Customer Engagement/Service/Behavioral Energy Efficiency/DSM

An Aug. 30 Request for Information, or RFI, from the U.S. Department of Energy on how best to use $3 billion in infrastructure bill smart grid funding is raising expectations among energy management services providers about a new round of smart meter deployments by utilities across the country.

It is also raising questions about unrealized benefits from 2009’s taxpayer- and ratepayer-funded billion-dollar American Recovery and Reinvestment Act, or ARRA, smart meter investment.

By the end of 2022, there will be over 124 million smart meters installed in 78% of U.S. households, according to data released in April by the Edison Foundation’s Institute for Electric Innovation. But less than 3% of today’s smart meters fulfill 2009 promises of customer savings and that must be prevented in the coming Energy Department-funded deployment, according to a September analysis by Mission:data Coalition.

“Utilities used federal and state funds to deploy smart meters and many explicitly promised to empower customers” to lower bills and earn rewards for supporting system peak demand reductions, said Mission:data President and analysis lead author Michael Murray. “The public policy failure is that utilities benefited from returns on capital expenditures and reduced operational costs but did not deliver those customer benefits,” he said.

There are reasons customer benefits have been limited, utilities said.

“Our web portal allows customers access to historic data and helps them take the steps to obtain near real-time data,” said Fort Collins Utilities Energy Services Manager and Policy Advisor John Phelan. But that “is an impractical, time-consuming process and customers lose interest in it after a few weeks,” he said.

Utilities can streamline real-time data access to enable greater customer and system benefits with “non-discriminatory” and “interoperability” standards, Murray and other smart meter advocates said. But that may compromise concerns of customers and regulators about system security and customer privacy protections, utilities said.

Big potential value

Smart meters are “a key technology” that facilitate “new and expanded services,” an April 2021 Edison Foundation report recognized. They can lead to “smart home energy management, load control, budget billing, usage alerts, outage notifications, and time-varying pricing” as well as improved visibility for system operators, it added.

In California, where regulators require utilities to enable some access to smart meter data, its value was demonstrated during nine system operator alerts for customer usage reduction in early September.

Energy manager OhmConnect’s California customers earned “over $2.7 million,” for reducing dispatch 1.5 GWh during those nine days, its CEO and founder Cisco DeVries said. And Google Nest smart thermostats “reduced usage 72 MW,” Google Nest Head of Energy Partnerships Hannah Bascom reported.

But inadequate real-time data was exchanged between California’s market operator and the state’s many distributed resources, and significant potential capacity was depleted before the most challenging evening peak demand spike, reducing the system benefit the state could have obtained, according to a Bloomberg Sept. 7 report.

Real-time data from smart meters on customer usage is “critically important” to optimizing distributed resources to deliver customer and system reductions, said a June 24 letter to the New York State Public Service Commission, or NYPSC, from advocacy groups. But as in many states, New York customers currently need “expensive and duplicative” equipment to obtain real-time data, the letter said.

Utilities are effectively using granular smart meter data to obtain meter billing data and reduce operational expenses for customer services, but access for customers and third-party energy management services is difficult and costly, DeVries, Murray and others said.

The problem

Almost 17.4 million ARRA-funded smart meters have been deployed by utilities since the 2009 Energy Department funding by 77 representative investor-owned utilities — 89.7% with real-time data access capability — but only 2.9% were “enabled” by utilities, Mission:data reported. And historical data was accessible in only 14.3%, it added.

Two steps are needed for customer access to real-time smart meter data. Customers first must install a Zigbee or other type of network solution that communicates with the meter. They must then authenticate their identity through the utility and, if they choose, authorize access for a third-party energy management service.   

Energy management providers can install their own metering equipment but “electrical rewiring makes it expensive and impractical in 99% of homes,” Mission:data’s Murray said. “The real question is whether smart meters should benefit utilities, customers, or both,” he added.

Smart Energy Consumer Collaborative surveys verify customer “disgruntlement” with utility processes that make data sharing difficult, SECC President and CEO Nathan Shannon said.

“About two-thirds of consumers” would share their electricity usage information with third parties to reduce their bills if the process was more accessible for them, he added. But 93% of surveyed customers also expect utilities to protect their data, which utilities say is a major impediment to enabling that access, SECC found.

