efficiency upgrades and utility savings while also helping Duke to meet carbon reduction goals.

“This is a monumental decision by the North Carolina Utilities Commission – as it stands to potentially help thousands of families across North Carolina,” said Daniel Pate, energy program manager at the N.C. Sustainable Energy Association. “Today, we’re excited to finally see a program designed to address the barrier of the upfront costs of residential energy efficiency.”

The process of making home upgrades begins with the utility reaching out to customers who likely have the greatest opportunity to benefit from energy efficiency, Casey Fields, Duke’s strategy and collaborations manager, said in an email. However, almost any customer with 12 months of usage data may participate.

Customers are asked to complete an enrollment form and schedule a home audit, Fields said. Duke will then model the customer’s projected energy savings, calculate available efficiency incentives and conduct a cost benefit analysis to make sure estimated benefits outweigh costs.

“If a customer accepts the proposal, then Duke Energy will schedule a vetted local trade ally to complete the installations,” Fields said. “A quality assurance check of the improvements will be conducted, and for certain improvements (like HVAC) semi-annual maintenance plans will be set up.”

It takes about a month for customers to see monthly charges about 30 days after efficiency upgrades are complete. If the customer moves out of their home, then the new customer will be notified by Duke Energy of the monthly charge, Fields said.

The program provides three major sets of benefits, said Fields: upfront cost reductions for efficiency upgrades, improvements to home comfort, and savings on customer bills.

“A major barrier to customers are the upfront costs needed to get this kind of work complete,” Fields said. “Being able to charge a portion of that cost monthly on their electric bill may remove the barrier of having to gather all the cash together upfront.”

Rebates available through the Inflation Reduction Act may help Duke to offer the program to more customers, Fields said.

The PJM Interconnection’s rules effectively block large-scale residential demand response aggregation, potentially increasing energy and capacity prices, CPower Energy Management said in a complaint filed with the Federal Energy Regulatory Commission.

The PJM’s tariff is unjust and unreasonable because it prevents curtailment service providers, or CSPs, from competing with other market participants to provide demand response residential service and because it potentially allows utilities to exercise market power, CPower said in the complaint filed Sept. 28.

There is “huge latent potential” for large-scale residential demand response in PJM, Ken Schisler, CPower senior vice president of regulatory and government affairs, said. “Every residential home in PJM probably has a smart device or smart appliance with the capability to participate in demand response programs. They just don't have a way to get that to market.”

While increased residential demand response in PJM could increase grid reliability and lower energy and capacity prices, CSPs are unable to tap those resources because of a Catch-22 in PJM’s rules, according to CPower.

Utilities don’t give CSPs needed information from their advanced metering infrastructure systems that is required for aggregations of thousands of residential DR customers to take part in PJM’s markets, CPower said. At the same time, PJM’s rules bar CSPs from using approved statistical sampling rules for DR residential participation in the grid operator’s energy and capacity markets if they have smart meters, according to the company.

AMI utility meters have been mainly designed for utility retail billing needs and for distribution system management purposes, and often lack the capability to meet PJM’s “extensive” wholesale demand response measurement, verification settlement, and compliance requirements, the LS Power subsidiary said.

In cases where the AMI meters could provide the needed customer information to CSPs, utilities have “consistently demonstrated limited cooperation or limited ability to cooperate” or have refused to provide CSPs with the data at a scale that would enable CSP participation in PJM’s markets, CPower said.

Further, existing AMI may be ill-suited to providing the needed information as the Internet of Things is expanding demand response opportunities, CPower said.

FERC should order PJM to let CSPs and utilities use statistical sampling of interval metering equipment to meet the grid operator’s measurement and verification requirements, which is already allowed for non-AMI meters, CPower said. The requirements are used to determine how much demand response is expected to be available and how much is delivered.

CPower said it failed to advance its concerns through PJM’s stakeholder process.

PJM is reviewing the complaint, according to Jeffrey Shields, a spokesman for the grid operator.

PJM operates the grid and wholesale power markets in 13 Mid-Atlantic and Midwest states, and the District of Columbia.

As an increasing supply of renewable energy resources requires greater reliability and resiliency for the power grid, virtual power plants are emerging as one way to ensure the supply of electricity always meets the demand.

“In the future, grids are going to need to be much more flexible,” said Severin Borenstein, faculty director of the Energy Institute at the Haas School of Business at the University of California, Berkeley, and a board member for the California Independent System Operator. “They’re going to use a lot of intermittent renewable energy, and they’re looking for ways to allow the system to easily and smoothly adapt to those fluctuations.”

