Growing California power system reliability threats made vivid by early September Flex Alerts called by the state’s system operator could be relieved by a price signal based on real-time pricing, or RTP, linked to smart customer-owned resources through new enabling technologies, according to the California Public Utilities Commission Energy Division’s June 22 ”CalFUSE” proposal.

The new approach could transform California’s high penetrations of customer-owned distributed energy resources  into a response to electricity market supply and load fluctuations, commissioners agreed in a July 14 order opening a proceeding to investigate the proposal’s potential.

RTP can signal DER owners and aggregators to provide “demand flexibility” by rapidly and cost-effectively responding to rising market prices for electricity by decreasing consumption or exporting stored energy, staff added at a July 21 CalFUSE introductory workshop. 

The CalFUSE framework “is complex, but the complexity will be outweighed by the benefits in the long run,” Southern California Edison Director of Pricing Design and Research Robert Thomas said. Customer bill credits “for responding to dynamic price signals” can “add up to significant affordability gains,” he added.

The proposal offers a vision of “a viable dynamic future grid,” and “utilities are critical to that vision, but it will not work without innovative third-party entrepreneurs engaging customers,” customer-owned device aggregator OhmConnect CEO and Founder Cisco DeVries cautioned.

CalFUSE’s rate design and enabling technologies can lower system and customer costs and drive system flexibility if customers participate and it is a solution that could work wherever power markets and RTP enable it, utilities, DER advocates, and other stakeholders agreed. But whether the plan is too complicated to be workable and how quickly it can be implemented remain highly debated.

The need

California faces a “high DER future” that could overstress the state’s distribution system, a March 2022 CPUC-commissioned white paper said. Customer demand, the state’s zero emissions by 2045 goal, evolving technology, and falling prices will continue to drive DER growth, it added. And Senate Bill 846, passed September 1, provides $1 billion to fund a clean energy reliability plan by 2023, which could further accelerate DER growth in the state.

By 2030, California distributed solar will increase from 2022’s 14,048 MW to 24,721 MW and distributed energy storage will increase from 2022’s 740 MW to 2,587 MW, according to California Energy Commission 2021 projections. California’s 1.1 million electric vehicles are projected to reach 5.7 million in that same timeframe, and its smart thermostats are growing exponentially, CEC data also show.

DER growth is already threatening reliability, as evidenced by the growing “ramp” during late afternoon peak demand periods when solar generation falls and other resources need to be quickly brought on, according to the California Independent System Operator demand flexibility proceeding filing.

“The maximum three-hour ramp in 2019 was 15,600 MW,” but the March 11, 2022, three-hour ramp reached “more than 18,000 MW, driven by a rapid decrease in both grid-connected and [distributed] solar,” during peak evening periods, it reported.

DER could quickly fill the gap between availability of solar and other types of generation, advocates said.

 

The CalFUSE elements

CalFUSE includes universal opt-in access to real-time energy and capacity pricing “specific to each customer at any time” through “a statewide internet-based price portal,” the CPUC CalFUSE proceeding’s opening order said. The proposal also addresses cost recovery for “generation, distribution, and transmission services and other fixed costs,” through individual electricity providers’ rate designs, it added.

A CEC-developed Market Informed Demand Automation Server, or MIDAS, platform or any other “price portal” construct could be the “front end” of what the CPUC described as a “price machine.” The customer-facing price portal would provide utility rate access to customer devices and third parties like aggregators and automation service providers, CPUC staff said in the July 21 workshop.

MIDAS will be a CEC-operated “internet service” with “a centralized, publicly accessible database” to provide “real-time access to time-varying locational electricity prices,” CEC spokesperson Elaine Kahan said in an email. MIDAS data can be used by automation service providers, electricity customers, building owners, and tenants to reduce or shift energy usage to when electricity is less expensive, Kahan added.

Back-end pricing computations will be done by the CPUC’s “price machine,” staff said. Inputs like system load forecasts, distribution circuit load forecasts, and wholesale market prices would be used to generate customer-specific RTP based on their California electricity provider rates.

The price machine’s mathematically derived capacity values for 8,760 hours, or one year, of forecasted demand would meet all Resource Adequacy requirements and recognize the needs and limits of local distribution systems down to circuit or substation levels, the white paper specified.

As tested in the Retail Automated Transactive Energy System, or RATES, pilot, implemented by subcontractor TeMix in SCE territory, the “design principle” is that “fixed cost recovery should be higher when the system utilization is higher,” the white paper stressed. That would ensure electricity provider revenue requirements are met and unintentional cost shifts are avoided, staff added.

Bidirectional pricing will allow customers to import or export electricity at equal dynamic prices, staff said. But third-party aggregation and automation services providers are expected to also “play a major role,” in the “CalFUSE ecosystem” by developing capabilities to make prices more accessible to third parties, optimize system functions, and expand aggregation capabilities, it added.

CalFUSE’s “subscription option” is intended to limit exposure to RTP for customers who choose not to participate, staff said. Those customers would subscribe to a monthly electricity usage based on their consumption history and be billed at a pre-set “predictable” rate, allowing a “transition from legacy rates to the CalFUSE price signal,” staff said.

The subscription would allow them to “buy additional energy” or “sell back any unused or excess energy” and benefit from bill charges or credits at more advantageous dynamic prices, it added.

Finally, proposed “transactive features” would allow forward energy arbitrage by customers or aggregators who “commit to future import or export of energy” at forecasted prices, the white paper said. This could both maximize customer benefits and allow system operators “more visibility for planning and operations,” it added.

But that only adds to the complexity, some stakeholders objected.

Too complicated?

Workshop feedback suggested the plan may be unworkably complicated, but utility and private sector rate design analysts disagreed.

CalFUSE offers “much more dynamic, granular pricing” than today’s time-of-use rates, but rising DER penetrations make that necessary, Regulatory Assistance Project Principal Carl Linvill said. Its RTP for energy addresses short-term marginal costs, its RTP for capacity meets longer-term marginal costs, and the bidirectional export-import price fairly compensates DER output and customer usage, he added.

Implementation will take time, and “most customers are unlikely to actively manage their consumption, especially if it is difficult or limits comfort,” he added. But utility, community choice aggregator and private sector flexible demand service providers “can build successful businesses from handling the complexity” with automated systems that aggregate and operate smart devices in response to price signals, he said.

CalFUSE is a “natural evolution” of rate design and “a fairly elegant solution” to promoting flexible demand, solving renewable over-generation, and dealing with net peak load issues, Tesla Managing Policy Advisor Damon Franz told the workshop.

Replacing demand charges with RTP capacity values could favorably impact Tesla’s EV and EV charger businesses, he said. And the bidirectional import-export pricing could be “critical” to its residential solar and storage businesses because it “will be fairly easy for customers to understand and for aggregators to respond to,” he added.

Brattle Group Principal Sanem Sergici, who often advises utilities and regulators on rate design, agreed with Linvill and Franz.

CalFUSE is “a first step” toward “a future of dynamic pricing and automation,” Sergici said. “Some aggregators will find business models and ways to communicate with customers and orchestrate devices and pricing signals to maximize customer savings because that is how innovation happens,” she added.

California’s 2020 outages were a driver behind development of CalFUSE, the white paper acknowledged. And during that August energy crisis, demand-side aggregator OhmConnect’s customers earned over $1.3 million through 739,000 usage adjustments, 580,000 automated, “without a single failure in dispatch,” DeVries reported.

The CalFUSE “vision” requires much higher levels of “customer adoption of technologies capable of automating customer load,” OhmConnect’s filing said. Much of that will be managed by utilities, but opportunities for “third party customer engagement and energy management should be a critical component,” DeVries added.

Market tests show OhmConnect could reduce customer bills significantly where customer costs are tied to electricity market pricing, which is the objective of the staff proposal, he said. With RTP “throughout the device ecosystem” and adequate access to customer data, third parties can create successful new business models that also reduce customer bills and lower system costs, DeVries said.

Compensation could be a monthly energy management payment or a share of customer savings and is likely to include compensation for critical peak and emergency demand reductions, he added. “There are multiple complexities, but this transition to dynamic pricing is urgently needed and we are way behind schedule,” DeVries said.

