Energy Efficiency and Demand-Side Management

CenterPoint Energy will deploy 15 large mobile generators to the San Antonio area to help reduce the risk of energy shortfalls this summer, the Texas utility said June 16.

Installation of the first five units has begun and the remaining 10 will be installed in the coming weeks.

The move “will immediately lower monthly bills for our Houston-area customers,” Jason Ryan, CenterPoint’s executive vice president of regulatory services and government affairs, said in a statement. The deployment is expected to reduce bills for Houston-area customers by approximately $2/month by 2027, the utility said.

The generators range from 27 MW to 32 MW and were acquired following Winter Storm Uri, which devastated the Texas grid in 2021. CenterPoint subsequently came under fire when the mobile units were not deployed after Hurricane Beryl last summer. 

The utility opted to forego some profits associated with the mobile generation lease, amid the controversy.

“CenterPoint will receive no revenue or profit from the 15 large units based on the agreement” with the Electric Reliability Council of Texas, the utility said.

According to the June agreement, ERCOT determined that the proposed retirement of CPS Energy’s V.H. Braunig Units 1, 2, and 3 “poses a significant risk” to its system because those units “help to mitigate risk of cascading outages associated with the post-contingency overload of certain transmission lines importing power into the greater San Antonio area.”

ERCOT recommended Unit 3 continue operating under a reliability must-run agreement, but said CenterPoint’s mobile fleet “could help further mitigate the identified reliability risks more cost-effectively than committing V.H. Braunig Units 1 and 2 through RMR agreements.”

According to CenterPoint, it’s generators will deliver approximately $200 million of value to the state’s grid. The agreement with ERCOT indicates the generators could run until March 2027.

In the aftermath of Hurricane Beryl, CenterPoint proposed a $5 billion investment into Houston-area grid resilience. In May, the utility said it had completed all of the critical portions of its Greater Houston Resiliency Initiative, including installing 26,000 storm-resilient poles, moving 400 miles of power lines underground and adding more than 5,100 automation devices to the electric system.

Power generators and large customers should embrace flexibility as rising power demand increases the risk of load-shedding events — interruptions in the delivery of electricity — during the spring and fall, Aurora Energy Research said in a June 6 report.

The Electric Reliability Council of Texas could see shoulder-season load-shedding events by 2030, according to a model based on past thermal generator outage conditions, the report says. It will have a ramping requirement of at least 10 GW for 16% of hours by 2035, underscoring the need for a fleet of flexible resources to respond to sudden demand swings, it says. 

Batteries and gas peaking plants provide crucial flexibility on the generation side, while flexibility from data centers and other large loads could prevent load-shedding and avoid 10 GW of new generation capacity by 2030, Aurora said.

Aurora’s modeling in ERCOT, the PJM Interconnection and other ISOs shows that the historically uneventful shoulder seasons increasingly present reliability concerns for grid operators due to aging infrastructure and ever-more-volatile weather conditions.

A May 25 load-shed event that affected nearly 100,000 customers in New Orleans highlights the risk, Aurora said. 

Two Louisiana nuclear power plants with more than 2 GW of combined capacity were offline during the event, one unexpectedly due to a cooling system issue. At the same time, a critical 500-kV transmission line serving New Orleans was out of service because it had been damaged in an early March tornado. Other lines in the area overloaded as demand spiked amid unseasonably hot weather. 

About 70% of the 6.3 GW of outages contributing to the event were unplanned; flexible resources like batteries could have addressed some of the shortfall, representatives for the Midcontinent Independent System Operator told the New Orleans City Council on June 3.

Existing capacity accreditation approaches may not adequately capture the risk of shoulder-season reliability events, Aurora said. For example, no more than 10% of accredited thermal generation capacity was unavailable in PJM during Winter Storm Elliott, the 2022 event that Aurora said was typical of peak-season grid emergencies. In contrast, 37% of accredited coal capacity and 27% of accredited nuclear capacity were offline in ERCOT during a May 2024 reliability event, Aurora said.

Grid-scale batteries discharged 2.2 GW and flexible resources discharged a total of 9.1 GW during the May 2024 ERCOT event, helping mitigate the impacts, Aurora said. 

Those contributions came amid a record pace of battery deployments in ERCOT. A December analysis by the American Clean Power Association found that the roughly 5 GW of batteries the region added between the summers of 2023 and 2024 dramatically improved system reliability while avoiding at least $750 million in consumer electricity costs.