VPPs are one way to address intermittency, an issue with wind and solar energy, by storing excess energy that’s sent back to the grid when solar panels and wind turbines aren’t generating electricity.  

“If prices start to spike [or energy supplies are constrained] we can look and say ‘hey, we have a resource within this region’ and we can press a button and call on that resource,” said Reg Rudolph, chief energy innovations officer for the Tri-State Generation Association.

However, even as VPPs proliferate, pinning down the meaning behind the term “virtual power plant” is difficult. Not everyone agrees precisely on a definition of “virtual power plant,” experts and industry insiders say.

“There is a lot of ambiguity in the market as to how they are defined by different vendors,” said Alex Pratt, vice president of business development for the California-based software company AutoGrid.

Pratt provided one such definition.

“A virtual power plant is an aggregation of distributed energy resources that is utilizing software to manage and orchestrate the resources to provide, as much as possible, the same grid services that a centralized power plant would,” he said.

A VPP can be as simple as a group of households with smart thermostats that a utility can adjust when demand strains the power grid. But VPPs generally involve several storage batteries connected to solar arrays or wind turbines that can work together to send energy back to the power grid.

“The idea of a virtual power plant is that in the heat of the summer, when you’re running your generation at full bore, you can hit a button and send a signal to larger loads and create 200, 300, 500 MW of virtual capacity,” said Rudy Garza, president and CEO of CPS Energy in San Antonio, Texas.

The concept has been discussed for decades, but utilities are looking more to VPPs as the use of battery storage increases.

“Once [a household or business] has a battery in place, the grid operator is saying ‘wait a second, we could benefit if we could use that battery on the worst day of the year,’” Borenstein said. “We could know that we could dispatch that battery right when we need it.’”

Several utilities are finding ways to encourage VPPs. The Sacramento Municipal Utility District, for example, provides a subsidy for anyone with battery storage who wants to join a virtual power plant, Borenstein said.

Virtual power plants are similar to microgrids because both can generate their own power. But microgrids are designed to run separately from the power grid, while virtual power plants are part of the grid.

Microgrids are intended to keep critical facilities such as hospitals online during blackouts.

The precise number of VPPs remains a matter of debate, but advancing technology and evolving regulations means the nation will almost certainly see more of them in the coming years, experts say.

How many are there?

The number of virtual power plants in the United States depends on how the term is defined, and with no precise meaning, regulators have yet to conduct their own count.

“Many companies include or remove criteria to enable them to be part of the picture,” said Ben Hertz-Shargel, global head of grid edge for energy research and consulting firm Wood MacKenzie.

But at least one independent assessment exists.

Wood MacKenzie calls a virtual power plant an aggregation of resources. Some or all are behind-the-meter and function together to provide some type of grid service.

“They need to be dispatchable,” Hertz-Shargel said. “They don't need to be able to hit a certain price point, they can be weather-dependent and can incorporate multiple technologies.” 

By that definition, the United States has more than 500 virtual power plants, with an outsized number, about 150, in California.

“There’s a lot of stuff that’s unique to California that would necessitate this,” said Ahmed Mousa, the utility of the future manager for Public Service Electric & Gas Co. in New Jersey.

For example, the unusually high price of energy in California requires novel ways to generate and deliver inexpensive power, and frequent wildfires mean that utilities need power sources to draw from when fires cause blackouts, he said.

What does it take to make more of them?

By all accounts, VPPs will proliferate as efforts to add renewable energy to the grid take on a greater sense of urgency.

But the logistics of virtual power plants are the most daunting barrier. VPPs require power generation and storage in multiple locations and software programs capable of connecting them to the power grid.

“There's a project development phase, akin to putting steel in the ground, that’s the biggest barrier,” Pratt said. “You need assets, and you need things that can be controlled.”

What are the benefits?

When asked about the benefits of a virtual power plant, experts and industry insiders have a common refrain: A lower carbon footprint.

A power grid relying on renewable energy needs a reliable source of power when the weather doesn’t cooperate, and virtual power plants are one way to achieve that reliability.

Virtual power plants or microgrids have numerous objectives, said Santiago Grijalva, the Georgia Power Distinguished Professor for the School of Electrical and Computer Engineering at the Georgia Institute of Technology. 

“One is resilience. If power goes out, or there’s a disruption in the grid,” a VPP can provide power to a small number of customers.

