While smart meter deployments are slowing in the U.S., demand response is rising, both at the retail level where it is managed by utilities and at the wholesale level where it is procured in organized markets.
And it is changing, with utilities increasingly harnessing distributed energy resources to manage their loads more effectively.
More broadly, utilities are using a variety of new resources and connected devices to balance the grid and meet demand, drawing on everything from smart thermostats to large-scale batteries.
This trendline looks at significant developments in energy efficiency and demand side management, including impacts from the COVID-19 pandemic and California's efforts to avoid more weather-induced power outages.
'Reports of energy efficiency's death are greatly exaggerated.' The cost keeps falling as the resource grows
Energy efficiency can be the least-cost resource in a procurement, and it is increasingly helping utilities select and optimize clean energy portfolios, experts say.
By: Robert Walton• Published June 23, 2021
The cost of energy efficiency continues to decline, and the opportunities continue to increase. The implications are enormous for utility systems, say experts.
"There will be places where another clean energy resource might be the cheapest option, but in general, energy efficiency outcompetes all the major fossil fuels," said Rachel Gold, head of the utilities program at the American Council for an Energy-Efficient Economy (ACEEE).
And the increasing inclusion of efficiency in clean energy portfolios can help eliminate the need for new gas plants, said Gold.
In a new analysis released Wednesday, ACEEE finds the levelized program cost of saved energy was $0.024/kWh in program year 2018, about a 15% decline from the 2015 program year. The group issues this report every three years.
Comparing efficiency with unsubsidized supply options, ACEEE found efficiency is potentially the lowest-cost resource. The report examined data from the 52 largest investor-owned utilities by sales volume.
Costs for efficiency range from $12 to $49/MWh, compared with $44 to $73/MWh for combined cycle gas generation (CCGT), $26 to $54/MWh for wind and $29 to $42/MWh for solar.
"Utility energy efficiency programs continue to be extremely cost effective," the report concludes. And those programs make up a growing portion of utility resource needs, supplying about 18% now and potentially becoming the United States' largest electricity resource by 2030, according to ACEEE.
That means that as U.S. power demand grows, much of that can be met through conservation. And efficiency is taking on a growing role in utility clean energy portfolios.
"There are at least a dozen utilities or states taking some action to move towards a more robust treatment of clean energy resources in planning," said Gold. "It's a bit of a mix, and the drivers are different from state to state, but there is definitely a trend."
Efficiency isn't going anywhere
Some believe that energy efficiency programs will eventually run out of so-called low-hanging fruit: easy, cost-effective projects that save energy. Lighting is the typical example, where the switch to LEDs has saved consumers billions, but now most less-efficient bulbs have been replaced.
But experts say fears of running out of efficiency appear unfounded.
"So far, energy efficiency is a renewable resource," said Gold. "We're 40 years into energy efficiency, and we continue to get this question every few years."
"I think that the reports of energy efficiency's death are greatly exaggerated," RMI principal Mark Dyson said in an email. He pointed to a 2018 paper from the firm arguing that efficiency potential is growing rather than shrinking.
Modern energy efficiency is "an expanding-quantity, declining-cost resource," RMI co-founder Amory Lovins wrote in that analysis. Adoption of efficiency as a resource "is constrained by major but correctable market failures and increasingly motivated by positive externalities."
Efficiency as part of a clean energy portfolio
Growing research shows that clean energy portfolios — including efficiency, renewables, demand management and storage — can undercut the price of any other resources.
A 2019 report from RMI found an optimized mix of those resources was likely to undercut the operating costs of over 90% of proposed new combined-cycle capacity by 2035, "creating stranded asset risk for investors."
"Our most up-to-date analysis suggests that most proposed CCGT capacity, if built, will be undercut by clean energy costs well before 2035," Dyson said. "This has stayed true even as gas price forecasts have fallen since our report in 2019 — those gas price declines have been offset by clean energy resources continuing to fall in price."
"Those portfolios have the capability to avoid almost all of the new gas being considered around the country," said Gold. But, she added, "we're not yet seeing a lot of utilities do that work to try and optimize resources and avoid fossil fuels."
"We see clearly that nonutility investors, who do not enjoy allowed cost recovery through regulated rates, are turning quickly away from new gas plant investment," Dyson said. "Regulated utilities have been slower to turn away from new gas investment, but they and their regulators are starting to follow the same trend."
South Carolina regulators on Thursday rejected Duke Energy's integrated resource plan, which contained several different proposals for meeting long-term demand, including development of new gas-fired plants. Dyson said the South Carolina decision "is a great example of that trend making its way into PUC decisions around the country."
"Regulators are increasingly aware of and concerned by the stranded asset risk posed by new gas plant investment," he said.
Efficiency values beyond cost
While the saved kilowatt can be cheapest, that is not always the case, and ACEEE's report is a reminder that utilities implement efficiency programs for a variety of reasons.
The report notes low-income efficiency programs "are pursued for customer equity objectives rather than least-cost resource planning," and they have a higher cost of saved energy than other programs. ACEEE found the levelized program cost of saved energy in 2018, when low- and moderate-income programs were excluded, dropped to $0.021/kWh.
"However, even considering the higher costs of low-income programs, the aggregate cost of saved energy remains comparable to the least-cost generation resources available to grid planners," the report added. "A purely cost-based analysis does not capture the full benefits of efficiency."
The value of efficiency also fluctuates "depending on what system planners are solving for," said Gold. Energy efficiency can be used for peak demand reduction, to address ramping periods, grid resilience, maintenance deferral and to lower operating costs. Ultimately, the report recommended investor-owned utilities work to expand their efficiency portfolios.
"Although the costs of renewable generation have fallen dramatically over the last decade to become some of the most affordable sources of energy available on the grid today, the low cost of energy efficiency proves that it should be an essential part of any least-cost infrastructure plan," ACEEE found.
Equity, security and load: FERC conference considers the challenges and potential of electrification
U.S. electricity load could double by 2050. The industry is focused on how to meet that need equitably and securely, panelists at a recent technical conference said.
By: Robert Walton• Published May 3, 2021
The electrification of transportation, heating and other end uses necessary for the United States to meet its decarbonization goals will require the country to double its electricity load by 2050, panelists said Thursday at a Federal Energy Regulatory Commission technical conference. With that additional load will come opportunities, responsibilities and challenges, they said.
The panelists frequently acknowledged the need to consider issues of equity, affordability and environmental justice throughout the energy transition. "If we don't address those issues, what are we doing? We're not accomplishing anything," said FERC Chairman Richard Glick.
They also raised cybersecurity concerns. It will be a constant battle to secure the grid, said Carlos Casablanca, managing director of distribution planning and analysis at American Electric Power Service Corp. But he added that AEP "does not believe that these risks are brought upon by electrification efforts alone, as these risks already exist in our industry and we actively manage them."
Commissioners also took the opportunity to voice some of their own concerns.
Commissioner Neil Chatterjee acknowledged that FERC is "not really in the driver's seat on electrification," but the commission has to understand how it will impact the wholesale markets it does oversee. State and federal policymakers are unleashing new electricity demand, and "we must make sure at every turn we send clear and consistent signals to the industry and investment community," he said.
"Mixed signals will delay the development at a time when we should be looking toward the grid of the future," Chatterjee said. But he added that reliability and the creation of efficiency through competition must remain FERC's focus.
Commissioner Allison Clements said she is focused on ensuring customer benefits do not get lost in the cracks between different regulatory jurisdictions. She wants regulators to consider "how we should think about costs and benefits of new investment across the systems," she said, from transmission development to utility meters.
"Our regulatory structures don't easily provide for optimization of benefits that all of those investments bring and the related savings for customers," said Clements. "Without that optimization, customers are left in less than optimal positions."
Utility loads could double by 2050
Just how much electricity load will increase between now and 2050 is uncertain, but many estimates indicate doubling is possible.
Jeff Dennis, managing director and general counsel of Advanced Energy Economy, pointed to a Brattle Group study which found that New England loads were likely to double across that time.
"Electrification will result in significant increases in electricity demand and the generation capacity needed to meet that demand," Dennis said, though "the pace of electrification and amount of energy required for building heating and other uses may vary by region."
Washington will need to "roughly double its electricity supplies," said Glenn Blackmon, manager of the Energy Policy Office in that state's Department of Commerce.
"Our hope is to draw those resources from multiple locations and energy sources across the West, capturing the advantages that different areas of our country have in producing electricity from renewable energy," Blackmon said. "This approach will not only minimize costs but also improve the reliability of our electricity portfolio."
The Electrification Futures Study, developed by the National Renewable Energy Laboratory and other research partners, concluded that "meeting electrified loads requires a doubling of generation capacity in all regions by 2050," Ella Zhou, senior modeling engineer at the lab, told the FERC conference.
The study shows that electrification has the potential to change how utilities operate, Zhou said. Most utilities now see peak electricity demand in the summer, for cooling, but that could shift as more heating loads are powered by the grid. "Participation in the planning and operations of the power system is crucial," she said.
As more energy loads are shifted to electricity, it is "incredibly important" to remember that low-income groups spend a greater portion of their income on energy and have a higher "energy burden," said Rob Chapman, senior vice president of energy delivery and customer solutions at the Electric Power Research Institute.