Go fast or together?

A major debate about CalFUSE is how quickly it should be implemented, with some urging prudence and others focused on an urgency made undeniable by September’s heat wave-driven wildfires and reliability-threatening power demands.

California’s electricity providers want “a more deliberate or phased” implementation “that takes advantage of the results from current pilots,” like Phase 2 of RATES, SCE’s Thomas said. The RATES Phase 2 report on an opt-in pilot across SCE territory of CalFUSE elements like customer response to RTP, the subscription option, and “automated vendor software,” is due in early 2025, according to SCE’s filing.

San Diego Gas and Electric “is not convinced” that the benefits of dynamic pricing for all customers will outweigh costs because they “have not yet been quantified,” its filing said. “Learnings” from pending RTP pilots will help address those doubts, it added.

Dynamic rate pilots proposed by Pacific Gas and Electric were approved after detailed analysis of customer differences, PG&E’s filing added. Because responses to dynamic rates differ significantly depending on customers’ “real-world circumstances,” moving before 2025 results on utility pilots could produce poor results, the filing said.

The Agricultural Flexible Irrigation Technology, or AgFIT, dynamic rate pilot, jointly implemented by CCA Valley Clean Energy, energy services provider Polaris, TeMix and PG&E, will send price signals to agricultural customers “to shift flexible irrigation pumping load away from daily load peak,” the Valley Clean Energy-Polaris filing said.

Implementing AgFIT showed the challenge of “even a small pilot where novel dynamic rates are being introduced to customers,” the filing said. In an uncommon IOU-CCA agreement, Valley Clean Energy also advocated awaiting “learnings” from “multiple large-scale pilots” on “best practices for scaling implementation of dynamic rates.”

Despite working with electricity providers on the pilots, TeMix somewhat disagreed. “The commission should authorize the CalFUSE tariff as opt-in for all customer classes as soon as possible,” its filing said. But regulators should also support further “demonstration projects” on “the CalFUSE approach,” it acknowledged.

Others urged acting sooner.

“Foundational work” on CalFUSE “needs to be done quickly,” emphasized the filing by the Center for Energy Efficiency and Renewable Technologies, which has long urged more use of demand flexibility. Opt-in CalFUSE rates should be implemented by summer 2023 “to determine what works,” because some rate proposals “may appeal to economists” but “customers may not understand or respond,” it added.

Tesla’s Franz cautioned that pilots may not show CalFUSE’s real appeal. “Limited” pilots can require significant hardware and software development by third-party companies, and they may not choose to participate if they cannot “get more output for that work than the pilot provides,” he told the workshop.

But that reasoning could also justify awaiting pilot results, SCE’s Thomas responded. Moving too quickly could result in a more expensive and slower deployment, because electricity providers could incur similar costs “and only after months or years would the customer response be clear,” he said.

“We don't want to fully implement what is not a fully informed pricing signal, disrupt customer participation, implement again, find out it works only somewhat, and then implement again,” he added. “Small pilots leading to full implementation by 2025 can avoid disruption and potential costs.”

The timeline and monetization mechanisms remain to be defined, and “it may seem complicated until an innovator simplifies the problem and builds a business model,” Brattle Group’s Sergici said. “But that does not mean the proposal is too complicated. It is the problem statement that will lead to solutions” sooner or later, she added.

The NextEra Energy “Real Zero” plan announced June 14 by the world’s biggest investor-owned utility could be a game-changing climate goal but comes with unanswered questions, stakeholders said.

Real Zero would eliminate carbon emissions from NEE operations by 2045 without relying on carbon offsets as other U.S. utilities’ net zero plans do, and is “the most ambitious carbon-emissions-reduction goal ever set by an energy producer,” NEE’s June 14 statement said. With it, NEE and subsidiary Florida Power and Light are challenging utilities with net zero climate goals, NEE President and CEO John Ketchum said.

NEE’s business model, based on utility-scale renewables development, has helped to propel it to the highest market capitalization of any electric utility in the world, NEE reported to investors June 14. Real Zero would “transform” over 80% of FPL generation to solar, battery storage, and green hydrogen, while “enhancing reliability, resiliency, affordability and cost certainty,” NEE said.

The Real Zero Blueprint would also leverage NEE’s scale as the biggest U.S. electricity producer to lead the over “$4 trillion market opportunity,” in decarbonizing the U.S. economy, NEE added.

It may be a “paradigm shifting” plan, according to longtime FPL critic Stephen Smith, executive director of the Southern Alliance for Clean Energy, or SACE. “When a private business as successful as NextEra puts this kind of ambition on the table, it moves the needle,” and “it has committed to elements of the blueprint in planning documents, showing it is serious,” Smith said.

FPL is also “on track” to meet its 2025 solar commitments, underscoring that seriousness, SACE, Sierra Club and other stakeholders agreed. 

But Real Zero’s 90 GW of solar, 50 GW of battery storage, and yet-to-be-piloted green hydrogen plan will be difficult to reach by 2045 at the promised “zero incremental costs” to customers, those stakeholders also agreed. And it lacks specific demand flexibility and energy efficiency goals likely to be needed to meet accelerating transportation and building electrification loads, they added.

Real Zero

From 2005 to 2021, NEE increased its emissions-free generation 300% and, from 2006 to 2021, its earnings per share had an 8.4% compound annual growth rate and its shareholder returns were 620% higher than the S&P 500 average, it reported June 14. In that period, unregulated subsidiary NextEra Energy Resources built 24 GW of wind and solar, NEE’s statement added.

In 2021, U.S. electric utility emissions were “36% below 2005 levels,” according to the Edison Electric Institute and a growing number of utilities have decarbonization commitments. But, unlike Real Zero, those net zero goals will not achieve “a total transformation of our energy infrastructure,” the NEE statement said.

Real Zero will eliminate all direct and indirect carbon emissions with “unprecedented speed and scale,” NEE added. FPL will be 52% decarbonized by 2030, 62% by 2035, 83% by 2040 and 100% “no later than 2045,” NEE committed.

By 2045, FPL’s current 4 GW of utility-scale solar will be over 90 GW, and its 0.5 GW of battery storage will be over 50 GW, the blueprint added. It will also convert 16 GW of existing natural gas generation to run on green hydrogen created from water electrolyzed by solar generation, a transition that avoids stranded assets, the blueprint added.

FPL will maintain its 3.5 GW nuclear capacity and, for added reliability, will develop a 6 GW carbon-neutral renewable natural gas capacity for limited use in its existing natural gas plants, FPL spokesperson Christopher McGrath told Utility Dive.

The blueprint reported past support by FPL for customer-owned demand-side resources like energy efficiency, but neither the blueprint nor McGrath proposed specific expansions of those resources.

Renewables’ accelerating cost competitiveness, largely due to global demand for natural gas that is driving up its price, makes Real Zero feasible, NEE’s investor presentation reported. The levelized cost for existing natural gas generation rose 63% from January 2021 to May 2022, while the cost for new solar rose only 16% and new wind’s cost rose 11%, NEE added.

Though renewables prices are also now rising, largely due to supply chain constraints, they are likely to retain relative cost-competitiveness, according to a June 30 BloombergNEF report.

With continued cost competitiveness, further technology advances, and adequate state and federal policy support, Real Zero is achievable at “zero incremental cost to customers,” NEE said. A zero emissions facility “won’t cost customers more than building a fossil plant to meet that same electricity demand,” McGrath added.

Critics support the ambition

Traditional FPL critics see promise in Real Zero.

SACE “has repeatedly called for a carbon target from FPL, but the scale of the Real Zero ambition has shifted the debate with utilities and we welcome it,” SACE’s Smith said. “It is what the planet needs and what the power sector needs to tackle the climate problem.”

FPL’s “no incremental cost to customers” language qualifies its commitment, but uncertain carbon-related politics and market dynamics require that, he said. SACE “will hold FPL to its word” but is giving the utility “a pass for now because we do not want to make the perfect the enemy of the good.”

Real Zero also shows other utilities that “renewables can be good for business and attract investors,” agreed Institute for Energy Economics and Financial Analysis Energy Data Analyst Seth Feaster.