By storing energy during excess generation, VPPs reduce the risk of power outages. Having more points of generation makes VPPs more reliable, Mousa said.

“You have to have some contingency,” he said. “You can’t rely on three customers, because what if they are not available?”

Another objective, Grijalva said, is sustainability. Packaging solar panels with storage batteries — as many VPPs do — makes solar more valuable, encouraging more utilities to use them and providing more power with fewer emissions of planet-warming gases.

The benefits to customers depend on where they live. Net metering rules that pay rooftop solar users for excess power change from state to state, but households who install solar panels almost always stand to benefit when those panels produce more power than they need.

“Our customers sign contracts through our demand response program,” Garza said. “We pay them what the market price is for power like we would when we go out and buy power in the market.”

How FERC order 2222 will help

Regulations are changing at the state and federal levels to clear the way for more virtual power plants

For example, in 2020, the Federal Energy Regulatory Commission ordered regional transmission organizations and independent system operators to let distributed energy resources participate directly in wholesale markets by 2026.

“And they allowed aggregation,” Mousa said. “All of us can work together to make up the virtual power plant.”

Once fully implemented, the order will be a boon for virtual power plants, which fall under the definition of distributed energy resources, experts say.

“It’s going to be a gamechanger,” Mousa said.     

Visuals Editor Shaun Lucas contributed to this story. 

Electric utility efforts to help customers reduce energy consumption and monthly bills have “stagnated,” the American Council for an Energy-Efficient Economy said in a report published Aug. 24. The group identified a nearly 5% decline in efficiency program spending from 2018 to 2021.

Energy savings dropped 5.4% across the same period. Most utilities, regulators and state policymakers “should do a lot more to help reduce energy waste,” said Mike Specian, utilities manager at ACEEE and lead author of the Utility Energy Efficiency Scorecard.

Eversource Massachusetts topped ACEEE’s scorecard for the third consecutive time, ACEEE said. Ohio Edison, a FirstEnergy utility, was last among the 53 utilities that were ranked on the basis of their policy and program efforts.

Electric utility spending on energy efficiency is down 4.9% since 2018, which has contributing to a 19% drop in peak demand reduction, according to ACEEE’s assessment. 

Spending “is a critical indicator of a utility’s commitment to energy efficiency,” ACEEE said. As a percentage of a utility’s revenues, spending on efficiency programs dropped from 2.58% in 2018 to 2.23% in 2021.

“As you might expect, this has negatively impacted savings,” Specian said in a webinar discussing the findings. “In 2018, utilities are saving an average of 1.03% of their annual sales through efficiency. Three years later, overall savings in absolute terms have dropped ... to an average of 0.91%.”

Likewise, energy efficiency went from shaving about 0.8% off peak demand, to 0.7%, he added. “I would characterize all these trends as moving in the wrong direction,” Specian said.

Utilities do not have total control over their efficiency spending, ACEEE officials noted. Ohio utilities essentially had efficiency programs canceled by state lawmakers in 2019.

Edison Ohio, which ranks last in ACEEE’s scorecard, scored just 2.5 points out a possible 100. The utility did not respond to a request for comment. AEP Ohio and Duke Energy Ohio scored in the bottom five of the scorecard.

“Even if we were to remove from consideration the three Ohio utilities that had their efficiency programs canceled, efficiency spending is still down over 2% nationally on average, and efficiency savings are about the same as they were three years ago,” Specian said.

Florida Power & Light was ranked next to last in ACEEE’s scorecard, at 52. A spokesperson for FPL parent company NextEra Energy said the utility has “long believed in empowering our customers to make energy-efficient choices that are right for them,” and “we communicate about energy efficiency year-round.”

FPL offers energy savings tips and programs, “including one of the largest demand side management programs in the country,” he said.

ACEEE’s scorecard did reveal “some positive developments on low income programs,” Specian noted. Utilities have increased low income spending 17% since the last scorecard, going from 10.7% of their efficiency program budgets on average, to 12.8%.

“So this is certainly a trend in the right direction, but those spending and savings levels, we would argue, are still too low,’ he said. “We know that low income programs typically require more spending per customer to achieve the same benefit.”

Global energy demand rose 1% in 2022 but the rate of energy efficiency improvements was double the average of the past five years boosted by “surging” sales in more efficient technologies like heat pumps and electric vehicles, the International Energy Agency said in a report June 7.