Third parties are “begging” utilities to enable customers and energy management providers to fulfill promises of benefits, “but utilities have many excuses,” Murray said.

But the difficulties customers have accessing their data, especially real-time data, are not excuses but power system realities, utilities responded.

Utility realities

Utilities recognize the potential of smart meters to empower customers to better manage their usage, but they are “regulated entities” and “must work closely with their state commissions to manage both customer privacy issues and cybersecurity threats,” Edison Foundation Institute for Electric Innovation Executive Director Adam Cooper emailed.

Utility websites do allow customers to “readily view” historic usage and some enable sharing with third parties, Cooper added. 

In New York, though, Consolidated Edison “has declined to enable real-time functionality” and Avangrid and National Grid have not yet reported when they will make it available, the joint advocates’ June 24 letter to the NYPSC said.

Customer access to real-time smart meter data will follow “physical deployment,” expected to begin in Q4 2022,  and will be completed in 2026, Avangrid spokesperson Kelly Packard responded, citing Avangrid NYPSC filings.

But enabling smart meter data access for customers and third parties “raises cybersecurity concerns” and faces “technical constraints,” said Consolidated Edison spokesperson Allan Drury. It would also “be expensive and provide little value added” to data currently available through ConEd’s web portal, he added.

Michigan’s DTE Energy makes real-time data access available, but customers can only use equipment from the utility’s affiliate and must pay $1.99/month, Mission:data reported.

The per month equipment “rental fee” to DTE’s affiliate allows customers access to real-time usage data through the utility website, said DTE Energy Spokesperson Brynn Guster. “Customers are empowered to see their usage through other ways without a fee,” but that could introduce authorization issues and other complications because customers must do it “safely,” she added.

“The whole purpose of smart meters was to empower customers,” Southern California Edison spokesperson David Song acknowledged. But customer and third-party access requires “precautions” to safeguard customer data and privacy, he added.

Only Colorado’s Fort Collins Utilities, or FCU, was identified by the Mission:data research as providing a viable process without a charge for both real-time and historic data usage access, Murray said.

With current technologies and privacy and security concerns, “real-time is a rabbit hole” and “we don't promote it,” responded FCU’s Phelan. Historic data is available through FCU’s web portal, and the utility recognizes customers right to their real time data, he said.

With two-factor authentication and added equipment, customers can access real-time data and authorize sharing it with third parties, he added. “But they often get bored” and “do not share the data,” he said.

“Smart meter software was not designed to share data with individual consumers,” Holy Cross Energy President and CEO Bryan Hannegan said. “Customers should have access to it, but no commission or board would allow the potential security risk” of access to “the utility’s cash register” without protections, he added.

HCE’s aggressive development of distributed resources might soon make dynamic price signals more important for system peak demand management, which is why it is building “a fiber optic distribution network,” Hannegan said. When utilities like HCE need customer or third-party responses in real-time, they may prefer to use their own smart networks, he said.

But because that network could make real-time smart meter data easier for customers to access, HCE has also consulted with third-party energy management services, said Hannegan, a former Energy Department researcher. Third parties can “absolutely” support customers in providing the system with valuable demand flexibility, “if there is a value proposition" for them and the utility, he acknowledged.

California’s experience shows customer access to real-time data does not compromise privacy or security, Mission:data’s Murray insisted. Utilities’ excuses “hide concern with revenue losses from lower kWh sales,” an intent to avoid “liability and customer support burdens,” or “competition from third parties for services they may eventually offer,” he said.

Energy management service providers disagreed about Murray’s assertions.

Energy managers differ

Some third-party energy managers work with utilities and others do not.

Enrollment with OhmConnect starts with the simple entry of the customer’s utilty and zip code at its website, but it gets complicated when the customer clicks through to the utility website, DeVries said. Some 60% of its enrollees become lost because they must provide the utility with detailed identifying information and go through an online or written authorization process to allow OhmConnect access, he said.