Sierra Club, which has long fought FPL over coal use and is still fighting it over natural gas infrastructure, sees Real Zero as  “a game-changing commitment,” the Club’s Beyond Coal Campaign Senior Campaign Representative in Florida Susannah Randolph wrote June 22. But its viability “will be in the execution.”

“Other Southeastern utilities claim clean energy is a risky financial bet, but FPL is now on the record that it isn’t,” she said. FPL’s proposed investment in green hydrogen, however, includes cost uncertainties for electrolyzers and plant and pipeline retrofits that could undermine its “no incremental cost to customers” claim, she added.

Even advocates for green hydrogen agreed.

About green hydrogen

Studies show green hydrogen’s current high electrolyzer, production and transport costs, and other uncertainties will resolve with scaling, Green Hydrogen Coalition Founder and President Janice Lin said.

And scale will come because some industries as well as long-distance aviation, ocean shipping, and power sector long-duration storage “urgently need renewable hydrogen to become climate neutral,” German consultant Agora Energiewende’s August 21 report said. Like wind and solar, green hydrogen costs will fall “if scale-up occurs,” agreed BloombergNEF’s November 2020 assessment.

Neither study reported deployment levels that are driving costs down, but power plant off-takers like FPL can provide that, which is why Real Zero could be pivotal for the technology, Lin said. 

FPL’s green hydrogen pilot, scheduled for late 2023, will use a 5% green hydrogen blend in its Okeechobee natural gas plant, McGrath said. A solar project and five electrolyzers built nearby will complete FPL’s Cavendish NextGen Hydrogen Hub, he added.

But Real Zero overlooks green hydrogen’s many uncertainties, stakeholders said.

The pilot’s unproven-at-scale technology may not work or may be too expensive and could result in FPL continuing to use natural gas blends that create emissions, Sierra Club’s Randolph said.

In addition, there are significant concerns about green hydrogen’s “timeline” because “the turbine and pipeline technologies for 100% green hydrogen are not ready,” IEEFA’s Feaster cautioned.

Hydrogen-natural gas blends of up to 5% are “generally safe” for pipelines and appliances but higher levels “require modifications” to avoid leaks, malfunctions, or even “gas ignition,” a July 18 University of California at Riverside report to the California Public Utilities Commission found.

And green hydrogen has competition, IEEFA’s Feaster said.

“There is a race with battery technologies, which the tech, utility, and auto industries are investing hundreds of billions of dollars in,” he said. Green hydrogen “may be the answer in 10 years,” but “there will likely soon be faster-charging, longer duration batteries, while the cost, complexity, and inefficiency of hydrogen could be obstacles,” he added.

But despite the questions around green hydrogen, some new technology like it “will likely be needed to reach high decarbonization levels,” SACE’s Smith said. FPL’s bet on electrolyzing hydrogen with solar may be the cleanest and most likely, and is worth exploring, because of climate change’s challenge to humanity and the planet, he said.

FPL’s commitment, and its announced interim commitments on carbon emissions reductions, show “real leadership” and “a specific and serious level of planning,” said Smart Electric Power Alliance Senior Manager, Research and Industry Strategy, Lakin Garth. But there is at present “no certain answer to how feasible and cost-effective” all the parts of its annual resource planning filing with regulators in April are, he said.

And to reach Real Zero by 2045, FPL will likely need an all-of-the-above approach that also includes demand- side resources that are not detailed in the blueprint, he and other stakeholders said.

The missing piece

Beyond green hydrogen uncertainties, FPL may have overlooked the benefits of flexible demand-side resources to power systems with high variable renewables penetrations, advocates said.

Through 2021, FPL’s demand-side management has produced a “cumulative summer peak reduction of nearly 5,500 MW” and “cumulative energy savings of approximately 95,000 GWh,” the blueprint reported. But FPL has used regulatory technicalities “to dodge” genuinely supporting energy efficiency, Sierra Club’s Randolph wrote. And “it is no secret FPL was behind the effort to end rooftop solar’s net metering incentive in Florida,” she added. 

Real Zero “leans in on innovation,” she said. FPL “could do the same with customer-owned demand-side resources to achieve both system and customer savings instead of using the most expensive approach,” Randolph added.

A zero-carbon power system can benefit from flexible behind-the-meter resources, SEPA’s Garth agreed. And ongoing scenario planning can evolve their role in reducing system costs and customer rates as technologies and economics change, he added.

FPL’s “ambitious initiative” does include a general reference to energy efficiency and demand response in its brief mention of smart grid technologies, California Efficiency + Demand Management Council Executive Director Joe Desmond emailed. And though it does not identify specific targets, the blueprint includes the undetailed observation that FPL is “investing and innovating” in demand-side resources, Desmond added.

FPL has long had “one of the largest demand-side management programs in the country,” and remains “open to the possibility of innovative technologies,” FPL spokesperson McGrath said. But its focus is “generation resources needed to be carbon-free by 2045, keep the lights on 24/7, and keep customer bills below the national average,” he said.

FPL was, however, ranked 51st of the 52 major U.S. investor-owned utilities for energy efficiency performance, program diversity, enabling infrastructure, and policies in the American Council for an Energy-Efficient Economy’s 2020 Utility EE Scorecard.

More effective use of energy efficiency could be one of the keys to managing anticipated loads from transportation and building electrification.

FPL is committed to EV growth and EV charger deployments in one of the fastest-growing state markets, McGrath said. But the blueprint provides no specific plans for addressing the explosive load growth expected from transportation electrification, McGrath acknowledged.

FPL also does not include a strategy for taking advantage of demand-side resources and dynamic loads from building electrification, he said. Addressing building electrification loads with grid-interactive efficient buildings could save the U.S. “between $8 billion and $18 billion annually by 2030,” a May 2021 Department of Energy building electrification roadmap reported. Cumulative benefits through 2040 “could reach $100 billion to $200 billion,” the roadmap added.

NEE and FPL may have omitted specific demand-side resource plans from the blueprint because “there is shareholder value they are planning to take advantage of in the future by owning them,” SACE’s Smith speculated. 

Ambitious decarbonization plans like Real Zero will need “all available options,” including “innovative demand-side initiatives,” Ryan Hledik, a Brattle Group principal and co-author of DOE’s electrification roadmap, said. “Regulators will find expanded energy efficiency and load flexibility investments are cost-effective and key to affordable decarbonization for consumers.”

None of the stakeholders contacted by Utility Dive debated McGrath’s assertion that Real Zero is “game-changing” and a “bold goal.” Implementing it “will not be easy, but FPL is not doing it because it will be easy, or to meet a mandate,” McGrath said. It is doing Real Zero because “it is the right thing to do for our customers, for Florida’s economy, and for the environment.”

And there is overall optimism about the chance for success.

FPL “has a track record of following through,” added Sierra Club’s Randolph. “It moved from coal when natural gas became the lower cost option, and it now is moving to solar and green hydrogen for the same reason. But everyone is watching closely to see how it implements the blueprint.”

Avangrid subsidiary United Illuminating expects to have 3,000 electric vehicles in its Connecticut territory by 2024 and has been working with Bidgely to utilize them as a grid resource and avoid driving higher peak demand when they are charging, Avangrid officials said.

Avangrid says it is developing a similar program in New York and is still in the process of selecting a long-term vendor in both states. Its work with Bidgely is being done under a one-year partnership announced in May.

The biggest challenge in serving EV load will be integrating the new demand in ways that do not drive higher peak demand, Charles Spence, Avangrid manager of customer programs and products, said in a July discussion of its load management efforts with Bidgely.

Connecticut finished 2021 with about 21,000 EVs registered in the state, but its long-term transportation strategy calls for 500,000 by 2030. As the number of plug-in vehicles in its service territories grows, Avangrid sees three key barriers to harnessing them as a grid resource, Spence said.

“The biggest challenge is obviously integrating that load,” Spence said. “We're seeing just an unbelievable number of vehicles, [and] those vehicles all can consume 60 kWh if they are expended fully and get recharged in a day. That's generally what the whole house uses.”