Flexible resources will be increasingly important as ramping requirements and overall loads increase through the end of the decade, Aurora said. Its models suggest data centers will be the single biggest contributor to an expected 63% rise in average hourly spring load in ERCOT by 2030.

While data center capacity in ERCOT is expected to increase from 4 GW this year to 35 GW in 2030, up to 50% of that capacity can provide some degree of reliability support in emergencies, Aurora said. Aurora projected that 20% of all expected data center capacity would be directly responsive to price, meaning data center operators can voluntarily run backup generators or shift demand during demand-induced price spikes, while 30% could turn down when called upon by the system operator.

The Texas Legislature passed a landmark bill this year to give ERCOT more control over data centers’ energy transactions, including authority to shut off power to them during grid emergencies. The bill, S.B. 6, “may become the model for the rest of the country," Republican state Sen. Phil King told the Texas Tribune last month.

Despite the growing need for grid flexibility, data center contributions to flexibility will remain modest, Aurora’s report noted. Even by 2030, data centers would need to flex less than 0.5% of total capacity during about 5% of hours in the year, with average event durations lasting five to 10 hours, Aurora said.

NRG Energy and LS Power on June 12 asked the Federal Energy Regulatory Commission to approve a $12 billion deal under which NRG would buy about 13 GW in gas-fired generation and CPower, a company with 6 GW in demand-response resources, from LS Power.

If completed, the transaction will increase NRG’s market share in the New York Independent System Operator and PJM Interconnection footprints, and in certain submarkets in NYISO and PJM, but not enough to give NRG the ability to exert market power, the companies said in an application at FERC.

Under the deal, NRG’s capacity in PJM would jump to 9.5 GW from 2.1 GW and NRG would own 2.2 GW in New York, up from 1.2 GW, according to the application.

Related to the deal, LS Power would buy energy, capacity and ancillary services via a power purchase agreement from a 985-MW unit at the Ravenswood Generating Station in Queens, New York, according to the application. The PPA would start at the deal’s closing and continue through April 30, 2029.

Under the deal, NRG would also buy 765 MW in ISO New England and 2 GW in the Electricity Reliability Council of Texas market.

NRG and LS Power asked FERC to approve the transaction by Oct. 24. They expect to close the deal early next year. The New York State Public Service Commission must sign off on the transaction.

Under the deal, which NRG and LS Power announced on May 12, LS Power will acquire about 11% of NRG’s outstanding common stock. However, to prevent LS Power and its affiliates from controlling more than 10% of NRG’s voting shares — a threshold that triggers heightened oversight by FERC — NRG will deliver any share that exceeds the 10% threshold to an independent trustee, according to the application.

The transaction will roughly double NRG’s fleet to 25 GW.

Facilities operations became part of a semiconductor manufacturer’s financial turnaround when it stabilized its energy costs by putting in a microgrid, says Charlie Lord, managing principal at Renew Energy Partners, an energy-as-a-service company.   

The publicly traded manufacturer had been struggling with financial challenges caused in part by the unreliability of the utility grid it was counting on for its energy, Lord told Facilities Dive. 

“They were dealing with a bunch of micro-outages because the grid was – and still is – unreliable in that corner of the grid, and for every outage they lost half a day and $1 million in revenue,” said Lord, whose company provides energy solutions to manufacturers and other industrial and commercial property owners. 

Once the manufacturer put in a cogeneration and battery array microgrid, which Lord’s company financed, it was able to replace the unpredictable availability and price of energy for a large portion of its daily needs with a predictable and lower-cost alternative source, Lord said. 

By itself, the stabilized cost was modest. But when coupled with other business and operational changes the company was making, it was enough for the company to improve its credit rating to investment grade after years of being below that threshold. 

“It actually was a little piece of their turnaround,” Lord said. “We reduced their costs. We dramatically improved the pro forma of the facility that was dealing with a bunch of outages.”

Renew works with commercial property owners to make energy design changes that aim to increase the efficiency of their HVAC and other systems. As an EaaS company, it finances and owns the upgrades. 

“Our customers will tell us what their priorities are for these projects,” said Lord. “An interesting shift we’ve seen in the last five years is they’ll often now say, ‘I will do any project that keeps my operating budget the same’ rather than try to lower their costs.” 

The reason for the shift is the value they get in other areas of their operations in addition to lower energy costs that spin off from the upgrades. 