“There are legitimate privacy and security issues,” but “if utilities simplify the process, the one in six U.S. customers behind in today’s utility bill affordability crisis can get important bill savings,” he said. OhmConnect customers in Texas “have reduced their energy bills up to 20%,” and California customers “earned $2.7 million” in September, he added.

Data is “the gateway to the clean energy transition with a trillion-dollar power sector benefit,” and “utilities blocking access to it is nearly criminal bad faith,” DeVries insisted. Utilities must learn to work with customers and third-party energy management services because “it is not their data,” he said.

Bidgely “is an energy management solution provider to utilities” that helps utility customers reduce their bills, said Bidgely CEO Abhay Gupta. Direct third-party energy management for customers, instead of working through the utility, “has not proven a scalable business model, and utilities cannot make it viable, because the problem is consumers’ lack of interest” and the technical difficulties and costs, he added.

“Making the consumer experience better has always been challenging,” agreed Plugged-In Strategies President and consultant Chris Villarreal, a former staffer at the California and Minnesota utility commissions. But “utilities can make access to data easier,” he said.

If utilities prioritize their uses ahead of consumer and authorized third party access, “that may be leveraging monopoly power at the expense of the competitive market,” Villarreal added.

Given past abuses of data in other industries, “utilities are justifiably worried about privacy and security, but there are potential solutions,” said Seth Frader-Thompson, CEO of energy management software provider Energy Hub.

One solution is an “independent statewide data platform manager that calculates and reports performance,” he said. Another is “allowing limited access to utility data, with guardrails to prevent a breach of customer confidentiality,” he added.

Such solutions may soon receive consideration by the Energy Department.

For the new deployment

Responses to the Energy Department RFI will inform use of funding from the 2021 Infrastructure Investment and Jobs Act, “a once-in-a-generation” modernization of the power system, the RFI said. An approximately $3 billion investment through 2026 will go into the three topic areas of the Grid Resilience and Innovation Partnerships program.

DOE is seeking ways its competitive grants can fund innovative technologies and strategies for preventing outages and enhancing reliability and resilience, as well as advancing system flexibility, the RFI said. A $3 billion Smart Grid Investment Grant Program, part of the $10.5 billion in infrastructure bill funding for power system advances, includes a special focus on technologies to aggregate and integrate technologies like smart meters.

Grants will go to projects that “support data standards, interoperability, and non-discriminatory data access on a real-time basis,” the RFI said. Federal funds will cover no more than 50% of total project costs up to a $30 million federal share, it added. Stakeholder responses to the RFI are due Oct. 14.

“The key phrase in the RFI is ‘non-discriminatory access to real-time data’ because it suggests DOE is learning from its mistakes,” Mission:data’s Murray said. If it remains in the final funding opportunity announcement, it would make it “discriminatory” for utilities to obstruct access to data, and “non-compliance would put utilities in breach of contract,” he said.

DTE and Avangrid declined to offer recommendations for the Energy Department RFI.

New competitive market opportunities for customer benefits “were not realized in the first smart meter deployment,” recalled Plugged-In Strategies’ Villarreal. “The new investment should ensure that open standards, interoperability, and open access are prioritized and that failure to deliver them is enforced,” he added.

“The new billion-dollar ratepayer and federal investment in the next generation of smart meters must enable better outcomes for customers,” DeVries added. “Maybe customers will use them, or maybe they won't, but that is not a utility decision, it is the customer’s.”

The California Energy Commission on Oct. 12 adopted new load management standards requiring utilities to develop retail electricity rates that “change at least hourly” to reflect grid costs and greenhouse gas emissions.

“This update is a huge leap into the 21st century, using digital approaches to unlock benefits for consumers by enabling them to automate their electricity use around cheaper rates and changing grid conditions,” CEC Commissioner Andrew McAllister said in a statement.

Automated load management can help utilities lower bills, more efficiently use renewable energy resources and boost grid reliability, McAllister said.

The CEC said the new load management standards are expected to produce $243 million in net benefits over 15 years and could reduce annual peak hour electricity use by 120 GWh.

The standards take effect in April, and will impact Pacific Gas and Electric, Southern California Edison, Sacramento Municipal Utility District, San Diego Gas & Electric, Los Angeles Water and Power and large community choice aggregators.