That load must be integrated on a volume basis as well as timing, he said, to avoid spiking demand when residential customers return home in the evening and plug in their vehicles. Avangrid’s demand response managed charging program in Connecticut helps with that, but other challenges include accommodating varied customer technology preferences when it comes to vehicles and chargers, and ensuring investments and incentives are properly sized.

“Making sure that we're not paying people too much, but on the other hand, [they] aren't being paid so little that they're not interested in participating,” Spence said.

Avangrid, like the rest of the utility sector, is still developing best practices when it comes to utilizing EVs as demand response assets, Spence said. Needs can vary from territory to territory, and between more and less constrained circuits, he said.

In the first year of its Connecticut program, Avangrid could call up to 15 demand response events per month where it controls customer EV chargers to reduce grid stress. Customers are able to opt out of events.

“I doubt we'll ever really call that many ... that's pretty heavy-handed,” Spence said. But the flexibility to call more events allows for the utility to test whether customer participation drops off over time. The utility is also able to use its extensive advanced metering infrastructure network in Connecticut to identify customers who have EVs but are not yet participating in a demand response program, or to better engage with enrolled customers who are not participating.  

Avangrid is still building out its program and doesn’t yet have a clear indication of how large a demand response resource EVs can be, said Spence.

“We’ll have a better idea of this total resource after the first program year where we’ve collected data on participation and gathered learnings,” Spence said in an email. “At that point, we’ll able to better estimate things like: average battery size of participating EVs, average participation per participant in terms of curtailable load, and the reliability of the resource overall.”

“The resource is absolutely growing and we expect this to be a substantial flexible resource over time,” Spence said.

Avangrid is working to develop a similar program in New York and in June filed a revised managed charging proposal with state regulators for its New York State Electric & Gas and Rochester Gas and Electric subsidiaries.

Though the New York programs will be larger than Avangrid’s Connecticut efforts, “this will end up being a very similar program, both from the perspective of what regulators have assigned to the utilities in the state, but also in the type of program we implement,” Spence said.

Energy efficiency, the cleanest, lowest cost, most overlooked resource in the climate fight, is now part of the world’s pushback against Russia’s invasion of Ukraine, according to the International Energy Agency.

Energy efficiency, or EE, is fundamental to the clean energy transition, analysts have long agreed. But the Ukraine war-driven urgency for the European Union to end reliance on Russian natural gas and avoid stopgap coal burning now makes EE vital, a June 10 statement co-signed by the U.S. and 25 IEA parties in the Americas, Africa, Asia and the EU recognized.

EE is “critical” to keeping world energy “affordable, secure, and clean,” IEA Executive Director Fatih Birol told the annual IEA Global Conference on Energy Efficiency June 8. And world leaders must make the conference “a meeting of hope” where “the world hits the accelerator on efficiency” or they may “pay the price for years to come.”

This “could be the peace project of our time,” U.S. Principal Deputy Assistant Secretary for Energy Efficiency and Renewable Energy Kelly Speakes-Backman added at the conference. “Russia’s unlawful invasion of Ukraine has challenged us to think differently about how we generate, distribute, and use energy, and the case for energy efficiency has never been more urgent.”

In the U.S., EE has enormous potential but must demonstrate its value across different regulatory and market circumstances, Speakes-Backman and other U.S. EE advocates said during and after the IEA conference. With more innovative and comprehensive policies, EE can have great value as demand response, or DR, and be used when and where the power system needs kWh reductions the most, they said.

The IEA initiative

New numbers support the IEA initiative.

Halving EU energy intensity, a ratio of energy use to gross domestic product, could reduce the need for “650 billion cubic meters of natural gas per year,” about four times the EU’s 2021 Russian imports, according to the IEA report released during the conference. “Total energy savings” could lower EU electricity bills “at least $650 billion a year by 2030,” the report added.

The Ukraine invasion “has massively disrupted European and global energy markets,” said the May summary of REPowerEU, the European Commission, or EC, plan to end Russian fossil fuel dependence. It called for raising the EU-wide target on total energy savings through efficiency efforts for 2030 from 9% to 13%. 

“The current scale of energy efficiency action is not sufficient” and implementation must be accelerated “on a global level,” the IEA post-conference 26 party statement agreed. EE “offers immediate opportunities to reduce energy costs and reduce reliance on imported fuels,” it stressed.

The EC proposal to accelerate EE “would be a step forward,” but “still must be approved by the European Parliament’s 27 member states,” Regulatory Assistance Project Executive Director for the EU Jan Rosenow told Utility Dive.

Final approval could come in the fall, and “hopefully before the next winter heating season because there could be real shortages and price spikes,” Rosenow warned. “But at least EU countries are finally considering policies that recognize it is necessary to move entirely away from natural gas as soon as possible.”

Recent executive orders from President Biden on heat pump production and liquified natural gas exporting show it supports the new EU initiative and may see market opportunities in it, Rosenow and others said.

EE in the U.S.

It is not clear if or whether the IEA initiative will directly impact the U.S. because “we march to our own drum,” American Council for an Energy Efficient Economy Executive Director Steve Nadel told Utility Dive. Only a few of some 50 federal efficiency standards that need revision have advanced, though new state and local performance standards for buildings and vehicles are making a difference, he said.

The most important policies are those that can make EE cost effective, like rebates and financing mechanisms that reduce upfront deployment costs, Nadel said. Some utilities, green banks and institutional lenders support on-bill financing and property-assessed clean energy, or PACE, programs that allow customers to pay for EE installations with their bill savings, he said.

Those policies, along with time-of-use, or TOU, rates that shift usage, and performance standards and codes for buildings and appliances have helped make California, followed by Massachusetts, the top two EE states, according to ACEEE’s December 2020 state analysis. For recent light bulb efficiency standards and residential and commercial building codes, Nevada was ACEEE’s “most improved” state.

Energy efficiency resource standards, which commit utilities to binding EE targets, are in place in 27 states, the ACEEE state analysis reported. “Wherever there is a standard, utilities have ramped up to meet them,” Nadel said.

In an ACEEE February 2020 utility analysis, Massachusetts’ Eversource and National Grid tied for first place for energy savings of over 3% in 2018, ACEEE said. San Diego Gas and Electric, or SDG&E, Illinois’s Commonwealth Edison, or ComEd, and Baltimore Gas & Electric followed in the top five.

Most utilities have ratepayer-funded EE programs, but adoption “tends to ebb and flow” with the economy, and “more can and should be done,” SDG&E spokesperson Sara Prince emailed. EE incentives are “the right thing to do,” agreed ComEd spokesperson Thomas Dominguez.

Residential EE upgrades with product rebates or on-bill financing are available in New York, Allan Drury, spokesperson for Consolidated Edison, said. And large commercial customers have incentives to reduce usage “at times of high demand,” he added. Massachusetts’ Mass Save programs are similar, Eversource Managers for Energy Efficiency Amy Findlay and Bill Stack told Utility Dive.

Oracle subsidiary Opower works with utilities and retail energy suppliers to engage customers toward behavioral actions that reduce usage, and recently, toward shifting usage to meet system needs, Oracle Utilities Group Vice President and Head of Opower Matt O’Keefe told Utility Dive. The key to Opower’s business model is the “regulatory and policy context,” he said.

EE and DR offerings, with TOU rates that support demand shifts, can reduce peak usage an estimated 5%, according to Opower. Its California EE programs were “nearly 72% of all peak savings claims from IOU EE programs” in 2021, according to California regulatory data.

Despite utility industry leaders’ EE programs, overall energy savings from ratepayer-funded EE have remained “fairly level” in ACEEE’s most recent analyses, Nadel said. But a new approach to EE policy can change that, advocates said.

A new way to use EE

U.S. consumers spend over $400 billion annually on energy for residential and commercial buildings and over 30% “is wasted,” according to a June 2022 Lawrence Berkeley National Laboratory, or LBNL, report. But “understanding efficiency market drivers and possible future efficiency market attributes” can allow policymakers and other stakeholders to change that, the report said.

There is an emerging realization that “reducing a kWh during peak demand is way more valuable to the climate and public health than reducing a kWh of overnight usage,” Rhodium Group Senior Analyst Ben King, previously a DOE analyst and representative for EE to the IEA, told Utility Dive. 