"Obviously electrification has the opportunity from an air quality and health perspective to help support those communities," Chapman said. "The flip of that is, we have to consciously think about the affordability aspect and realize many disadvantaged communities are not going to have the capital to invest in emerging technologies."
Energy efficiency efforts can help address some the energy burden inequities, Chapman said. And environmental justice efforts must also look at the impact of transit corridors and public transit on disadvantaged communities, he said.
"As we seek to ensure that underserved communities have access to clean energy, we must be intentional and specific in identifying solutions and programs and involve communities in determining their path forward," said Katherine Hamilton, co-chair of the World Economic Forum’s Global Future Council on Clean Electrification.
Hamilton said the solution to "transition these communities that have been harmed by fossil fuels" includes reducing barriers to entry for energy technologies and markets. That could mean making resource interconnections cheaper, allowing aggregation of resources and co-optimization of efficiency efforts, such as installing heat pumps at the same time other upgrades are made.
All of these efforts include "making sure we lower the barriers to entry and make sure cost-effective, cheaper and more resilient solutions are available to customers who normally couldn't afford them," Hamilton said.
The electrification of demand and the growing interconnectedness of the grid has created new opportunities for disruption by hackers, the panelists acknowledged. But the industry remains confident this is a risk it can manage.
"As more electric systems 'go digital' or some non-electric products become electric, it is expected that the internet of things will only continue to grow, increasing the potential number of points for cyber intrusion," Casablanca said. "Continued cyber security technology development, collaboration, education and investment across all sectors of industry will be required to continuously mitigate this known risk."
But Casablanca also said the industry is already managing the risk daily, so electrification does not change the fundamental issue.
The industry must address cyber risks in a proactive and forward-looking way, said Chapman, because bad actors are only getting more sophisticated.
"I would suggest right now we have very good efforts underway, in terms of managing cybersecurity, but of course the bad actors always seem to be one step ahead of where we are going as an industry," Chapman said. "That risk only increases, from a resiliency and reliability perspective, as we drive more of our consumers to use electricity as an end use fuel of choice."
'A total mindshift': Utilities replace gas peakers, 'old school' demand response with flexible DERs
Utility-customer cooperation can balance renewables' variability with flexibility without using "blunt" demand response or natural gas.
By: Herman K. Trabish• Published March 8, 2021
Utilities and their customers are learning how their cooperation can provide mutual benefits by using the flexibility of distributed energy resources (DER) to cost-effectively balance the dynamics of the new power system.
The future is in utilities investing in technologies to manage the growth of customer-owned DER and customers offering their DER as grid services, advocates for utilities and DER told a Jan. 25-28 conference on load flexibility strategies. And there is an emerging pattern of cooperation between utilities and customers based on the shared value they can obtain from reduced peak demand and system infrastructure costs, speakers said.
"The utility of the future will use flexible DER to manage system peak, bid into wholesale markets, and defer distribution system upgrades," said Seth Frader-Thompson, president of leading DER management services provider EnergyHub. "The challenge is in providing the right incentives to utilities for using DER flexibility and adequate compensation to customers for building it."
Customers need to know the investments will pay off, according to flexibility advocates. And utilities must overcome longstanding distrust of DER reliability to take on the investments needed to grow and manage things like distributed solar and storage and electric vehicle (EV) charging, they added.
"It will require a total mind shift by utilities away from old school demand response," said Enbala Vice President of Industry Solutions Eric Young. "Many utility executives have never envisioned a system where thousands of assets can be controlled fast enought to ensure they get the needed response."
Customer demand for DER and utilities' need for flexibility to manage their increasingly variable load and supply are rapidly driving utilities toward cooperation, conference representatives for both agreed. And though technology, policy and market entry barriers remain, an understanding of how new technologies make flexible resources reliable and cost-effective is emerging.
All about flexibility
Natural gas peaker plants have long provided supply-side flexibility for power systems, but increasingly cost-competitive DER can provide demand- and supply-side flexibility, conference speakers said. Data on natural gas plant performance in California's August 2020 blackouts was no better than "solar-plus-storage, demand response, and other DER," stakeholders told California regulators Jan. 28.
The final total on 2020 investment in DER-based power system flexibility is expected to reach $386.6 million in North America and to be over $2.3 billion by 2029, according to a Q3 2020 Guidehouse/Energy Hub Insights white paper. The Guidehouse insights were widely affirmed by conference speakers.
DER investment is now and will "remain highest in the residential sectors" but will grow in the commercial-industrial sector, Guidehouse said. That investment, led by distributed solar and storage, EV infrastructure, and home energy management system expenditures, will add 387 GW of DER capacity by 2025, according to Wood Mackenzie's June 2020 report.
In the near term, the COVID pandemic and its recession will impact DER, with annual DER capacity additions falling by 61% in 2020, Wood Mackenzie projected last June. But Order 2222 from the Federal Energy Regulatory Commission (FERC), which requires system operators to develop tariffs and rules for aggregated DER in wholesale markets, will likely be a key DER growth driver by the mid-2020s.
Investments will be driven by utility "bring your own device" programs and by aggregating customer assets as non-wires alternatives, Guidehouse said. Using them to reduce peak demand and defer distribution system upgrades will require utilities to engage customers and improve control room visibility and management of customer-owned assets.
Improved distribution system load visibility and system management technologies like distributed energy resource management systems (DERMS) can integrate DER into system operations and planning.
Utility incentives like rebates and bill credits for DER adoption can engage customers and drive growth if they justify customer costs for things like smart thermostats, distributed solar and storage, and EV chargers, Guidehouse said. Cost savings and customer satisfaction from helping the environment must also be sufficient to justify any inconveniences to customers from allowing utility management.
"From 2017 to 2020, EnergyHub doubled the utilities we work with to over 50, and increased the total number of thermostats we manage by 120% from 2019 to 2020." Frader-Thompson said. The "majority" of its 1,800 MW of flexible resources is from DER like smart thermostats, EV chargers, solar with batteries and smart inverters, and grid interactive water heaters.
Now, utilities like Southern California Edison, Eversource, National Grid and Baltimore Gas and Electric are already planning for and working with DER, conference speakers said. That includes integrating DERMS with Advanced Distribution Management Systems (ADMS) for peak shaving, for distribution system infrastructure deferral, for managed charging, and for grid interactive water heater programs.
Most utilities are doing a good job of capturing DER value at the system level by using preexisting mechanisms creatively, EnergyHub's Frader-Thompson said. "Overcoming uncertainty about DER at the distribution level will require a new comfort level with the computer taking over more of the DER management."
Integrated ADMS and DERMS provide situational awareness of customer load in real time and deliver forecasting and planning analysis to smooth present and future system constraints, Guidehouse said. These advanced technologies can allow utilities to "act on the offensive and transition to become critical allies in the orchestration of distributed assets."
Older demand response software and hardware was "like a blunt instrument" that "could turn the end device on or off" but "data would not necessarily flow back in a meaningful way," said Eversource Energy Director of Energy Efficiency Michael Goldman. New software like Enbala's DERMS is "more surgical in its precision," he added.
The smart software "allows us to aggregate all the different types of DER into a single platform and present us with a single view and a single point of control," Goldman said. The technical capability "is there now and we are actively doing it," though many utilities are still "transitioning," he added.
Many kinds of utilities in many places are showing an interest in that transition.
California community choice aggregator Marin Clean Energy is working with Enbala to develop an operating system that, when deployed, will use customer-owned DER to shave peak, Marin's Distributed Energy Resources Manager Jim Baak said.
Holy Cross Energy is working with a proprietary software operating system built by Camus Energy "for integrating variable renewables and distributed resources at scale at the distribution level," its President and CEO Bryan Hannegan said. And it is working on pilots "to find ways to access value using customer-owned DER in a real world environment, with real people," he added.
Minnesota's Otter Tail Power has long used "multiple" rate strategies to manage up to 120 MW of demand, but is only beginning to look at DER, according to its Market Planning Program Manager Jason Grenier. "We're looking at new technologies to give us more flexibility" after a recently completed grid interactive water heater pilot "had mixed results" and the control technology proved non-viable, he added.
Puget Sound Energy in Washington state has piloted traditional demand response programs with similarly "mixed results," but is working on all-source flexibility solicitations, its Manager of Distributed Energy Resources Therese Miranda-Blackney said. Puget Sound "does not have that capability today and there is a lot to figure out, but the desire to get to 'yes' in the future is very strong."
Baltimore Gas and Electric has over 300 MW of load reduction capability through over 400,000 DERs and 1.3 million smart control devices, its Senior Energy Efficiency Program Manager Dana DeRemigis and Strategic Programs Manager Kristy Fleischmann Groncki told the conference. But it is now working with EnergyHub to add 30,000 devices and 30 MW of load reduction capability by 2023 and to prepare a managed EV charging program.
A major question for all these utilities is whether the customers that own DER will allow utilities to use their resources when needed, the representatives said.
The primary tool utilities are exploring to assure the DER will be available as promised is through incentives that drive customer choices, conference speakers said.