The new standards will help disadvantaged communities, the CEC said, by “introducing fairer compensation mechanisms, creating bill savings for customers with flat loads in disadvantaged communities or who are able to shift usage to when electricity is cheaper and lowering energy costs for all customers by reducing peak electricity demand.” 

Along with developing new retail electricity rates, utilities will be required to provide information to a central repository for rate information called the Market Informed Demand Automation Server. They will also be requred to “educate customers about time-dependent rates and automation technologies to encourage their use,” the CEC said.

California regulators have approved the nation’s first vehicle-to-grid export rate for commercial electric vehicle fleets and chargers connected to energy storage, PG&E and the Vehicle-Grid Integration Council announced last week. Upfront incentives that will be provided by PG&E and payments for exported power under this rate mechanism are expected to advance the adoption of EVs by helping offset the cost of electric buses and commercial customers' fleets.

Two-way vehicle chargers with storage, electric buses and EV fleets are the focus of this new real-time pricing three-year pilot, which can be extended by state regulators. The pilot seeks power discharges during times of peak demand and for backup power during outages, the utility said in an Oct. 26 statement.

The utility’s territory is home to the largest EV market in the U.S., representing about one in every six EVs sold nationally. As many as 2 million electric vehicles in PG&E’s region could both charge from the grid and discharge into it to provide needed reliability, the company said.

The California Public Utilities Commission approved Oct. 20 a settlement among PG&E, the Vehicle-Grid Integration Council, or VGIC, Electrify America and the CPUC’s Public Advocates Office that sets a compensation mechanism for commercial electric fleets and bidirectional chargers supported by energy storage that provide grid reliability. 

“The CPUC’s decision is a strong step forward for Californians and in support of the state’s grid, implementing the nation’s first dynamic export rate for EV charging customers,” Ed Burgess, VGIC policy director, said in a statement. “As ever-greater numbers of EVs hit the roads, this innovative rate option will allow EV owners to further benefit from their investment in clean transportation.”

The novel rate is to be implemented “as soon as practical” but no later than Oct. 1, 2023, the agreement states. PG&E is working on a launch date, said utility spokesperson Mike Gazda.

 Participating customers will be compensated “for exports based on day-ahead hourly pricing,” said VGIC spokesperson Todd Zeranski. To encourage enrollment in the first 12 months, incentives will be offered to school buses and larger vehicles and be based on the equipment’s size. EVs and chargers able to discharge up to 100 kW are eligible for $1,800 with electric buses getting $3,150 in incentives. Those with larger batteries can reap $3,750, with an adder for large electric buses and the incentive totaling $6,560.

Analysts say fleet electrification is poised for significant growth, and school buses in particular offer opportunities for grid management because of their large battery sizes and predictable schedules.

In mid-October, a project was announced in PG&E’s territory that will connect electric buses to a branch of the Oakland Public Library. The buses are to provide up to six hours of power when the library serves as an emergency shelter.

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. 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.”

Duke Energy has proposed an electric vehicle (EV) charging program that could allow some residential customers in North Carolina to charge a vehicle for a fixed monthly fee as low as $19.99. In exchange, the customer would allow Duke to manage the vehicle's charging, in order to avoid grid stress and higher costs.

The utility is trying to provide a "seamless customer experience and an ecosystem of EV products," while also avoiding costly grid upgrades necessary to meet rising peak demand, Duke Vice President of Rate Design and Strategic Solutions Lon Huber said.

The proposed pilot is "all you can charge," said Huber, though some limitations apply. 

Customers who consume more than 800 kWh for charging in a month, or opt out of several managed charging events during which charging may be paused, could receive warnings and be removed from the pilot. According to Duke, that amount of energy will get a typical EV close to 2,000 miles of range. But clean energy advocates say the program limits are an indication that subscription-based managed charging plans may not work for all customers.

Duke is moving rapidly to implement its electrification plans, and has asked the North Carolina Utilities Commission (NCUC) to approve the charging pilot within 60 days. Electric transportation is expected to be one of the most significant drivers of Duke's load growth over the next 20 years, the utility told regulators, and managed charging is a key to controlling costs.