“They’re interested in upgrading equipment that they know needs to be upgraded,” he said. “So, that’s a capital avoidance. They’re interested in carbon and emissions reductions because they’re getting pressure from customers or buyers or limited partners. They’re interested in the resilience and the reliable energy costs they get by avoiding price spikes.” 

When Lord’s company works with property owners, it will bring in a design-build partner. Together, the companies will determine the mix of upgrades that will meet the goals of the owner. Renew serves as the hub, providing the financing, managing the contractors and owning the result.  

“We are the central shop,” he said. “We think that’s an important attribute of a good partner – someone who can provide the capital and help manage the complexity by saying, ‘Let’s look at all of it and help you figure out what to do and we’ll be your point of contact for all of it.’”

For middle-market companies and larger, typically with multiple properties, Lord’s company will execute a master energy services agreement at the corporate level and, for the mix of work that needs to be done at each facility, add a project addendum. That’s a structure that keeps legal costs and paperwork to a minimum, he says. 

“Each one of these project addendums will be linked to a design-build contract and we will fund that contract to get the work done,” he said. “We’ll also fund the ongoing operations and maintenance and we’ll optimize the performance of the system.”

Monetizing waste heat

One of Renew’s specialty areas is thermal energy. It will execute a thermal energy purchase agreement, which Lord called an analogue to widely used power purchase agreements. The difference is the thermal agreement focuses on heat. 

“In the same way that, say, a solar array would deliver a meter and charge for a kilowatt-hour, we’re capturing waste heat that’s otherwise going up, say, a smokestack and, through our system, redelivering it to meet the company’s thermal need,” he said. “That’s a therm that isn't being produced by natural gas or whatever the fuel source is.”

Thermal energy purchase agreements can make sense for any type of commercial property that generates excess heat but they tend to be used mostly by manufacturing companies that throw off a lot of waste heat as part of their business processes, or by hospitals. Senior facilities that have staff working 24 hours a day also tend to generate a lot of waste heat. 

These thermal projects lower costs, even after including an annual inflation adjustment, and replace unpredictable grid costs with predictable costs, according to Lord.

“When we sign a contract, we’ll set a price per therm,” he said. “There may be a 2-3% escalator for inflation. Typically, that’s driven by our expectation that the cost of maintaining this will go up every year, which it has. But if you know that you’re going to buy half your therms for the next 15 years from a contract that’s going up at exactly 2% or 3% a year, guess what? The other half is still subject to market conditions from the utility, and that may go up 15% in one year.” 

That scenario has happened in a number of states over the last two years, Lord said. “So, you’re taking half of your load and saying, ‘I know exactly where it’s going to be.’ You can say that to the CFO. ‘I know exactly what this energy’s going to cost us, every year for the next 15 years. So, we’ve only got half now that’s exposed to that volatility.’ And CFOs love predictability.”  

Demand response is a growing resource in New York, and that system flexibility will be even more important to meet rising demand going forward, the state’s Independent System Operator said in a June 2 report.

“The grid is undergoing rapid and instrumental change,” New York ISO President and CEO Rich Dewey said in a statement. “We continue to observe declining reliability margins while forecasting a dramatic increase in load. It’s imperative during this period of transition that we maintain adequate supply to meet growing consumer demand for electricity.”

In its most recent Reliability Needs Assessment published last year, the ISO said total generation resource capability in New York for the summer of 2024 was projected to be 40,461 MW, including 37,595 MW of generating capability, 1,281 MW of demand response and 1,585 MW of net long-term purchases and sales with neighboring control areas. 

This summer, the ISO said it expects 1,487 MW of demand response to be available, about a 16% increase over last year. In-state generation will be about 37,699 MW and import capabilities have grown to 1,769 MW. 

Longer-term reliability needs “may be resolved by new capacity resources coming into service, construction of additional transmission facilities, increased energy efficiency integration of distributed energy resources and/or growth in demand response participation,” NYISO said in its Power Trends 2025 report.

Electric vehicles, HVAC systems and other grid-connected distributed energy resources could provide New York with 8.5 GW of cost-effective grid flexibility by 2040, Brattle Group said in a January report prepared for the New York Department of Public Service and the New York State Energy Research and Development Authority.

Grid flexibility could address approximately 25% of New York’s expected peak load “that is not served by renewable generation,” approaching the scale of other, utility-scale flexible resources, Brattle said.

Among other key findings from NYISO’s Power Trends report, the grid operator said generator deactivations “are outpacing new supply additions,” while electrification programs and new large-load customers associated with economic development initiatives “are pushing projected demand higher.”