The new demand response "is entirely in the consumer's hands," Holy Cross's Hannegan said. The utility will contract with customers for rebates on DER purchases and lower rates in return for being allowed to use the DER to reduce loads. "Our data analytics will allow us to understand what participation rate to expect," he said.
Southern California Edison (SCE) is incorporating DER through long-term contracts, SCE spokesperson Julia Roether emailed. These contracts contain "development milestones and financial provisions that are intended to ensure the resources meet contractual online dates," and they also may include "financial penalties to compensate SCE for having to purchase alternative resources."
Like many other utilities, SCE commits to compensating customers for DER "monthly dispatch performance," she added. These "pay-for-performance" agreements also allow the utility to terminate the contract if customers' performances are inadequate.
That does not mean the needed flexibility will not show up, Enbala's Young said. System management software "individually manages and measures the response of each asset to turn on or off, or increase or decrease output instructions, in near real time," he said. "If a battery does not discharge, the software sees that and instructs the next battery in the system to discharge."
The total assets participating "are the insurance of getting the needed flexibility, and if the response is inadequate, the operator is alerted and they can take other actions," he added. "Today's software is a complete reboot of system management, and will manage different types of customers, technologies, and vendor brands to optimize the system in real time."
Diversity "is the key to knowing customers will show up," EnergyHub's Frader-Thompson agreed. "Repeated outcomes and propensity to adopt assessments show we can tell you what incentives and technology offerings will lead to what participation, and whether and when and how utilities can achieve their goals. Some customers will not participate but that is not a failure because most will."
Because customers have consistently proven that they will participate, using customer-owned DER is an advantage over using traditional resources, he added. "A model based on diversity makes it very unlikely that all resources and software will fail simultaneously. There is strength in numbers."
The other important factor in securing customer participation is policy, Frader-Thompson said.
Programs have grown more rapidly where utilities offered bundled incentives, like rebates through energy efficiency programs for batteries and time-of-use rates that reward customers for reducing peak demand period usage, he said. But utilities may require regulatory approval of these bundled incentives through different programs from different utility silos.
With new acceptance from utilities and adequate regulatory support, the customer piece can take its place in the cooperation needed to make load flexibility a wider opportunity, conference speakers said.
When it all comes together
Where utility system control technologies and customer participation come together, they offer a flexible and emissions-free solution critical to the emerging challenge facing the power system of managing a dynamic load with a variable supply, Frader-Thompson said. When utilities and customers partner, EnergyHub and others using smart system managers to take advantage of flexible resources can dispatch demand to meet renewable supply instead of dispatching supply to meet demand, he added.
Incentives attract participation and contracts assure the resources are online and functioning, SCE's Roether agreed. And SCE is building new ADMS and DERMS "operational control and DER management capabilities" to address future uncertainties through integrated resource planning that incorporates reliability forecasting, she added.
"The utility is increasingly the conductor of a symphony of distributed resources and the challenge will increasingly be to prevent the sound from the individual devices from clashing," Holy Cross's Hannegan said. The incentive programs and advanced software are "to make beautiful music that operates with all the reliability and safety customers expect."
Clarification: This story has been updated to more accurately reflect the views of EnergyHub's Seth Frader-Thompson regarding the company's efforts to match energy demand and renewable energy supply.
Article top image credit: Photo illustration by Brian Tucker/Utility Dive; photograph by jhorrocks via Getty Images
Two barriers to utility and customer savings with flexible loads and how regulators can help
Utilities, regulators and load flexibility authorities say better distribution system control technologies and compensation are needed to increase use of flexible customer-sited resources.
By: Herman K. Trabish• Published Jan. 6, 2021
Utilities' ability to protect reliability in today's rapid transition to variable, distributed generation faces two key barriers and regulators' help is needed to overcome them.
Advanced demand response (DR) can use the flexibility of customer-owned technologies to meet the balancing challenges of the changing supply mix, regulators and utility executives agreed during an Oct. 20 symposium hosted by The Brattle Group. Utility pilots are revealing what works, but also showing how technology and incentive structures are keeping flexible loads, such as customer-owned solar and smart thermostats, from supporting reliability.
"Load flexibility can shift energy use to when it costs less, shape energy use to match renewables' availability, and to allow them to meet other system needs," said Minnesota Public Service Matt Schuerger during the symposium. "And it can be a cost-effective solution for reliability by offsetting other investments in generation with lower-cost customer-owned distributed technologies."
"As transportation and building electrification initiatives grow, flexibility might become necessary for utilities to manage cost," said symposium co-chair and Brattle Group Principal Ryan Hledik. In fact, "the regulatory approval of grid modernization investments to support electrification, decarbonization, and increase utility revenues could be justified by the cost-effectiveness of flexibility."
Utility advanced DR pilots are growing, but regulators have only begun to resolve the two key barriers of finding technologies to manage distribution systems and creating incentives for stakeholders, Brattle's symposium revealed. Inadequate system controls and compensation mechanisms have left load flexibility's enormous potential to meet U.S. reliability needs little used, participants agreed.
The potential of advanced DR
Almost 70% of today's approximately 60 GW of U.S. DR capability comes from traditional commercial-industrial load management, according to a June 2019 Brattle study. But new demand-side smart technologies, utility control and communications technologies could transfer market dominance to residential customers within the next ten years, according to Brattle.
The resulting nearly 200 GW of cost-effective load flexibility from existing and new DR could meet up to 20% of the estimated 2030 U.S. peak load, avoiding over $15 billion annually in system costs, Brattle found. Existing incentives and technologies can deliver an estimated 40% of the new load flexibility capacity, but the other 60% will require new technology and incentive solutions.
"The question is no longer whether load flexibility is reliable, but whether utilities, regulators and stakeholders want to do it."
Principal, The Brattle Group
The bulk of the 2030 value will be in avoided capital expenditures for new generation, Brattle estimated. Avoided expenditures for transmission and distribution infrastructure and for ancillary services will also add value.
They can also give utilities the incentive to move away from investments in generation and other system infrastructure by allowing them comparable returns for investments in customer-sited flexible technologies, the symposium speakers said.
Driven by competition from distributed energy resources (DER) providers, new utility programs have shown load flexibility can be reliable. "The question is no longer whether load flexibility is reliable, but whether utilities, regulators and stakeholders want to do it," Brattle's Hledik said. "Some are starting to understand how demand-side resources can lower system costs and increase their systems' flexibility."
Utilities and regulators are demonstrating that new understanding through pilots.
The technology barrier
Pilots are a way to break down the technology barriers, utilities and regulators told the symposium.
Xcel Energy Minnesota is developing a variety of DER-based peak reduction programs that allow customers to give the utility control of smart thermostats and appliances. But Xcel-commissioned research by Brattle showed a limited value proposition in peak shaving and grid services until utility control-room management of the flexibility from DERs improves, Xcel Senior Regulatory Analyst Jessica Peterson told the symposium.
Since 2015, Xcel's strategy to expand use of DERs has been to evolve "toward flexibility" by gradually introducing advanced practices like controlling customer thermostats and devices, Peterson said. With its learning, it has set higher goals for advanced DR programs using customer-sited resources.
But distribution system control "technology is a huge challenge right now because it needs to evolve more to meet utilities' needs," she said. Xcel chose a DERMS system that it found could not connect to all its customer's devices. "We need to be able to connect with and control any equipment a customer or third party may want to use and we're still looking for that technology."
A big step forward would be streamlining the regulatory approval process "so we can move more quickly to trials of unproven new technologies," she added.
Minnesota's utility commission acknowledged Xcel's concerns in its 2017 order approving the company's last integrated resource plan, Commissioner Schuerger said. The order required 400 MW of additional DR by 2023, a full and thorough cost effectiveness study, and an evaluation of new advanced DR and load flexibility technologies.
Minnesota's resource mix is changing rapidly, Commissioner Schuerger said. To support an expected 45% or higher renewables penetration by 2030, the commission is evaluating investments in distribution grid modernization and focusing on "overcoming technology barriers," he added.
"The technologies load flexibility depends on may be acceptable for cell phones but not for electric system reliability."
Smart Buildings Research and Development Manager, Southern Company
Portland General Electric (PGE) was an early leader in testing load flexibility.
Its proposed smart grid test bed program would pilot smart devices and appliances controlled through new communications technologies, Salmi Klotz said. The program aims to better understand the values and services flexibility can offer to the distribution and bulk electric systems. It will also explore customer rate design preferences and other factors impacting customer participation.
But there are challenges ahead, PGE Director of Retail Technology Strategy Conrad Eustis told Utility Dive in 2019. The lack of customer devices with the needed communications capabilities may prevent Brattle's 200 GW load flexibility forecast for 2030 from being realized until 2050.
Utilities and commissioners have every right to be concerned about inadequate system controls, but "we can develop any technology to meet customer needs," Salmi Klotz said. Though PGE's test bed will demonstrate new ADMS and DERMS breakthroughs, he shares Xcel's concerns about the lack of interoperability and open standards that prevent visibility and management of all customer technologies, and have already imposed costs on PGE customers.
"Closing the communications standards gap would accelerate our ability to develop and deliver cost effective solutions," he said. Technology is a baseline issue, but Oregon regulators are working with PGE "to open that discussion about solutions."