New policies can provide incentives for EE to function as DR and make new and retrofitted grid interactive efficient buildings a significant system resource, King said. But designing those policies remains “a solution to target,” he acknowledged.

New research at LBNL may accelerate that policy design, according to LBNL Electricity Markets and Policy Department Program Manager Natalie Mims Frick. EE can be DR “if it changes a building’s electricity use when it matters to the system,” and new LBNL work on building load shapes is quantifying that potential, she said.

Policy incentives could then be designed for the EE tools that optimize peak load reductions, and as system needs evolve, those incentives can be re-targeted, Mims Frick said.

Policies that optimize EE as DR can “provide savings for the entire system” and make the energy transition “more affordable,” agreed Commissioner Megan Gilman of the Colorado Public Utilities Commission during a June 30 LBNL webinar on the future of energy-efficient buildings.

With power system supply becoming more variable and less flexible, EE as DR can make a net zero emissions system more efficient, added Southern Company Chief Economist and Director of Planning, Regulatory & Strategy Support Kenneth Shiver in the webinar.

EE “is where the conversation begins” for making new build and building retrofits sustainable, and “the policies most agile at using EE to meet market needs are becoming the most attractive,” said Trevor Joelson, Business Development Manager for Commercial Energy Services for heating and cooling systems provider Trane Technologies.

But new policies could maximize EE’s potential even more by rewarding integrated design of EE installations, leading EE specialists said.

The biggest picture

The big payoff from EE will come from integrative design of things that use energy as whole systems for multiple benefits, according to extensive data analysis by Amory Lovins, co-founder and Chair Emeritus of Rocky Mountain Institute and Stanford University Adjunct Professor of Civil and Environmental Engineering. 

Policy support for integrative design applications can drive innovation beyond using EE as DR to new technologies, financing strategies, and business models, Lovins’ work has shown. EE “is perceived as a cost, not as a savings, but new business models that incorporate integrative design are ripe for application,” he told Utility Dive.

An emerging energy-as-a-service, or EaaS, concept could move the private sector toward a more integrated use of EE and renewables, some EE advocates said. EaaS is similar to “traditional” companies that contract to provide energy savings, but the EaaS provider makes all project capital investments and owns and manages the project, according to a 2019 Deloitte white paper.

The EaaS provider has an incentive to integrate all EE options into the project’s design because it carries all project risk and derives greater profit from optimizing project performance, Deloitte said. The customer, typically the building owner, shares in the savings according to the terms of five-year to 20-year contracts and benefits from the “simplification” of energy management, it added.

The global potential revenue of EaaS could reach $278 billion per year in 2028, according to a Navigant Rearch 2019 (pre-pandemic) estimate. And established energy service contractors, like Honeywell and Trane, have “a powerful advantage,” Deloitte said.

EaaS could “enable a significant amount” of EE adoption, Trane’s Joelson agreed. Some large Trane commercial customers “see no reason to give up the savings opportunity to a third party,” though others, like large data centers, which are aggressively growing, may “want to focus on their core business,” and therefore welcome EaaS if its benefits outweigh its costs, he added.

Mechanisms like limited energy savings performance contracts with companies like Honeywell and Trane work for large commercial customers, but EaaS might enable EE for residential customers, Rhodium’s King said. It might be implemented as a subscription fee but that kind of use of the concept “pushes beyond where providers have gone so far,” he recognized.

Though utilities have still not generally adopted EaaS, they “have a natural advantage” because of “long experience of owning and operating the essential physical assets,” Deloitte said. And it could be an innovative way “to improve their connection” to consumers, the paper said.

It offers “an interesting new customer relationship” and is “something we might explore if it delivered a better customer experience,” Eversource’s Findlay said. But it would require the utility to develop “a different line of business,” she added.

Whatever business models might emerge, the acknowledgment of EE’s importance was welcomed by advocates.

“It is easy to think about 2030 or 2050,” but “policy decisions now about energy efficiency in the next three years will impact the climate and the Ukraine war,” Ireland Environment, Climate, Communications, and Transport Minister Eamon Ryan warned world leaders at the IEA conference.

“There is no distinguishing between the EU effort to get off Russian fossil fuels and what we do in the U.S.,” Lovins agreed. “The high EU energy prices rippling through markets all over the world are sending a global price signal to incentivize efficiency.”

Ithaca, New York, made headlines last year when its city council voted to fully decarbonize. Achieving the 2030 goal will require grid decarbonization, electrifying transportation and rolling out heat pumps to the city's 6,000 aging commercial and residential buildings.

Ithaca is known for its progressive politics — in the 90s the city pioneered a time-based currency to inspire local spending, for example. But the decarbonization plan is among its most ambitious efforts, according to Director of Sustainability Luis Aguirre-Torres.

"When I came to Ithaca last year ... my job was to craft a plan to decarbonize in eight years. I told the mayor, 'You're nuts. This is very difficult to achieve,'" said Aguirre-Torres, who took the job in April 2021.

Ithaca's plan is "innovative," Building Decarbonization Coalition Executive Director Panama Bartholomy said, and is an example of the kind of work many cities are now exploring.

"It's encouraging to see a city take a wholesale approach to buildings instead of trying to adopt policies that are more reactive," Bartholomy said. "Every major city in the United States right now is trying to figure out the right model for how to do this."

About 40% of Ithaca homes are more than 100 years old, and the city says a full retrofit of every building could cost $600 million. So how can a city with about 30,000 residents and projected revenues of around $80 million finance such an ambitious project?

Installing heat pumps and making other efficiency improvements makes financial sense for some buildings: the energy savings will pay for the improvements. Other projects may be close, or simply not pencil out. Either way, the savings accrue slowly. So in order to get all buildings decarbonized, the city aggregated blocks of buildings to manage project risk, and then securitized the project to attract private capital. 

"Similar to the way the mortgage crisis happened," said Aguirre-Torres. Though he quickly added that the plan is also very different because the number of buildings being aggregated is so relatively small. 

"The numbers work for some [buildings], they don't work for some. But in the end, as a whole, it works for the investor," Aguirre-Torres said. The program is essentially a way of covering the upfront costs of making building improvements and turning it into “electrification as a service,” he explained, resulting in long-term leasing or long-term lending at a low interest.

Investors in Ithaca's decarbonization plan are a Brooklyn-based climate tech company called BlocPower, and Boston-based private equity firm Alturus. The two have combined to commit about $105 million to make low- and zero-interest loans for heat pumps and other electrification technologies available to residents and businesses, with BlocPower acting as program administrator and also lending its expertise in building energy use analysis.

"This is a unique opportunity to build the blueprint of how we can actually accelerate the adoption of all the technologies," Tommy Freeman, head of strategic partnerships at Alturus, said during the Bloomberg Green Summit in April.

But how will these companies help Ithaca to decarbonize? What does the city need to accomplish its goals? And are there concerns about the use of private equity funds?

The 'easy' challenge of building electrification

Ithaca has annual emissions of about 400,000 metric tons of CO2, with about 40% from buildings, 40% from transportation and 20% from waste and other sources, said Aguirre-Torres.

A 2021 energy code will soon ban new gas hookups in Ithaca building construction, "so my job was the easy one," Aguirre-Torres joked: to figure out how to make existing buildings carbon-free.

Conversations with local efficiency and construction companies and nonprofits yielded an estimate of $50,000 per building, on average, to retrofit and electrify Ithaca's residential buildings. That figure included multifamily and single family homes, and is an average per-building cost (rather than per individual housing unit). For commercial buildings, the cost to retrofit will average $70,000, including the electric panel and wiring to the utility pole.

Aguirre-Torres estimated it would take at least 1,000 buildings to create the necessary economies of scale and reduce the cost of parts and labor for electrification, and also give the city some bulk purchasing power with which to negotiate the price of heat pumps.

But because the loans for commercial and residential buildings have underwriting differences, the financing had to be executed separately. And so in order to gain economies of scale, Ithaca developed a plan to initially retrofit 600 commercial buildings and 1,000 residential buildings in the next three to four years. The remaining 4,400 buildings will be tackled in a second phase.