In the United States last year, residential heat pump sales exceeded gas furnaces for the first time, making up 53% of heating system sales.

Sales of electric vehicles grew 55% last year in the United States, and in the first quarter of this year made up more than 7% of new car sales. Globally, EVs made up 14% of new car sales in 2022 and could reach 18% this year, IEA said.

Global investment in energy efficiency is expected to reach record levels of $624 billion in 2023, IEA said, “though growth is slowing due to increased cost of capital.”

Global energy efficiency investment in 2022 was about $600 billion, according to the report. 

“Sales of key efficiency technologies are surging,” the report said. Heat pump sales grew more than 10% globally last year and in Europe increased by almost 40%. There were 2.3 million EVs sold worldwide in the first quarter of this year, a 25% boost over the same period last year.

“We are seeing strong momentum behind energy efficiency,” IEA Executive Director Fatih Birol said in a statement. “We now need to push into a higher gear and double energy efficiency progress by the end of this decade.”

Heat pumps are a “key technology” for decarbonization efforts, according to the report and new market data show that heat pump sales for residential space heating continue to rise significantly with a global increase of more than 10% in 2022.

Improvements in primary energy intensity increased to 2.2% in 2022, double the average over the previous five years and four times the rate in the last two years, IEA said. The sale of smart energy controls and building energy management systems increased last year but “remain far from the 2030 IEA Net Zero targets.”

Doubling the rate of energy intensity improvements globally, from 2% to above 4% would reduce global energy-related carbon dioxide emissions by almost 11 gigatons by 2030, the report concluded.

“We have all the ingredients. What we don’t have is time,” Schneider Electric Chairman Jean-Pascal Tricoire said. “Optimizing how we consume energy is the priority of how we tackle the climate-and-energy crisis.” 

Last year Schneider Electric purchased AutoGrid, a company focused on the optimization and integration of distributed energy resources.

The California Energy Commission last week approved a state load shift goal of 7,000 MW by 2030, which is double current levels of demand flexibility and could power up to 7 million homes by the end of the decade without new power plants, according to the agency.

The goal, which comes from a requirement in state Senate Bill 846, passed last year, includes a series of measures including demand response programs and time-of-use rates that incentivize the use of electricity when it makes the most sense for customers and the grid.

The goal is “essentially the counterpart to the renewable portfolio standard,” said Cisco DeVries, CEO of OhmConnect. The RPS was “a giant starting gun for utility-scale renewable power… we’ll look back on this as a starting gun for dramatic expansion of flexible demand across the state,” he added.

The CEC set the load shift goal, which was developed in consultation with the California Public Utilities Commission and California Independent System Operator, as the state projects the need for around 38,000 MW of new clean energy resources by the end of the decade. 

The CEC outlined three categories of load flexibility resources in a report outlining its goal:

• “Load-modifying” demand flexibility resources, like time-of-use rates, that directly impact load forecast;

• Resource planning and procurement load flexibility, like supply-side demand response, that helps with resource adequacy requirements, or reduces the requirements as a credit;

• Incremental and emergency load-flexibility programs, like the state’s emergency load reduction program, that are targeted at extreme events. 

The agency also put together policy recommendations for each of these three categories. For instance, the CPUC should instruct utilities to roll out dynamic pricing options for as many customers as they can, and the CEC could look into the possibility of a centralized, competitive demand response marketplace for the state, according to the report. Additionally, the CEC could also look at piloting programs specifically meant for behind-the-meter storage.

Load flexibility plays a critical role in the state’s broader clean energy transition, especially in terms of changing the amount of resource build-out the state needs and how efficiently it is built, CEC Vice Chair Siva Gunda said at the agency meeting. This is especially the case given that California is facing the prospect of electrifying its transportation and building sector and potentially its industrial and agriculture sectors.

“By embracing the load shift goal and demand response, we can maximize the potential of existing resources, definitely reduce the amount of greenhouse gas emissions, and also achieve a more resilient, affordable and reliable system,” he added. 

OhmConnect’s DeVries is optimistic about what the goal means for demand flexibility in California, noting that it is similar to the adoption of the renewable portfolio standard that was the catalyzing event for the growth of utility-scale solar in California and many other states.

The next step on the load flexibility front, he said, would be moving from a goal to a legal mandate, adopted by either the appropriate state agencies or by the legislature. The CEC’s goal is the first, and critical, step in getting to such a mandate, he said, “and I suspect we’ll see something like that over the next year or so.”