"The technologies load flexibility depends on may be acceptable for cell phones but not for electric system reliability," said Phil Markham, smart buildings research and development manager for Southern Company and its subsidiaries in Alabama, Mississippi and Georgia. Flexibility "could be a threat to grid stability" without "granular control," he added.
But because load flexibility is a part of decarbonization, it offers "opportunities to make capital investments in electrification," he added. Regulators need to support research on "communications with open standards to allow utilities to connect through a reliable communications network with the range of customer technologies," he said, endorsing the Xcel and PGE position.
"Regulators need to create the space for utilities and third parties to innovate and create financial rewards."
CFO, Sacramento Municipal Utility District
Streamlining the development of new technologies like energy management systems is "essential" to adding load flexibility, spokesperson Craig Bell for Southern Company subsidiary Georgia Power agreed. That is the "goal" of the load flexibility pilots it has proposed to Georgia's regulators.
"I'm hired to understand and prepare Georgia for what will be needed in the future," Georgia Public Service Commission Vice Chair Tim Echols told the symposium. The legislatively mandated integrated resource planning process includes "a pilot project opportunity" that allows regulators to green light load flexibility trials and the commission has multiple innovation sandboxes on DER ongoing.
"Regulators need to create the space for utilities and third parties to innovate and create financial rewards," Sacramento Municipal Utility District CFO Jennifer Davidson told the symposium. "We cannot do it alone. The need for innovation is too big."
But Hledik said the technology barrier is already being addressed. "Utility pilots and small programs are using technologies to communicate with customer-owned smart devices and DER," he insisted. "It may not be the level of sophistication some utilities would like, but it's been enough to meet system needs."
Breaking down the incentive barrier may be more complicated.
PGE's test bed may allow trials of innovative transactive or subscription rates that provide compensation to customers for allowing the utility to use their DER for load flexibility, but if they are scaled, they would have to be worked into the traditional regulatory model, Salmi Klotz said.
There are also discussions with Oregon regulators to address the incentive barrier through a new specially designed compensation rate to participants in load flexibility programs based on the value of the service they provide, he added.
It is possible the test bed could trial direct monetary incentives to customers, but PGE is still working on how to structure them, Salmi Klotz said. It will likely require "layering incentives" to get adequately high "levels of engagement and participation."
The other approach is compensation to utilities that offset their losses of guaranteed returns for infrastructure investments, he said. That could be through performance-based regulation incentivizing load flexibility additions, or adjusting the utility's rate of return to make using flexibility as beneficial to the utility bottom line as capital expenditures on central generation.
Introducing those kinds of changes "does not have to be a barrier if the utility's approach is customer-centric," Salmi Klotz said. "The regulatory compact is based on service in the public interest and load flexibility is in the public interest because it gives customers a way to lower their bills and makes the utility a tool for policy implementation, which justifies a rate of return for supporting flexibility."
"There is a real danger of letting the perfect be the enemy of the good. To protect ratepayers, we have to develop new programs, learn from them, and move forward."
Commissioner, Minnesota Public Utilities Commission
The Minnesota commission has been "actively evaluating and advancing" performance-based regulation, Commissioner Schuerger said. The objective is developing performance metrics that "cost-effectively align generation with load and reduce peak demand."
Xcel is already working under a multi-year rate plan and, with stakeholder input, has identified performance-based goals, outcomes and metrics, he added. "Xcel's Q1 2021 report on its performance, using those metrics for the first time, is expected to lead to data-based performance incentives for advanced DR and load flexibility."
But the new metrics, and the incentives they could lead to, "are intended to improve and evolve the traditional cost of service ratemaking paradigm, not replace it," Schuerger stressed. "They can also evolve traditional DR into more flexible advanced DR," he said.
The next big question
Regulators and utilities must break down these barriers, but they also must take the next big step, Brattle's Hledik said.
Through 2030, load flexibility will "get smarter" and then "get bigger," growth will be led by residential customers with new access to smart devices, and regulators will support pilots, Brattle predicted in its 2019 paper.
But a lot of pilots, which are important when they test new and unproven features of flexibility, "will never become full-scale programs," Hledik said. "They are being done without planning for full-scale deployment, and without that planning, there is a strong possibility there will be no further deployment."
That is an indicator of "the bigger problems" of mistrust of technologies and of not addressing the disincentive to investment, he said. "Pilots have shown and are showing flexibility saves system and customer costs and they should be scaled."
Scaling flexibilty pilots is important, Commissioner Schuerger agreed during the symposium.
"There is a risk to ratepayers and to the public interest of not developing new load flexibility programs," he said. "Institutional inertia could lead to addressing reliability with investments that could become stranded, increasing costs to ratepayers."
The record before the Minnesota commission "shows advanced demand response and load flexibility are cost effective," Schuerger said. "There is a real danger of letting the perfect be the enemy of the good. To protect ratepayers, we have to develop new programs, learn from them, and move forward."
Tacoma Power's first foray into demand response could support green fuels production
Tacoma Power wants to attract green hydrogen producers to its territory with a discounted electricity rate. In exchange, the utility may curtail its service up to 1,300 hours annually.
By: Robert Walton• Published March 29, 2021
Tacoma Power has developed a pilot demand response project that will offer producers of electrofuels like green hydrogen a discounted electricity rate in exchange for the ability to curtail their electric service potentially up to 1,300 hours a year.
This is Tacoma Power's first foray into demand response, according to Erin Erben, a manager in the power rates and financial planning department of the public utility of Tacoma, Washington.
Most of Tacoma Power's electricity transactions are made in bilateral markets, where the focus is selling excess supply and not buying capacity for seasonal peaks. So as spare hydroelectric capacity in the region has tightened, the utility is for the first time considering a program what it may be worth to pay customers to reduce usage at peak times.
"We have spent quite a bit of time at Tacoma Power, discussing the merits of demand response and demand response rates, as the market evolves in the Northwest and capacity constraints become more prevalent," said Erben.
"[I]f we don't have to commit to procuring generation for a customer, essentially then they are non-firm and we wouldn't need to assign costs associated with generation capacity in our cost of service."
Power Rates and Financial Planning Department Manager, Tacoma Power
Tacoma has historically relied on hydropower, both self-generated and purchased from the Bonneville Power Administration. But according to Erben, this supply source is limited and as other Northwest suppliers shut down fossil plants and invest in renewable energy the amount of available capacity in the region has been shrinking.
Along with wanting to ensure system reliability, the Tacoma City Council is also pushing to reduce the city's overall carbon emissions.
The combination of capacity shortages and clean energy policy "got us to really think about how to price, how to value demand reductions when there is no explicit market for demand or capacity in the Northwest," said Erben.
The utility landed on the idea of a non-firm rate that could take advantage of the flexible production schedules of electrofuels operations, such as green hydrogen and formic acid production. "The benefit of this approach is that if we don't have to commit to procuring generation for a customer, essentially then they are non-firm and we wouldn't need to assign costs associated with generation capacity in our cost of service," said Erben.
Will customers sign up for longer curtailments?
Customers on the new electrofuels tariff could be curtailed not for hours, but days — up to 15% of a year.
"That's a lot," said Erben. "Typically, customers get a little nervous when you want to curtail more than 100 to 200 hours in a year. This could be more than 1,000 hours. Not many businesses can handle that, especially on 10-minutes notice, which is what we have here. Essentially this is the equivalent of spinning reserve capacity."
With those requirements, there is no guarantee the program will attract customers. "Getting a customer to shed load for a few hours a day is a lot easier than getting customers to shed load for several days in a row," which is a key element of the pilot that this is designed to target, Erben said. But "given the unique nature of this emerging business, it seems like a really good opportunity to explore."
Brett Feldman, research director at Guidehouse Insights, said in an email that Tacoma Power's interruptible rate "is a novel idea to try to bring that specific customer segment of electrofuels to locate in their territory." But he also questioned whether it is technically demand response.
"Utilities have had interruptible rates for decades for electric and gas," Feldman said. "They give large industrial customers lower rates for the right to shut them off if needed."
There are emerging demand response-type programs arising for battery storage that allow for "many more hours of response than in traditional curtailment-based DR programs," Feldman said. He pointed to National Grid's Connected Solutions program in Massachusetts and that state's Clean Peak Standard.
Relying on hydrogen for storage
Green hydrogen can function as energy storage, because the fuel is later used as a replacement for fossil fuels in some applications. But its ability to be used by Tacoma in an interruptible-rate program hinges on the flexibility electrofuel producers have in the process.
Hydrogen production is not a time-critical operation, said Feldman, "and curtailing it does not negatively impact production (unlike some industrial processes like steel, cement), so it is very flexible, as long as the financial benefit of the lower rates outweighs the loss of production during curtailment."
Tacoma Power considered applying the new rate to its customer base more broadly, but Erben said that "for a lot of larger customers, turning on and off with minimal notice was not attractive." The utility will be exploring other pricing-based demand response solutions other large customers over the next year, she added.
Ultimately, Tacoma Power is still considering how much of its load it can economically make available under the new tariff. The pilot launched with 65 MW available — though prospective customers have expressed interest for up to 200 MW.