BlocPower raised the equivalent of $55 million for the initial electrification effort, while Alturus committed $50 million.

Structuring the financing

Even with the financing secured, setting up Ithaca's program was complicated, particularly on the residential side.

The actual work — replacing gas appliances with electric versions — is "straightforward," said Bartholomy.  The success of electrification programs comes down to, "are you running the right kind of financial model? And are you offering the right kind of customer and installer value proposition?"

New York's constitution doesn't allow a municipality to offer a loan guarantee for private individuals, so Aguirre-Torres negotiated with the state. "Eventually we had a loan loss reserve, basically guaranteeing loans for low-income people and reducing risk in the program," Aguirre-Torres said.

State funds and anticipated incentives were also used to help lower the cost of capital, meaning less cost to the community to electrify. And in order to access federal funds from the American Rescue Plan Act and reduce risk further, the city tapped BlocPower to act as program manager and focus on customer acquisition and building analysis.

BlocPower will analyze buildings that Ithaca wants to decarbonize, develop a work plan, and for a fee, pass the customer information on to local companies and contractors to do the actual work.

"Because we reduce the customer acquisition cost and the sales cycle for local companies, they're happy to pay this fee because it's even lower than their [customer acquisition] costs," Aguirre-Torres said.

A community advisory board is also helping BlocPower to better understand the community’s needs, said Aguirre-Torres. And on customer acquisition, the city of Ithaca is working with community groups, a local engineering firm and Cornell University, to identify buildings for electrification.

The need for private equity in decarbonization efforts

There was some local concern about using private equity to fund energy efficiency and electrification efforts, said Aguirre-Torres. Some activists feared local contractors or businesses would lose out, or BlocPower and Alturus would make too much money on the deal. 

But there is also a growing recognition that private equity funding can be a boon to electrification and energy efficiency efforts, because so much capital can be leveraged so quickly, said Aguirre-Torres. Ithaca's investors will likely see a 3-4% return on their investment, he said, while allowing the city to ultimately decarbonize 1,000 buildings a year.

Experts say Ithaca's approach is a recognition of the urgency of climate change.

"Without a doubt, we're going to need private equity involved in this transition," Bartholomy said. "If you look at the speed and the scale of the energy transition, there's just no way that public capital by itself, taxpayer or ratepayer dollars, are going to be able to help us on this journey, if we're going to try to meet our targets. We need private capital."

"The key thing is really protecting homeowners and residents," Bartholomy said.

Alyssa Giachino, campaign and research director for a watchdog group called Private Equity Stakeholder Project, said there is a need for "creative and aggressive" decarbonization efforts across the entire economy but the use of private equity funds can be risky for communities.

"It's crucial that the public entities that are stewards of the public interest build in strict guardrails, because private equity does not have any obligations to the public interest," Giachino said. "They only have obligations to their investors or shareholders. So they have a singular purpose, which is to maximize profits."

To assuage concerns, Ithaca has worked to be transparent and to financially insulate residents from the program. "The money is either going to come from taxes or ratepayers or private sources," Aguirre-Torres said. "There were people thinking that by using Wall Street money, we were selling the town."

Ithaca's approach was "validated" in January, said Aguirre-Torres, when Gov. Kathy Hochul, D, directed the New York State Energy Research and Development Authority to consider private equity funding strategies to electrify the state's buildings. The state wants to develop 2 million "climate-friendly, electrified or electrification-ready homes" by 2030.

Decarbonization will require investing hundreds of billions of dollars globally, Freeman said.

"If we put that burden on every business owner or every homeowner, to be able to come up with that upfront investment, it's not going to happen — at least not in time," he said. "It is a little bit of a risk, obviously, because the city is the first one to do this. But that's part of the excitement behind it, as well."

Decarbonization pilot will focus on hard to reach 30%

The Ithaca electrification program is just starting up, and the city is taking applications for the first building upgrades. There has been a lot of publicity around the electrification push, which has helped to get the word out among residents.

Whether the program succeeds or fails will hinge on the city's ability to reach residents with limited incomes and who are not immediately interested in the energy transition, said Aguirre-Torres.

The city has first-adopter residents who are already driving electric vehicles and for whom electrification is a natural next step, he said. Likewise, there is a contingent that still resists the notion of climate change and is unlikely to make the electrification switch soon.

"That leaves me with about 50%, and of those, half are low income," said Aguirre-Torres. "But I have incentives, even an economic incentive to pay some of them. So I think it's just about talking to representatives of those communities."

Ultimately, the hard work of decarbonization will hinge on reaching about 30% of the city's population, said Aguirre-Torres. The electrification program will focus on houses that heat with baseboard resistance heating, fuel oil or propane.

Aguirre-Torres said Ithaca has developed a tool with Cornell University, allowing it to see the energy use of any building in the city. "Before doing an energy assessment, I know if it is worth it or not. Because if they have a brand new natural gas furnace, it is not going to make any sense."

"When you have the data on all 6,000 buildings in the city, you can start to tranche and prioritize things," BlocPower CEO and founder Donnel Baird said at the Bloomberg summit. "You can use statistical modeling to start to identify which buildings have furnaces that are about to fail, because you can analyze the installation dates of the gas furnaces in the home." 

BlocPower builds digital models of buildings and helps building owners understand how they can save money while upgrading their building to all electric energy, improving health outcomes and using less energy, Baird said. 

"All of those things create value for building owners and so you want to target and market to different building owners according to what makes the most sense to them," Baird said.

Developing a green, regional workforce

What sort of workforce does it take to electrify 1,000 buildings in a year?

Right now, Ithaca has about 70 people capable of doing the work necessary to electrify buildings. And BlocPower has a restriction on its contract that it cannot take more than 20% of the job opportunities it presents.

"We want to create local jobs," said Aguirre-Torres, who estimates Ithaca needs about 400 workers for the pilot and ultimately 1,000 for the full program. "The idea is to work with local companies and sole proprietors."

So Aguirre-Torres traveled to nearby New York cities of Binghamton, Rochester, Syracuse and Elmira, discussing the job opportunities with local officials and workforce development organizations. The cities formed a "Green Jobs Corridor" with 120 organizations across the state, including labor unions, and are working to share transportation, education, childcare and language support opportunities to develop a regional green workforce.

"I am proud of this," said Aguirre-Torres. "This is going to expand."

Not only will the local economy expand, but with more workers available to electrify homes, Aguirre-Torres said more communities may make similar decarbonization commitments.

"A lot of what we're doing is sharing wisdom," he said. "Hopefully this becomes a blueprint."

Grid impacts and Phase 2

The program will ramp up quickly, particularly as workforce issues are addressed. In the first year, about 20 buildings are expected to be completed, after that ramping as quickly as the workforce will allow.

The slow start will also allow New York State Electric & Gas to upgrade the city's electric grid, and the city is considering non-wires alternatives to avoid significant investment. Ithaca is also adding "as much solar as possible," said Aguirre-Torres.

But even assuming a 30% efficiency improvement in retrofitted buildings, winter electric loads are expected to ultimately triple as the city electrifies. If the city moves ahead with electrification but fails to upgrade the distribution system, "we have three substations that will just catch fire" by 2026, Aguirre-Torres said.

How the second phase of Ithaca's electrification efforts — another 4,400 buildings — rolls out will be determined by data from the pilot. But Aguirre-Torres said the city already has a "hard commitment for the money right now," so long as the pilot works out. Alturus has committed an additional $50 million if initial goals are met.

"Alturus has about $600 million in their pockets, and they can fund the whole thing, but we need to make sure that it works," he said. "That's why we're working so closely with them, to make sure that we're meeting their expectations and making sure that they are getting the returns."

Tesla and Pacific Gas & Electric have launched a program to aggregate the storage in ratepayers’ Tesla Powerwalls to provide emergency power to California’s grid when intense heat drives up demand on the system this summer and the summer of 2023. Participating residential and other distributed battery owners will be paid $2 per kWh for exporting power to the system when supplies are crimped from 4 p.m.–9 p.m. between May 1 and October 31.