“Together, these forces are also narrowing reliability margins across New York and increasing the risk of future reliability needs,” the ISO said.

The grid operator expects New York to transition to a winter-peaking electric system by the 2040s, driven primarily by electrification of space heating and transportation. “On the coldest days, the availability of natural gas for power generation can be limited, and interruptions to natural gas supply will introduce further challenges for reliable electric grid operations,” NYISO said.

Electric utilities can make calls and send demand response text messages to customers who have provided their phone number, the Federal Communications Commission said in a June 9 declaratory ruling.

“When a consumer gives a utility their phone number they give their prior express consent to receive non-telemarketing demand response calls and texts,” the commission wrote.

“We confirm that demand response communications are closely related to utility service and thus within the scope of consent customers give when they provide their phone number to their utility,” FCC said. “We thus make clear that a utility can make critical, time-sensitive demand response communications to its customers rather than having to solicit additional consent from each customer, a burdensome and often costly undertaking.”

The Edison Electric Institute, which represents investor-owned utilities, requested in March that the FCC clarify that utilities have prior express consent under the Telephone Consumer Protection Act, and utilities can make demand response communications without risking penalties or fines.

EEI “appreciates the FCC allowing electric companies to deliver timely and clear communications that help customers conserve electricity — and save money — at times of extremely high demand,” Senior Vice President of Customer Solutions Phil Dion said in a statement. “As summer begins and Americans use more electricity to cool their homes and businesses, demand response programs allow grid operators to maintain reliability while helping to keep customer bills as low as possible.”

Utilities see demand response as a key resource to meet growing electricity demand. EEI told the FCC in its March request that the clarification would help “ensure that utilities can continue to provide safe, reliable, and efficient service to customers.”

U.S. electricity demand could grow 25% from 2023 to 2030, ICF said in a May report. And utility demand-side management programs, which include demand response, could be able to meet about 10% of U.S. electricity demand by the end of this decade, it found.

The FCC said its decision “will promote reliable utility service to customers as well as cost savings to consumers.”

The FCC received 15 comments on the utility trade group’s request for a declaratory ruling, and only one objected. A group of public interest groups that included the National Consumer Law Center argued that calls soliciting enrollment in demand response programs are not sufficiently integral to the provision of energy service to be deemed closely related to that service.

“But demand response communications, as described in EEI’s petition and as defined in this declaratory ruling, are not messages about enrolling in energy savings programs or any other program,” FCC responded.

Utility demand response communications are instead “short-term, targeted communications during critical times of peak demand to provide customers with information to avoid service disruptions,” the commission said. “As a result, they are not incentives to purchase and install equipment and appliances that exceed federal or state minimum efficiency standards.”

NCLC doesn’t dispute the efficacy of demand response programs, but wants to ensure consumers have control over what communications they receive, NCLC Senior Attorney Margot Saunders said. The FCC’s declaratory ruling is an interpretive order and there could still be a lawsuit, should a consumer get annoyed with utility demand response messages, she added.

The Environmental Protection Agency’s plan to eliminate the Energy Star program is a “misguided decision [that] would be counterproductive to our national housing, economic, and electricity goals,” Sen. Ruben Gallego, D-Ariz., wrote today in a letter to EPA Administrator Lee Zeldin and provided in advance to Utility Dive.

EPA announced “organizational improvements” in May that would phase out the popular program, which has helped consumers identify energy-efficient home appliances for more than 30 years.

While Gallego’s letter honed in on Energy Star’s potential impacts on energy prices, other lawmakers have focused on the program’s legal standing. Energy Star is “protected under federal statute and thus illegal for the Administration to terminate unilaterally,” 22 senators wrote in a May 20 letter to Zeldin and Secretary of Energy Chris Wright.

Efficiency advocates argue that Energy Star is a popular, cheap and effective program — and also protected by law.

“At a time when American families are grappling with rising energy and housing costs and our nation faces mounting energy and climate challenges, eliminating a highly successful program that lowers utility bills and reduces emissions is indefensible,” Gallego wrote.

“EPA will review the letter and will respond through appropriate channels,” an agency spokesperson said in an email.

More than 2,500 builders, developers and manufactured housing plants are active in the Energy Star program, Gallego noted. In 2023, about 12% of all new U.S. homes were Energy Star compliant.