"That aligns pretty well with where we start to see capacity constraints in some months," said Erben. The utility sees potential capacity constraints in the fall, when water supplies are tighter, along with any time high loads stress the system.
The system has a peak load of about 900 MW.
Tacoma Power does most of its power trading on Intercontinental Exchange, but is also preparing to enter California ISO's Energy Imbalance Market (EIM) next year. The new demand response rate "is a tool we're thinking would benefit us in a market like EIM."
So far, no customers have signed up for the rate though some have expressed an interest. Price is a "significant" issue for green hydrogen producers, said Erben. "Their margins are thin," but they can also curtail their load regularly.
Green hydrogen producers are looking for rates at about $0.035/kWh, said Erben. Tacoma Power's demand response rate will vary based on some considerations, including load factor, but is expected to come in around $0.045/kWh.
Without the demand response rate, producers would pay about $0.055/kWh, said Erben.
"We are talking with customers now," said Erben. Potential customers must also find sufficient land for their operations, in areas where the utility can supply sufficient power. There are also considerations for environmental impacts, and permitting which needs to be done.
For now, Tacoma sees this new rate as "putting our toe in the water around demand response," said Erben. The utility is trying to understand the value of flexible capacity, and expects to utilize the resource more as its understanding deepens.
"Over the next five years I think we'll have a lot more clarity in the Northwest around capacity values," said Erben.
Demand response failed California 20 years ago; the state's recent outages may have redeemed it
State regulators may now see a need for more flexible demand response to address power supply shortages
By: Herman K. Trabish• Published Sept. 28, 2020
California's recent blackouts revealed serious shortcomings in the state's energy transition planning, but may also have prompted a reconsideration of a distribution system resource that previously had a bad reputation.
Demand response (DR) failed California in its 2000-2001 energy crisis and left regulators inclined to call on it only in the most dire energy shortages. But the recent heatwave-induced rolling blackouts had billion-dollar-plus costs and the performance of a new kind of DR got policymakers' attention.
Preliminary data from a CPUC analysis of the blackouts suggests the still-small supply of flexible DR "contributed quite a bit to grid support," said CPUC Deputy Executive Director for Energy and Climate Policy Edward Randolph. "This is the first event in many years that required sustained demand response. The analysis of its performance will inform future decision-making."
"If California had already seriously embraced flexible demand response, it would not have even come close to blackouts," said Gridworks Executive Director and former California Public Utilities Commission (CPUC) Energy Advisor Matthew Tisdale.
If the CPUC analysis confirms flexible DR's potential, the resource will face new and bigger challenges because its value will change with increased use, according to Randolph, DR advocates, and a July 2020 study from Lawrence Berkeley National Laboratory (LBNL). That will add to the regulatory controversies about its value that have obstructed DR growth for years.
The need for flexible DR to manage peak demand is likely to grow as more of the economy is electrified and the need for and value of being able to shift and shed load becomes greater.
The value of flexibility
California's rising penetration of distributed energy resources (DERs) makes it a leader in discovering the value their flexibility can bring to power systems across the country.
Buildings use 75% of U.S. electricity and in some regions up to 80% of peak demand generation, LBNL reported. Making buildings more energy efficient and managing their energy usage with flexible distributed energy resources (DERs) can limit blackouts without compromising reliability.
"Demand flexibility is the capability of DERs to adjust a building's load profile across different timescales," according to LBNL. The strategies to do that are "the core" of grid-interactive efficient buildings (GEBs) and "the potential impacts are significant."
"Our aggregations of nearly 60,000 devices and appliances, including thermostats, batteries and home car chargers are bid into the CAISO market 10,000 times a day, like small power plants on standby all over the state."
GEBs use "smart technologies, including advanced controls and sensors," to "optimize" building energy use, LBNL added. The building's load profile can be adjusted by shedding, shifting or modulating load and supplying generation.
Nearly 200 GW of flexibility from both the traditional DR used for decades and new DER-driven flexible DR could reduce the projected 2030 U.S. peak load 20%, avoiding over $16 billion annually in costs, a 2019 Brattle Group study concluded.
"Modernizing conventional programs" can deliver 40% of that potential, but the other 60% is in "emerging" building automation technologies, Brattle Principal and study co-author Ryan Hledik added.
Where flexibility is working
DR's value in meeting August's "grid needs" was recognized in CPUC Energy Division Demand Response spokesperson Aloke Gupta's Sept. 3 email to demand response providers, in which Gupta called for their "continued support." The California Independent System Operator (CAISO) has similarly recognized and praised DR's contribution.
Utilities also took advantage of flexible DR during the recent shortages.
Residential and commercial-industrial customers "delivered" in response to the millions of Pacific Gas and Electric emails, phone calls and texts sent between Aug. 17 and 21, the utility's spokesperson Ari Vanrenen emailed. On Aug. 17, the utility's flexible DR programs dispatched about 480 large customers and about 1,500 capacity bids, and 234,450 customers earned rate rewards for load reductions.
In Massachusetts, Eversource Energy has had similar success with flexible DR launched in 2019, said Michael Goldman, the company's energy efficiency, regulatory, planning, and evaluation director.
Eversource's "portfolio of flexible loads" includes "customer-sited behind the meter assets" like smart thermostats, batteries, electric vehicles, smart appliances and traditional commercial-industrial loads.
Eversource used "tens of thousands" of distributed assets to reduce system peak demand by 100 MW to 200 MW in the program's first year, Goldman said. And "we are thinking about new use cases [for DER] to provide transmission or distribution system services."
"Making smart devices available and affordable to more customers would, however, be an investment in making California ready for the next heat wave."
Executive Director, Gridworks
California has seen both a growth in DR and a shift from the traditional approach, which focused on large corporate loads that respond to direct notification by the utility or system operator to curtail energy use.
California grew its 2003 DR capabilities of 1,485 MW to 2,732 MW by 2019, according to CPUC data provided by Randolph. But traditional DR diminished after 2015, when the commission turned toward flexible DR. Its pilot Demand Response Auction Mechanism (DRAM) mandated investor-owned utilities acquire flexible DR and it ruled that diesel-fueled backup generation could not serve state DR programs after 2017.
"The goals of demand response have shifted," CPUC's Randolph said. Because CPUC directives discouraged traditional DR, California's total DR growth fell, but "it is starting to build back up," he added. With new initiatives "there will be significant growth by 2021."
California's private sector has also shown the new flexible DR is viable.
OhmConnect is a private aggregator of customer-sited DR. Its 150,000 California customers answered calls over 200 days in 2019 and at times reduced state peak demand over 150 MW, OhmConnect CEO Cisco DeVries said. "Our aggregations of nearly 60,000 devices and appliances, including thermostats, batteries and home car chargers are bid into the CAISO market 10,000 times a day, like small power plants on standby all over the state," he said.
OhmConnect reduced over 200 MWh of load on Aug. 14 and 18, almost 200 MWh on Aug. 17, and almost one GWh of total energy usage from Aug. 13 to Aug. 20, DeVries reported. Its customers earned over $1.3 million for usage reductions and 739,000 adjustments to devices and appliances were made, including 580,000 done automatically with only 20 minutes notice and "without a single failure in dispatch."
OhmConnect "has spent seven years building the capability and technology to address load reduction and learning how to engage customers," DeVries said. "It is not easy, but we can now do it at scale, in real time, and in measurable and predictable ways."
The company is targeting 600 MW of California DR capability for summer 2021, or "more than half of what was needed during the blackouts," he added. Flexible DR "is the only way we can solve the blackout issue in the near term without fossil fuels."
On the blackouts' first day, smart battery provider Stem's deployments through the DRAM, Southern California Edison, and private contracts "supplied about 50 MW to customers, which reduced peak loads equivalent to taking 20,000 homes offline," said Ted Ko, Stem's vice president of policy and regulatory affairs.
But LBNL, advocates, and utilities said big challenges are ahead if flexible DR's real potential is to be realized.
The problem of success
"Utilities and regulators must confront technical and market complexities" to enable greater use of flexible DR, Brattle's Hledik said. Measuring its value will require metrics not necessary for traditional DR.
Performance assessments must "determine the timing, location, quantity, and quality of grid services," LBNL reported. The metrics must show system operators, utilities, building managers, and occupants that flexible DR can "optimize building performance."
Much assessment will be by comparison with a "counterfactual" or "baseline" quantification of what would have happened in the absence of flexible DR, LBNL said.
But when flexible DR events are called multiple times a week, defining that baseline will be harder, LBNL Electricity Markets and Policy Department Senior Advisor and paper co-author Steven Schiller said. Unlike traditional DR value, based on quantifiable past impacts, calculation of flexible DR value will require "automated analytics" to make complicated performance projections of changing loads and customer participation.
Non-event days "may not be a reasonable proxy for normal load when normal load is altered on a continuous basis," Eversource's Goldman agreed.
Some industry observers said flexible DR's potential will only be realized through rate reform.
Effective use of DR "has to start with efficient pricing," said CAISO Senior Manager for Infrastructure and Regulatory Policy John Goodin. "Customers must be exposed to time-varying, grid-informed, grid-supporting prices, and homes and buildings must be automated to use customers' preset preferences to react to price signals."