Owners of one of Tesla’s 50,000 distributed storage systems in PG&E’s service area can take part in the Emergency Load Reduction Program, or ELRP. This program was approved by the California Public Utilities Commission last December to shore up the grid with 2-3 GW of new resources as well as negawatts – energy use reductions – to avoid blackouts during late summer afternoons and early evenings.

The Tesla-PG&E project allows Powerwall owners to reserve storage capacity to ensure juice in their battery remains after responding to a grid warning so they can power their home as needed or preferred. They also can opt out of a grid warning event.

“Become a part of the largest distributed battery in the world and help keep California’s energy clean and reliable,” Tesla said last week in announcing its deal with PG&E to use the combined output of many customer Powerwalls to create a virtual power plant, or VPP. 

“The program is an opportunity to show how customers can make a difference, replace dirty peaker plants and provide a climate-wise solution,” said Kate Unger, a senior policy advisor at the California Solar and Storage Association. But having the program in place for only two to three years is inadequate because a longer program is needed to increase participation, she added.

What is notable about this part of California’s ELRP program, created in response to Governor Gavin Newsom’s July 30, 2021, emergency summer supply directive, is that it allows for the first time compensation for exports, not just load curtailments, Unger said. That is generally not true of California policy frameworks that govern VPPs, including for resource adequacy need, according to Unger. “This is one thing about ELRP that is a step in the right direction,” she said.

Jin Noh, California Energy Storage Alliance policy director, said the storage industry “worked to get exports recognized and compensated in the ELRP to help with the summer capacity tightness.”

California has the largest amount of distributed battery storage in the nation, hitting 900 MW from more than 75,000 systems installed, California Solar and Storage Association Policy Director Brad Heavner told Utility Dive June 27. 

Between 900-1,350 MW of supply and demand-side resources during emergencies is to come from PG&E territory under the ELRP. 

The Tesla-PG&E program is enhanced by fact that many of Tesla’s distributed batteries in PG&E’s territory are fueled by rooftop solar, according to the utility. Charging behind-the-meter batteries with solar power further reduces demand on and emissions from the grid.

PG&E ratepayers participating in the program are required to help the grid for at least 20 hours and at most 60 hours during annual summer grid alerts and emergencies called by the California Independent System Operator. Participants may get 24-hours’ notice or less. Under the program, battery owners can decide how much power to reserve for their own use.

“With Tesla’s participation in PG&E’s Emergency Load Reduction Program, we are further integrating behind-the-meter battery energy storage based VPPs on the largest scale yet,” said PG&E spokesperson Paul Doherty in an email.

Those enrolled in this ELRP program can not only opt out of an emergency a year but also turn off the VPP setting on their Powerwall to suspend their enrollment in the program but not terminate it.

Tesla said it will compensate program participants once a year or more frequently, starting in March.

The energy efficiency sector continues to feel the impacts of the COVID-19 pandemic, with about a quarter-million contractors and others in the industry still out of work, but states are taking steps to bolster conservation programs and investments to aid in recovery, according to a new report from the American Council for an Energy-Efficient Economy (ACEEE).

A dozen states in 2021 passed new clean energy legislation, including incentives for fuel switching and electrification, or set new appliance efficiency standards, the report notes. Those efforts will get a boost from the $1.2 trillion infrastructure bill signed by President Joe Biden in November, offering states "unprecedented levels of federal support." 

The pandemic has had "lingering disruptions" on the industry, according to ACEEE, and slowed the progress of energy savings programs broadly. The most recent data shows power saved by ratepayer-funded electric efficiency programs dipped 1.1% nationwide in 2020.

States in 2021 passed "ambitious" clean energy legislation to electrify buildings, promote cleaner heating systems, strengthen building codes, and shift to electric vehicles — all moves that will combat climate change while also helping to repair the economy, according to ACEEE.

“As states emerged from the early months of the pandemic, they turned to electrification and energy-saving standards to help address the growing urgency of the climate crisis,” ACEEE senior researcher and report author Weston Berg said in a statement.

There is room to make up. Ratepayer-funded efficiency program savings declined from 26.9 million MWh in 2019 to 26.6 million MWh in 2020. The decrease "reflects the significant disruptions to the energy efficiency industry from the pandemic," according to the report.

The report is an "interim update" to ACEEE’s typically annual state efficiency scorecard, which ranks policy and program efforts to conserve energy. The group said it "decided to forgo a formal scorecard ranking" due to COVID-19 and its impact on energy efficiency last year.

California topped the 2020 rankings, followed by Massachusetts, Vermont, Rhode Island and New York. Several of those states have taken additional steps to cut energy use and reduce greenhouse gas emissions, according to the new report.

In New York, the state is ramping up efficiency and building electrification programs to meet a 185 TBtu savings goal for 2025, Berg said in an email. And those programs are being designed to ensure at least 35% of benefits — with a goal of 40% — flow into disadvantaged communities.

And the New York State Energy Research and Development Authority has set aside more than $230 million for workforce training, heat pump initiatives for low- and middle-income customers, and other conservation programs.

Massachusetts, along with Rhode Island, Maine, Nevada, Oregon and the District of Columbia, passed laws in 2021 to require energy and water use reductions from several types of appliances.

More than a half dozen states passed new energy laws that set electrification as a "growing priority," according to the report. They are Massachusetts, Illinois, Colorado, Minnesota, North Carolina, Oregon and Washington.

California and New York set goals for the sale of all new passenger cars and light-duty trucks to be zero-emission by 2035.

New Jersey "marked a major milestone" in June when it finalized new utility energy efficiency programs, Berg said. Those programs are expected to invest at least $1.6 billion over the next three years, he said, driven by the state's 2018 clean energy law and a "landmark" 2020 Board of Public Utilities order that set annual gas and electricity savings targets.

The increased focus on efficiency will help address employment in the sector, experts say, which remains below pre-COVID levels.

Data from BW Research and E4theFuture, released in July, showed an 11% decline in employment in the efficiency sector, relative to pre-COVID-19 levels, with about 263,500 energy efficiency employees still out of work.

Federal funds could help close the gap, according to ACEEE. The infrastructure legislation passed last year includes $3.5 billion for low-income home weatherization, more than $1 billion for building energy codes, $7.5 billion for electric vehicle chargers, revolving loan funds for commercial building and home upgrades, and other programs.

There is also the potential for additional support from Congress. Biden's agenda includes another $1.8 trillion in potent climate and social spending, but the report notes its future is "uncertain amid ongoing negotiations in January 2022."

The U.S. Department of Energy (DOE) is considering strengthening energy efficiency standards for new manufactured housing, and comments on the proposal show a range of stakeholders — including some focused on utilities — have taken opposing positions on a key issue.

While states govern the building codes and efficiency standards for site-constructed homes, the federal government oversees manufactured housing. The Department of Housing and Urban Development set the most recent rules in 1994. Lawmakers in 2007 directed DOE to take on the task, but a final rule has not yet been published. 

DOE's latest proposal is based on the 2021 version of the International Energy Conservation Code (IECC), and experts say it would result in substantial energy savings over current requirements. The proposal's "tiered" approach would leave manufactured homes priced below $63,000 subject to less stringent requirements.

The manufactured housing industry and rural utilities filed comments warning that stricter efficiency rules could drive up home prices. The California Energy Commission (CEC) said in its comments, however, that a tiered approach is not strong enough and that weaker standards "threaten grid reliability, and will create avoidable greenhouse gas emissions."

Tiered approach causes rifts 

There are roughly 22 million U.S. residents living in about 6.8 million manufactured homes, making them a key piece of the nation's affordable housing stock. But current energy efficiency requirements are more than a quarter century old, and advocates say they leave residents — mostly low and middle income — to struggle with higher energy burdens.

DOE's proposal, a supplemental notice of proposed rulemaking published in August, would establish new requirements for manufactured homes that include building thermal envelope improvements, air sealing, and installation of insulation. It is these requirements, according to the proposed rule, that could vary depending on the price of the home under a tiered approach. Other requirements in the rule, including those related to duct sealing, heating, ventilation, air conditioning, and heating and cooling equipment sizing, would apply to all homes regardless of price.

A different tiered approach would apply some requirements based on the configuration of the home. DOE is also considering an alternative approach where efficiency requirements based on the 2021 IECC would be applied regardless of home price or configuration.