The program was created in 1992 under President George H.W. Bush and has helped consumers save more than $500 billion in energy costs and 5 trillion kWh since its inception, according to the Energy Star website.

“This program saves families and businesses more than $40 billion every year with a budget of less than $40 million. It’s an astonishingly good deal,” Steven Nadel, executive director of the American Council for an Energy-Efficient Economy, said in a statement.

Congress directed the government to run the Energy Star program, Nadel also noted. “Until now, the EPA has implemented that statutory obligation.”

Lawmakers signing on to the May 20 letter defending Energy Star also noted that the program could not be terminated without Congress.

“The program [is] protected under federal statute and thus illegal for the Administration to terminate unilaterally,” the senators wrote. The group includes Sen. Peter Welch, D-Vermont; Sen. Bernie Sanders, I-Vermont; Sen. Amy Klobuchar, D-Minn.; and Sen. John Fetterman, D-Pa.

The Energy Policy Act of 2005 says that responsibilities for the Energy Star program “shall be divided between the Department of Energy and the Environmental Protection Agency in accordance with the terms of applicable agreements between those agencies.”

In April, more than 1,000 companies and organizations lobbied EPA to maintain the program, noting that “a typical household can save about $450 on energy costs each year” by choosing Energy Star products.

Expanded use of energy efficiency and demand response could help lower Texas power bills while also boosting grid reliability, according to a May 6 paper from Aurora Energy Research.

Electrification, data centers and industrial growth are driving energy demand higher across the U.S., and the trend is particularly evident in Texas. In April, the Electric Reliability Council of Texas published a load forecast that predicted nearly 60 GW of new peak summer demand by 2031. Electricity supplied by the grid is expected to rise from 486 TWh this year to 1,038 TWh in 2031.

“Texas’s economic momentum is driving a sharp rise in electricity demand, creating both a challenge and an opportunity,” Olivier Beaufils, head of USA Central for Aurora, said in a statement.

“For the average Texas household, converting to a heat pump instead of resistance heat can decrease the yearly cost of electricity by $424, approximately 45%,” the Aurora report found. “Increased demand response participation can save industrial consumers $1.9M/yr and residential consumers $225 per year.” 

If 7.7 GW of demand side response capacity, including both residential and industrial consumers, is added to the ERCOT system by 2040, it would reduce the need for new gas-fired generation by 1 GW, the report said. Texas has been trying to build more gas plants through a state backed loan program, but the Texas Energy Fund has seen 35% of its proposed dispatchable capacity canceled or withdrawn amid escalating project costs and supply chain challenges.

“Energy efficiency and demand response programs provide critical additional levers for Texas to keep pace with the demand while cutting costs for consumers and strengthening the reliability of the grid,” Beaufils said.

President Trump on May 9 signed four Congressional Review Act resolutions that will roll back energy efficiency standards and rules passed in the waning days of the Biden administration.

The CRA allows Congress to rescind rules passed by federal agencies. The act, enacted as part of the Small Business Regulatory Enforcement Fairness Act in 1996, applies to interim and final rules.

The rules Trump rescinded covered tankless natural gas water heaters, commercial refrigerators and freezers and walk-in coolers. A fourth resolution did away with certification requirements for a range of products subject to energy efficiency standards, but it did not alter the efficiency requirements themselves, according to the Appliance Standards Awareness Project.

The water heater standard was expected to reduce total costs for consumers by an average of $112 over the life of the appliance, according to a fact sheet from the group. The rule for commercial refrigerators and freezers was expected to save businesses $4.6 billion and walk in cooler standards would have saved businesses up to $6.5 billion, both over 30 years of those products’ sales, the group said.

“President Trump just signed a series of bills that will raise costs for families and businesses,” ASAP Executive Director Andrew deLaski said in an email.

Trump has opposed energy efficiency requirements and has taken other steps to reduce regulation and oversight. The Environmental Protection Agency plans to end its popular Energy Star program, which helps consumers identify energy-efficient home appliances. 

“It’s all about common sense,” Trump said at the signing ceremony May 9, arguing that the efficiency rules cost businesses money and leave consumers with less product choice.

Sen. Ted Cruz, R-Texas, had proposed the resolution rescinding regulations for natural gas water heaters.

“The Biden-Harris administration knew they were increasing costs on American consumers and limiting consumers' ability to choose the heater that works best for them, but they didn't care. President Trump's signature today will ensure this anti-consumer regulation is permanently revoked,” he said in a statement.