Regulators have been amenable to Duke's plans so far, which support North Carolina's broader electrification strategy. In January, North Carolina Gov. Roy Cooper, D, issued an executive order calling for zero-emission vehicles to comprise 50% of in-state automobile sales by 2030.

Last week, the NCUC approved Duke's proposed Make Ready Credit, which will allow the utility to compensate customers who install EV charging at homes or businesses. And regulators have asked for comments on how the utility can access federal infrastructure funds to assist with its transportation electrification plans. 

As customers transition from traditional gas-powered cars to EVs, utilities must be thinking about "how to make this a frictionless experience," Huber said, and "accentuating the benefits of electrifying transportation."

The proposed $600,000 subscription EV charging pilot would run 12 months and include an initial 200 participants split evenly between two service territories, according to Duke's application. As part of the pilot, Duke will "actively manage" vehicle charging and can schedule up to three managed charging events per month.    

Duke Energy Carolinas (DEC) customers would pay a fixed monthly rate of $19.99 for the charging pilot, while Duke Energy Progress (DEP) customers would pay $24.99. "Historical cost structures" of the two utilities account for the difference, said Huber. Participating customers can save on charging, he said, while the pilot's load management aspects are designed to benefit all of Duke's customers.

Managed charging key to limiting cost increases 

EV load is expected to grow as Duke is transitioning to a lower-carbon portfolio, which "will cause increases in the proportion of capacity or demand costs," the utility said in its application. That's due, in part, to renewable energy typically having higher capacity costs and lower energy costs.

Demand costs account for roughly 59% of DEC's revenue requirement and 49% for DEP, according to Duke's application.

"Because demand costs correspond to system peaks and charging an EV adds demand to the system, costs will be primarily driven by peaks on the generation, transmission, and distribution systems rather than energy costs," the utility warned regulators.

Unmanaged EV charging that occurs during or near the coincident peak could mean Duke "will need to build or obtain additional capacity resources to avoid power interruptions or damage to the system," the utility said. "This could result in increased costs for all customers."

On the other hand, if EV charging is managed effectively Duke said it will be able to "delay or avoid adding additional capacity resources" and reduce costs in both the short- and long-term. System assets will also be used more efficiently, "and these savings will be shared among both EV drivers and non-EV drivers."

Duke said it is working with BMW, Ford Motor, General Motors and American Honda Motors, testing an Open Vehicle Grid Integration Platform developed with the Electric Power Research Institute that provides interoperability with the automakers' vehicle telematics applications. That would allow Duke to use charging data from the vehicle to measure a customer's usage and demand, rather than require installation of an expensive second meter.  

"The beauty is that you don't need a second meter — at least, that's our going-in assumption," said Huber. "We're going to be testing out the accuracy of the telematics. 

Active charging will allow Duke to "shape the EV charging patterns to ensure charging occurs during low cost, environmentally friendly periods, and that adequate charge levels will be reached by a designated time set by the customer," the utility said.

Some restrictions apply 

Duke will be able to pause a customer's charging for up to four hours, three times per month. Participants will receive twelve hours advance notice that a managed charging event will occur, and can opt out of two such demand response events throughout the pilot.

"Any participant who opts out of more than two managed charging events may be removed from the pilot at the companies’ discretion," according to Duke's application. 

There are other limitations on the program, and they indicate subscription charging may not work for everyone, said Stan Cross, electric transportation policy director for the Southern Alliance for Clean Energy.

Duke may also send warnings to a participant using more than 800 kWh/month for EV charging "that they have consumed a potentially excessive amount of energy for one vehicle" and could be removed from the pilot.

Participants who receive three warnings can be removed at Duke's discretion. And any participant consuming more than 1,200 kWh in any month "may also be removed from the pilot immediately at the company’s discretion," according to Duke's application.

"We are big fans of managed charging and are excited that Duke is looking to innovate," Cross said. "We have concerns about subscription-based tariffs. EV efficiency and customer needs vary greatly. So a flat rate might not be an appropriate way to base a managed charging program."

One issue, said Cross, is that managed charging programs are new in general, and in particular when paired with EV charging. "We want to be really careful ... that we're really controlling the variables and making sure that we're testing for the right things," he said.