The comment period on DOE's proposal closed Nov. 26, and the tiered proposals have caused rifts between groups that are more often aligned.

The CEC in its comments urged DOE to adopt an "untiered” approach. "Permitting the unnecessary consumption of energy in manufactured housing under either 'tiered' approach will create additional strain on California’s electric grid, threaten grid reliability, and will create avoidable greenhouse gas emissions, which disproportionately affect frontline and low-income communities throughout California," CEC said.

"Manufactured homes fall outside of our building code jurisdiction ... so we really rely on the federal government to help us create the most robust, energy-efficient, cost-effective manufactured housing stock that we can," CEC Commissioner Andrew McAllister said in an interview.

The National Association of State Energy Officials (NASEO) also filed comments pressing DOE for stronger standards. It warned that establishing a two-tiered standard "that excludes the lowest cost homes from energy efficiency saddles those residents with high energy bills for the 30-40 year average lifetime of a manufactured home." 

CEC said the untiered approach "is more equitable because it significantly reduces the energy burden on low-income residents over the life of the home without having a demonstrable effect on the availability of affordable housing."

Other stakeholders say the question of affordability is not so clear.

Rural cooperative utilities oppose DOE's rule

"We appreciate DOE’s attempt to address price sensitivity through the set of 'tiered' standards," the National Rural Electric Cooperative Association (NRECA) said in its comments. "We support DOE efforts to improve the energy efficiency of manufactured housing."

But the group indicated that it does not support DOE's current proposal, on the whole. For many of NRECA's members, manufactured housing makes up 25% or more of the housing stock in their service territory, the group said.

"We are concerned the [proposal] does not adequately address the affordability concerns that price-sensitive consumers will face when considering purchasing a new manufactured home," NRECA said. "Ultimately, we fear that if the [proposal] is finalized as drafted the door to home ownership for these consumers may be shut and that opportunity lost for them."

NRECA declined to comment for this story beyond what it already filed with DOE.

High-efficiency heat pumps, installed before the home is delivered, are "the most effective way to both improve efficiency in manufactured homes and lead to lower electricity bills," NRECA said.

The Manufactured Housing Institute, a major trade association for the industry, filed comments saying DOE's proposal "will add significant costs to manufactured homes," and "any increase in construction costs, even modest increases in response to a new energy conservation standard, could jeopardize homeownership for hundreds of thousands of Americans."

CEC's McAllister, however, says the new rules ultimately will help residents save money.

Advocates say energy savings pay for themselves 

California has hundreds of thousands of manufactured homes in large rural areas, McAllister said, and a significant low-income population. Incremental increases to the cost of homes are "more than compensated by the savings on the energy bill," he said.

McAllister, who previously worked for NRECA, noted that California has a small cooperative utility footprint and said CEC's position is "not opposition to them. This sector is challenging from a lot of perspectives."  

The American Council for an Energy-Efficient Economy (ACEEE) and other conservation and advocacy groups say DOE's proposal doesn't go far enough.

“The department’s primary proposal would leave many low-income residents of manufactured homes with decades of high energy costs. The alternative proposal appears to be a better start, but the department needs to look at stronger options to reduce overall costs and emissions,”  Lowell Ungar, ACEEE's director of federal policy, said in a statement.

ACEEE says that under DOE's proposed alternative rule, where all homes meet higher standards, owners of new single-wide homes would see savings of $1,727 over 30 years, net of costs, while owners of multi-section homes would save $2,511 across the same period.

Kentucky-based Next Step works nationally with homebuyers to help them purchase Energy Star manufactured houses, which meet higher efficiency standards. Next Step President and CEO Stacey Epperson says it is "common sense" that putting new requirements on the homes will raise prices somewhat, but she stressed that the homes will still be affordable.

According to Next Step, last year the U.S. manufactured housing industry shipped 94,390 homes, of which 30% were certified as Energy Star.

The group filed comments advocating for a "single-tier standard that promotes equal access to energy efficiency." DOE's rulemaking "should not disproportionately impact residents of manufactured housing communities, persistent poverty regions, communities of color, and underserved rural areas," it said.

Next Step studied home mortgage data and the cost of DOE's improvements, and it concluded that manufactured homes "can serve low-income families across the country," Epperson said. "Can it serve everybody that wants a home? Probably not. But that's kind of like everything, right?"

As of 2020, about 65% of electricity meters across the United States had "smart" capabilities including integrated data processing and two-way communications, according to Guidehouse Senior Research Analyst Michael Kelly. The penetration of advanced metering infrastructure (AMI) has been steadily growing by about 4-5% annually since 2016, he said.

Utilities are headed towards about 90% AMI uptake by the end of the decade, though penetration varies by type, according to Guidehouse data. Cooperative utilities have about 78% smart meters on their systems, while investor-owned utilities sit around 65% and public power companies at 55%.

The growth in smart meters is helping utilities expand their load management programs. The smart meter installed base grew by 9.3% between 2017 and 2020, while the demand response customer base grew by 7.3% over the same period, said Kelly.

Smart meters are a foundational part of the energy transition and can help transform electric vehicle (EV) and building electrification efforts into flexible grid resources. Tens of millions of older meters remain on the grid, and the full transition will take more than a decade, but Kelly said progress on replacing them has been steady for years.

"The only kind of barrier would be on the regulatory side," said Kelly. And increasingly, regulators are seeing the value of AMI, he added.

Kentucky regulators in 2018 rejected proposals by Kentucky Utilities and Louisville Gas & Electric to install AMI across their territories, but reversed course and approved plans in June for more than 900,000 smart electric meters. In New Jersey, Public Service Electric & Gas got approval in January to install 2.3 million smart meters. New Mexico is now considering grid modernization applications at the direction of lawmakers.

Getting regulators on board requires educating them on the range of benefits that smart meters can provide, Kelly said. But for utilities, accessing the benefits will require more than deployment, he added.

Kelly co-authored a white paper commissioned by software company Grid4C that concluded "the full value proposition behind smart meter deployments has yet to be fully realized. Immediate benefits around workforce optimization, billing accuracy, and outage detection represent the tip of the iceberg in potential value creation."

"The disconnect stems from an underutilization of smart meter data and an underinvestment in smart meter analytics," Kelly wrote.

Rather than collecting meter readings every five or 15 minutes, new meters can record usage data at sub-second intervals, Kelly said. That opens up a lot of potential — while also introducing complexity for utilities.

"Do you have the communications bandwidth to send hundreds of thousands of data points? Probably not," Kelly said. A new wave of AMI solves that problem by moving the analytics and storage onto the meter itself, he said.

"More granular collection intervals ... opens up a whole new set of applications around the power quality, which smart meters have never been able to do before," he said.

Utilities are taking advantage of the growing number of smart meters on their systems, according to data from the Federal Energy Regulatory Commission. The agency's 2021 Assessment of Demand Response and Advanced Metering shows that from 2018 to 2019 enrollment in retail incentive-based demand response programs increased by 1.1 million customers, and enrollment in retail dynamic pricing programs increased by 1.7 million customers. The enrollments represent annual percentage increases of 12% and 19%, respectively, according to the report published this month.

"That’s a good sign that more utilities are starting and/or growing DR programs," Guidehouse Research Director Brett Feldman said in an email.

Part of the increase in retail dynamic pricing programs coincides with the California Public Utilities Commission's 2015 decision "requiring utilities to transition customers to default time-of-use rates beginning in 2018 and 2019," FERC noted in the report. 

There is not a lot of dynamic pricing uptake outside of California, said Feldman, "but some utilities are still trying pilots to find models that work for customers, especially as solar, storage, and EVs grow."

The report found from 2019 to 2020 demand resource totals in wholesale markets decreased by approximately 4% to a total of 30,787 MW.  But despite the nationwide decrease in demand resources, FERC also concluded "wholesale demand resource potential to meet peak loads increased" across the same period due to lower peak demand in 2020.

"The decreased load is due to a combination of Covid and a general trend of flattening and decreasing loads due to greater energy efficiency," Feldman said. "However, that trend is reversing with more electric vehicles and electrification of heating in buildings."