Smart technologies that can control flexible DR are available and companies like OhmConnect have shown how to unlock their value with time-varying pricing, GridLab Executive Director Ric O'Connell added. "But there is not a robust market that compensates providers and users for that value."
Instead of the complicated reliability rules that limit DR viability in California, Texas uses market signals to drive new investment "and wholesalers and retail distributors manage the risks of shortages and price spikes," O'Connell said. But "it makes a participation model for flexible DR, which may not be price-competitive with utility-scale renewables, more difficult, and we need to unlock its potential."
California has "a duct-taped, MacGyver-like resource adequacy system in need of overhaul."
Executive Director, GridLab
Customer engagement is "critical," but California should start with basic, easy things like more messaging to customers when load shedding is needed, not rate reform, Gridworks' Tisdale said. "Making smart devices available and affordable to more customers would, however, be an investment in making California ready for the next heat wave," he agreed.
The biggest obstacle to advancing flexible DR is California's regulatory and legislative apparatus, Goodin, O'Connell, Tisdale and Randolph agreed.
MacGyver's duct tape
California has "a duct-taped, MacGyver-like resource adequacy system in need of overhaul," GridLab's O'Connell said. "Our generation mix is changing dramatically, and the blackouts are part of a complicated transition," but "the way we address change now will not serve us going forward."
Measures to improve compensation to customers for adding flexible DR devices, now stalled before the CPUC, should be advanced, flexible DR advocates said.
Stem could have provided twice the 50 MW load reduction it delivered if rules recognized and compensated the multiple uses of batteries and allowed export of stored energy to the grid, Ko said. "A 2017 LBNL study for the CPUC called the flexibility of customer-sited battery storage 'the ideal DR technology,' but the commission did not follow through," he added.
The 2017 study did show the need for more flexible DR and storage, CPUC's Randolph acknowledged. But rules that apply to flexible DR are "fundamentally different" than those for "event-based" DR, and commission rules calling and compensating flexible DR must be consistent with "the ISO's specific need" for resources to be available when called.
The uncertainties about flexible DR have slowed development of participation rules, but its potential, especially of automated DR, "is becoming clear and we need to move faster," he added. Those rules will not, however, change "tomorrow" because providers "might not be able to meet them that fast."
A major commission failure was curtailing the DRAM program, OhmConnect's DeVries and Stem's Ko said.
The DRAM was intended to help scale flexible automated DR, and it was imperfect, but inadequate fixes to procurement processes were made, DeVries said.
If those procurement changes on incentives had not been made, there might have been "as much as 300 MW more commercial sector storage available to respond to the blackouts," Ko added.
"The DRAM pilot project did not perform well initially but was extended, with rule and process changes," CPUC's Randolph replied. Because "some providers still could not meet their contractual obligations," it was reduced "to protect ratepayers."
"These events are the first big test of this kind of demand response and now we will have a lot more knowledge to work with."
Deputy Executive Director for Energy and Climate Policy, CPUC
More recently, new DR providers, using "a new type of customer and new technologies, are matching or exceeding their obligations," he added.
A 2019 CPUC "Load Shift" study suggested that from 2025 on, over $600 million per year could be saved with load shifting strategies to integrate more renewables and support reliability, Tisdale said. "But caution about the DRAM program's $10 million budget contributed to a billion dollar or more power outage. We need to be much bolder."
California "can no longer afford to be timid in readying the power system for massive climate changes," he added. "We can learn from our mistakes. The only thing that will stop us is timidity. Timidity and incrementalism got us blackouts, so why not try boldness?"
It is fair to criticize regulators for being too risk averse, CPUC's Randolph acknowledged. "But rules protecting reliability are one of the most fundamental things regulators must get right to keep the lights on. We have to be very conservative around those rules."
Regulators must, however, "avoid stifling innovation and potential market transformation," he agreed. "That is why we are doing a deep analysis of the blackouts' root causes. These events are the first big test of this kind of demand response and now we will have a lot more knowledge to work with."
Voltus vies to unleash thousands of MWs of demand response capacity in challenge to MISO restrictions
Clean energy advocates say allowing demand response participation in wholesale markets will increase competition, reduce customer costs and help regional transmission operators better manage the grid.
By: Robert Walton• Published Nov. 4, 2020
Demand response aggregator Voltus has filed a complaint with the Federal Energy Regulatory Commission challenging Midcontinent Independent System Operator (MISO) tariff provisions that allow states to block third party aggregators from participating in wholesale markets.
Experts say the practice is common in other whole wholesale energy markets, as technology has advanced since state opt-out provisions were approved. In MISO, Voltus says the change could unlock thousands of megawatts of demand response capacity.
The prohibitions were intended to alleviate concerns regarding implementation issues for operators, with regard to planning and transparency for utilities responsible for reliability. If Voltus prevails, the decision would allow demand response aggregators in MISO to participate in both retail programs run by utilities and bid into wholesale markets.
"This is really all about increasing competition and unleashing market forces in a space where they've been constrained," said Earthjustice staff attorney Aaron Stemplewicz. The group is representing Voltus in the case.
According to Voltus, aggregators could be delivering over 9,000 MW of demand response in MISO states, if not for the opt-outs. The company says if it were delivering the same demand response that utilities currently provide "Voltus would be saving ratepayers $130 million per year, while delivering better quality service via its technology platforms."
"It would mean more reliable and less expensive megawatts of demand response in all MISO states," said Voltus CEO Gregg Dixon.
Order 719 was issued in 2008, and in 2009 and 2010 MISO states adopted what were supposed to be "temporary" prohibitions — but then "there was really no fact finding beyond that," explained Stemplewicz. The prohibitions remained in place.
He says Voltus has brought its complaint forward now, more than a decade after Order 719, because there is recent and "clear" precedent to reverse the allowance of opt-outs, in FERC's recent Order 2222 and litigation surrounding FERC Order 841.
MISO, in a statement, said it believes its tariff and demand response provisions "continues to meet legal and regulatory requirements. We will respond to the complaint at FERC and provide any assistance in understanding the issues as FERC may direct."
In Order 841, FERC opened up wholesale market participation to storage resources and was later challenged for not including state opt-outs. The D.C. Circuit concluded in July, however, the effort to force opt-outs "invalidly invades the federal agency’s exclusive domain."
"The same principle applies here, the states are targeting FERC’s statutory domain by carving third party aggregators of demand response out of MISO’s wholesale market," Stemplewicz said. Similarly, FERC's recent Order 2222 rejected a broad state opt-out for distributed energy resources but left the opt out provision of Order 719 in place, he said.
The deadline for comment on the Voltus complaint is Nov. 9, but the Organization of MISO States (OMS) has requested an extension until Nov. 19. Once comments are in, MISO will have an opportunity to answer.
In an email, OMS Executive Director Marcus Hawkins said the group could not comment on the complaint as it is "still working through our internal processes to finalize our position."
Hawkins did say, however, that OMS has previously weighed in on this subject with regards to storage and Order 841. In that proceeding OMS warned that planning and operation of the distribution system by vertically-integrated utilities "can be greatly impacted by third-party resources without the requisite transparency."
In MISO, experts say most of the states have prohibited demand response participation in wholesale markets. But other regional transmission operators (RTO) have demand response aggregation in their markets.
Demand response aggregators already participate in both retail programs run by utilities and bid into wholesale markets in many RTOs, according to Brett Feldman, an associate director with Guidehouse Insights. The ability is "common in many other markets," he said, including PJM Interconnection, New York ISO, ISO New England, California ISO, and the Electric Reliability Council of Texas.
"MISO is the only market where most of the states ban third party participation of demand response," said Dixon.
"A lot of the issue in MISO is related to the fact that over 90% of the footprint is traditionally-regulated utilities," said Jessica Bell, a clean energy attorney at the State Energy & Environmental Impact Center at NYU School of Law.
According to Dixon "that's the single biggest factor," because utilities don't want third-party demand response and instead prefer to manage the resource themselves.
Technology enables more demand response competition
Stemplewicz said companies like Voltus could be providing more services to the MISO grid, "whether that's reliability, whether it be savings to ratepayers, or helping to more smoothly integrate renewable generators." Technology advancements since FERC's 2008 order have largely alleviated the implementation concerns, he said. There would also be mechanisms in place to ensure "there is no double counting" of demand response resources.
MISO officials, in their statement, noted that "technology is advancing at an unprecedentedly rapid pace which is true not only for DR technology but for all aspects of our industry requiring very complex layered solutions." The grid operator said its role is to "integrate what is approved into the marketplace."
The prohibitions mean limited competition, say aggregators.
"There is no competition so we see the quantity and quality of products are severely diminished," said Stemplewicz. He said this is "particularly important" in MISO, as the grid operator is "increasingly dependent on demand response resources."
Demand response "is one of several tools we use to help manage the increased uncertainty and variability that has come with a changing landscape," MISO officials said, "but there are others as well." They say those include: increased coordination with transmission seams partners, stakeholders and distribution operators, changing market products, incentive structures and planning processes to better align with efficiency and future reliability needs.
Earthjustice requested FERC fast track the case, in hopes the commission can make a decision before MISO's 2021-2022 planning resource auction that takes place in March of each year, to give Voltus and other aggregators the opportunity to participate.
As smart meters proliferate, a new kind of demand response becomes entrenched
AMI penetration is slowing, but utilities are harnessing new resources to keep demand response growing.
By: Robert Walton• Published Nov. 14, 2018
As a host of technologies are utilized in new ways to balance the electric grid, the definition of "demand response" is becoming more nebulous. But, however defined, one thing is certain: As a resource, it is growing more important.
Federal Energy Regulatory Commission (FERC) staff recently issued an annual analysis of advanced metering infrastructure (AMI) and demand response (DR), concluding both are on the rise.
The report found that DR participation in wholesale markets rose by about 3% from 2016 to 2017, to a total of 27,541 MW. And the contribution of demand resources to meeting peak demand reached 5.6% last year, up from 5.3% in 2016.
All this points to a growing flexibility in the nation's electric grid, though it is region and utility-specific. And it is being driven, at least partly, by AMI deployment. Smart meters are now "the most prevalent type of metering deployed throughout the country, accounting for nearly half of all meters installed and operational in the United States," according to the staff report.
The most recent data from the Energy Information Administration (EIA) shows 70.8 million out of 151.3 million operational meters were advanced meters in 2016. EIA's data, shown in the chart below, has AMI at about a 46.8% penetration rate; the Institute for Electric Innovation pegs the number at 47.6%.
But, it appears that the penetration rate of AMI is slowing.
"The number of AMI meters grew quickly over the period from 2007-2011, partially due to American Recovery and Reinvestment Act funds," FERC staff said in a statement to Utility Dive. Since then, according to EIA data, the growth in annual deployment of AMI has been "fairly steady," with the number of AMI meters increasing by about 13% per year on average from through 2016.
FERC staff added that those numbers have held true in more recent 2017 data from EIA, and over the past year "utilities in several states have received approval for, or proposed large-scale deployments of AMI."
But some regulators have been pushing back on further deployments.
Some regulators "don't think full deployment of AMI is justified, or that the benefits will justify the costs, and they think a more targeted approach is the way to go right now."
Senior manager of policy research, North Carolina Clean Energy Technology Center
"AMI penetration sits around 50%, and it seems that's just where it's at," Brenda Chew, an analyst at the Smart Electric Power Alliance (SEPA), told Utility Dive. "Part of me wonders if those that have a lot of changing customer needs and a lot more demand response resources have already got AMI installed."
Chew also points out that some utilities have switched from installing smart meters to replacing them. "After a decade or more of AMI being in the field, some early adopters are actually replacing existing meters," she said.
There are a few reasons the deployment of AMI is slowing, in particular that federal support for smart meters, which was authorized by the Energy Independence and Security Act of 2007, has dried up, according to Navigant analyst Brett Feldman.
There have been some concerns about the benefits of time-based rates, leading Massachusetts regulators to deny AMI deployment. While some utilities, like Consolidated Edison in New York, are still pushing full deployment, "other utilities [are] more targeted for now," he said in an email.
ConEdison plans to deploy 5 million smart meters by 2022, for instance. FERC staff's analysis noted that in Massachusetts, Kentucky and other places, "state regulators and utilities are taking more targeted or cautious approaches to advanced meter deployment."
In August, the Kentucky Public Service Commission rejected proposals by two utilities to install smart meters throughout their service territories. The utilities can resubmit the plan in the future, but for now regulators said no to the $350 million expense.
In some states, regulators "don't think full deployment of AMI is justified, or that the benefits will justify the costs, and they think a more targeted approach is the way to go right now," Autumn Proudlove, senior manager of policy research at the North Carolina Clean Energy Technology Center, told Utility Dive.
And as larger utilities roll out the infrastructure, that leaves "a lot of smaller utilities left so it's harder to get the benefits of scale," Feldman said.
Demand response making 'comeback'
FERC's report also illustrates the growth of demand response, both at the retail level where it is managed by utilities and at the wholesale where it is procured in organized markets. But while the overall numbers rise, the data also shows it is dependent on decisions by specific utilities and grid operators.
FERC staff's report pointed out that demand resource participation in the wholesale markets increased by approximately 3% from 2016 to 2017.
The increase "is mainly attributable to an increase in demand resource participation in MISO and ERCOT, which was offset by small decreases in participation in other regions," staff concluded. The contribution of demand resources to meeting peak demand rose slightly, "due to a decrease in peak demand levels in 2017."
The report also looked at retail demand response, using EIA data from programs within each of the eight North American Electric Reliability Corp. regional entities, as well as Alaska and Hawaii.
"Nationwide, total potential peak demand savings from retail demand response programs increased by almost 3,050 megawatts," the report found, or approximately 9%.
For utilities, said Chew, they are embracing a wide range of technologies and expanding previous ideas of what constitutes demand response.
"There is a big shift in movement. Demand response is growing with new capabilities."
Analyst, Smart Electric Power Alliance
"It's hard to talk about demand response without getting into it in a more existential sense," said Chew. "There is a big shift in movement. Demand response is growing with new capabilities."
The resource may even be underestimated, she said. "I don't think they're counting all of it. It takes a while for them to change the terminology."
SEPA's own report earlier this fall, which it published along with Navigant and the Peak Load Management Alliance, concluded utilities were embracing use cases for demand response far beyond emergency, direct-load control programs.
The report surveyed 155 utilities and found they dispatched 10.7 GW of demand response last year out of a total reported enrollment of 18.3 GW of capacity. And increasingly, these include additional uses for demand response: soaking up solar, or utilizing controllable thermostats, rather than emergency load reduction.
"There are a lot of things that can be demand response," said Chew. "There is a lot of dispatchable, direct load control, but there are changes in the way people are calling on these devices. There is more locational deployment."
Compared with its origins as an emergency resource, Chew says "I think demand response is making a big comeback."
Cities push ahead on Energy Efficiency as a Service as private sector plays catch up
Forms of EEaaS have existed for decades as alternative funding mechanisms in cities. Now, as technologies accelerate and COVID-19 continues, the private sector wants in.
By: Chris Teale• Published Oct. 5, 2020
The proliferation of new technologies has transformed areas of mobility and software into comprehensive service offerings to bolster operations. Now, public sector entities are leading the charge on a tech-driven service offering that's been bubbling under the surface for decades: Energy Efficiency as a Service (EEaaS).
Under EEaaS, businesses and governments can underwrite the up-front costs of energy efficiency upgrades, then pay for them with the savings they get from those upgrades over the course of a long-term financial contract. Those upgrades are typically in the areas of lighting, air conditioning (HVAC) and energy management.
As an alternative funding mechanism, forms of EEaaS have existed for decades. But in contrast to typical innovation trends, the public sector is pushing ahead on EEaaS as private companies try to catch up.
Companies may be reluctant to make energy efficiency investments amid tightening budgets due to the COVID-19 pandemic, but with recovery showing the increasing need for climate action and safe air quality, EEaaS could present opportunities for growth, according to experts.
"Much of the world is shifting their focus to explore how to be part of the clean energy economy, and they're realizing that it's cost efficient," said Lisa Brown, senior director for municipal infrastructure and smart communities at Johnson Controls. "They're realizing it's good for the planet… It's part of their narrative now."
Steve Herzog, CEO of energy developer Greener Solutions, said the public sector's lead on EEaaS was driven partly bythe incremental tightening of local budgets over the last few decades, which forced city leaders to get more creative in how they could finance capital improvements.
"If you look at what happened to the government sector 20 years ago, [it] basically was like, 'Oh my God, we don't have enough money in our budgets to continue to fund different energy projects,'" Herzog said.
Public schools, too, have seen the benefit of EEaaS. Hillsborough County Public Schools in Florida, the eighth-largest public school district in the U.S., entered a 25-year contract with Minimise Global to revamp its energy management, add LED lighting and more efficient HVAC systems, with a view to incorporating rooftop solar.
That project, which Minimise says is the largest of its kind in the world, saves the school system $4 million a month and will ultimately result in $850 million in total energy cost reductions, CEO Dan Badran said. In 2018 alone, the company generated a rebate of $1.7 million to the school district through energy savings, and plans to expand the model to school districts elsewhere.
"All these initiatives around sustainability are being driven by consumers, asking their vendors to be more sustainable and to be more conscious of the impact their businesses are having."
U.S. Energy Advisory Services leader for power and utilities, PriceWaterhouseCoopers
The private sector is now looking to tap into the energy saving advantages of EEaaS. This push is driven in part by investor and consumer pressures to follow growing business trends in cutting emissions and decarbonizing operations, said Casey Herman, PriceWaterhouseCoopers U.S. Power & Utilities leader.
"All these initiatives around sustainability are being driven by consumers, asking their vendors to be more sustainable and to be more conscious of the impact their businesses are having," Herman said, noting that change has happened "very slowly."
While many businesses have emphasized their emissions reduction efforts for years, they have done that by highlighting investments in renewable energy portfolios or in other, more public-facing ways, Herman said. Now, with investors looking for more solid actions, energy efficiency has taken on new importance.
Robert Johnson, senior vice president of climate change solutions investment company Hannon Armstrong, said the public sector often has a leg up on the private sector as the tenor — the length of time on a financial contract like EEaaS — is far longer for government clients. Typically, the federal government can have a tenor of 25 years on a project, whereas the more profit-driven private sector may only go for five or 10 years.
Hannon Armstrong's efforts to boost energy efficiency at the U.S. Marine Corps Recruit Depot at Parris Island, SC, for example, resulted in a $85 million resiliency project financed over 22 years. That project included the addition of storage capacity, solar and 29,000 LED lights on the base. With shorter tenor in the private sector, a project's scale could be limited, Johnson said.
"It's a broad generality, but you can do lighting, and some generally light HVAC systems under that type of tenor, but doing large, very capital intensive projects, that becomes more problematic under those tenor constraints," Johnson said.
The evolution of the energy efficiency market has accelerated due to the proliferation of technology to help verify energy cost savings. Experts say it's come a long way from previous decades, when changes to work and savings were difficult to monitor.
"Think about big box retailers. Before, they had rooftop systems with a control point ... that was available to the store manager or store employees," Johnson said. "They used to have the thermostat under this plastic key-locked box. But no one could really mess with it unless you had the key. Well, most of those now are going away. And what's happening is all that's being monitored remotely."
This has been seen commonly with energy-efficient LED lights, which have increasingly been installed in streetlights. With internet of things (IoT) technology helping to remotely monitor energy usage, LEDs are a cost-effective way to save energy, according to experts.
It is a similar story with air conditioning, which is a major drain on finances and energy consumption, and is expensive to replace. To tackle this problem, OhmConnect CEO Cisco DeVries, a former aide to the U.S. Secretary of Energy, designed a program called Property Assessed Clean Energy (PACE).
PACE enables building owners to finance energy efficiency improvements through an increase in that building's property taxes over a set period of time, generally over five to 25 years, to avoid major expenditures up front. If an owner is seeking HVAC upgrades and the installation of solar panels, for example, that kind of modeling is key, DeVries said.
"You can pretty quickly say [to clients], if you got rid of that air conditioning system from 20 years ago and installed a new, highly efficient one and fixed up your [air] ducts, you would save a ton of money and a ton of energy," DeVries said. "But the up-front costs, maybe $20,000, maybe $25,000, is too much for most people to just pay for."
DeVries' company OhmConnect is a free service that pays California residents — particularly customers of utilities Pacific Gas and Electric (PG&E), Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E) — to lessen their energy use when the electrical grid is under stress.
Remote monitoring capabilities enabled OhmConnect to leverage this service and remotely turn off customers' energy during recent power blackouts in California, intended to reduce the risk of wildfires. Those efforts resulted in energy savings of 220 megawatt hours in just one day, DeVries said, with that energy returned to the grid to reduce strain.
With these IoT-driven solutions, experts say it will be imperative for building owners and cities to invest properly in data management software that can help to analyze energy savings data and insights. Those offerings are improving too, Herman said.
"Whether it's adjusting settings or whether it's turning things on and off, whether it's accumulating data across multiple facilities, data warehouses and data management has made that cheaper and more effective," Herman said. "Twenty years ago, you had more efficient equipment and that was it."
A post-COVID acceleration?
The long-term impacts of the COVID-19 pandemic on energy efficiency efforts for both the public and private sectors is unclear, experts say. In the short term, however, the pandemic has resulted in a major slowdown of energy efficiency projects as building owners look to tighten their belts, Herzog said.
"When COVID came in, you would think that because of the financial pressures on everybody that it would actually help the case. At least from what I've seen, most buildings are not comfortable letting people back in," Herzog said.
EEaaS could take on more importance amid pandemic recovery, Brown said. While cities may have been risk averse in the past when financing the retrofits needed to reduce building emissions, Brown said this could give them new urgency to invest.
"From a municipal and local government standpoint in the United States, it was more that people were intrigued, but not committed," Brown said. "Now that COVID hit, it ramped up the need to look at various other alternative financing mechanisms, just because of the budget shortfalls all these folks have."
Procuring the technologies needed to make buildings sanitary and safer post-COVID may also encourage cities to find alternative funding mechanisms for these kinds of expenditures. Features like better ventilation, effective heating and cooling, and tools to track social distancing must all be energy efficient to help ease operating costs.
"Overall, connection and remote control is probably much more top of mind than it was, say, six months ago," Brad Pilgrim, CEO of energy management firm Parity, said. "The pandemic has shone a pretty big light on the importance of having good air quality in our buildings, having remote access and control, and limiting the amount of people that are going into a building and letting people do things remotely."
Article top image credit: Kendall Davis/Utility Dive
SCE's novel energy efficiency deal with price 'premium' draws scrutiny, protest in Pacific Northwest
Southern California Edison wants to buy surplus hydropower. Although customers will pay a premium, NGOs say it may be a "groundbreaking" way to advance energy efficiency.
By: Robert Walton• Published Feb. 26, 2020
Southern California Edison (SCE) wants to spend approximately $3 million over three years to purchase 5 MW of hydropower from Oregon's Bonneville Power Administration (BPA) in a first-of-its-kind deal that energy efficiency advocates say could be "groundbreaking."
The hydropower is available because BPA exceeded its efficiency targets, but critics say SCE could simply buy energy on the spot market and that customers will wind up paying more than necessary.
SCE has asked California regulators to approve a contract with BPA by the end of this year, painting the deal in its October 2019 application as a "relatively small-scale commercial transaction" to test a "a model of conservation transfer."
The arrangement would "evaluate the efficacy of greenhouse gas reductions through an inter-regional transfer of carbon-free energy" and would be a "low-risk and innovative way to test the concept," the utility said in its application at the California Public Utilities Commission (CPUC).
Billed as a "proof of concept" transaction, SCE's application said the deal — if it proves to be effective and scalable to a larger market — "could help California meet its ambitious carbon-reduction goals without increasing emissions in other regions."
The utility has requested authorization to recover $2.89 million over three years in incremental costs to purchase the carbon-free energy. A CPUC public hearing has been set for April 13 and 14, and proponents of the deal are hoping for an October decision.
If SCE's application is approved, officials told Utility Dive that BPA has agreed to investigate offering larger-scale products for the transfer of carbon-free energy, freed up for export through BPA's energy efficiency initiatives.
"No one has done this before," NRDC Senior Attorney Ralph Cavanagh told Utility Dive. "If we can clear all the inevitable objections, there is the ability to get more energy efficiency ahead of targets and transfer the surplus. ... There are hundreds, potentially thousands of average megawatts of untapped energy efficiency in the region."
Cavanagh maintains the transaction is potentially "groundbreaking" and could enable greater greenhouse gas reductions anywhere there are energy efficiency gains in excess of planned savings.
Consumer advocates say deal too expensive
Some customer advocates, however, don't see the benefit, as SCE could simply purchase BPA hydropower or other carbon-free resources on the spot market.
The Utility Reform Network (TURN) filed a protest with the CPUC, questioning whether the proposed deal "constitutes an example of resource shuffling that would be prohibited under cap-and-trade rules adopted by the [California] Air Resources Board."
TURN notes that SCE has proposed to recover premiums paid to BPA through a "Clean Power Fee" ranging between $34.65/MWh and $36.55/MWh, which would include an energy efficiency program cost of $22.75/MWh that would be recovered from all SCE customers.
The customer advocate has asked CPUC to weigh in on the reasonableness of recovering a portion of the costs of this transaction through SCE's Public Purpose Program charge, which recovers costs for administering state mandated programs, as well as "whether the transaction is likely to result in any prospective commitments to incremental energy efficiency that would not otherwise have occurred."
"It seems likely SCE is overpaying," Kevin Woodruff, of Woodruff Expert Services, said in testimony filed Feb. 18 on behalf of TURN.
"The contract does not provide lower cost" energy efficiency to SCE, Woodruff wrote in his testimony. He added that the relevant comparison is not between SCE's and Bonneville's efficiency costs. "Rather, the relevant comparison for the commission to apply in this docket is the benefits and costs of SCE's other potential no-carbon resources."
TURN officials say they are concerned SCE is valuing the purchase of Bonneville electricity based on the CPUC-approved method for valuing energy efficiency located within the utility's own service territory.
"This conflation of demand and supply value is fundamentally inconsistent with the CPUC's guidance and dramatically overvalues imported electricity from the northwest," TURN staff attorney Matthew Freedman said in an email.
"The contract does not offer reasonable value to SCE's customers," Woodruff concluded. "It is not clear that the 'market price' portion of the contract is still at market or that SCE is not overpaying."
Deal advocates tout long-term price stability
Cavanagh said the three-year contract term is a key to having the deal pencil out. "Spot market prices are volatile," he said.
"Assured deliveries over a multi-year term are the antithesis of a spot-market transaction," Cavanagh said. "You have certainty of delivery, price, and a zero-carbon electricity product."
In a statement to Utility Dive, SCE said its electric customers "would pay a premium above the energy's market price," but also said the product BPA is providing "is different than what can be purchased on the spot market."
"The proof of concept will inform whether there is a market for this type of transaction and that market could be available to all load-serving entities in California," the utility said.
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Davide SavenijeEditor-in-Chief at Industry Dive.