Distributed Energy Resource Growth

A planned Austin neighborhood is touting itself as "the nation’s most sustainable residential community," with homes outfitted with solar panels and battery storage from Tesla.

The SunHouse at Easton Park development is the result of a partnership between Tesla, Brookfield Asset Management and real estate developer Dacra. Installations at the homes began in June with sample homes that will help guide the rest of the planned development. Homes will also have electric vehicle chargers and other smart features and the community will be outfitted with coordinated transportation and technology solutions, according to a Brookfield press release. 

The project also offers Tesla a unique large-scale test bed for its energy products, which have had trouble breaking through in the market because of installation challenges and high prices. Although Tesla CEO Elon Musk has pledged to make his company a market leader in solar with ambitions to build "virtual power plants" that connect homes powered by Tesla solar roofs, he admitted this spring to "significant mistakes" with the company’s solar arm. 

In a July 9 statement, Musk said "the feedback we get from the solar and battery products used in this community will impact how we develop and launch new products." Tesla, which disbanded its public relations department in 2020, did not respond to requests for more information about what it hopes to learn from the project. 

One of the errors Musk had cited was not recognizing the complexity of some existing roofs and the difficulty engineers would face in retrofitting them with Tesla solar tiles. Building the SunHouse homes from the ground up, however, can sidestep that issue and show the full potential of the solar and storage package, said Adam Walters, former legal counsel for Tesla. 

"Tesla is always looking to showcase its solar and storage technology and this is a great opportunity to do that, particularly as Tesla does not rely on consumer advertising to sell its products," said Walters, now an energy attorney with law firm Stoel Rives, in an email. "Tesla’s Powerwall 2 residential battery is already one of the most popular consumer choices for home battery systems worldwide, but this also gives Tesla’s struggling Solar Roof product line an opportunity to shake off some of that recent bad publicity due to its high cost and recent price increases."

'More people want independence'

The project will hold particular appeal in Texas, where a devastating winter storm in February led to the loss of almost half of ERCOT's generation and left millions without power for days. The grid operator has said it expects record demand this summer. 

In part because of concerns about grid reliability, the state has seen a surge of storage installations. An S&P Global Market Intelligence analysis, released in June, found the state could have up to 1,400 MW of storage online by September, eight times more than the previous year. Experts have said the grid failures could also fuel interest in microgrids that can be separated from ERCOT and keep the power on for businesses and residents. 

"More people want sustainable energy and more people want independence," said Peter Asmus, research director for Guidehouse Insights’ microgrids team. "I would imagine more projects like this would come."

Asmus explained that the Austin project is not a microgrid yet, although by some definitions each individual house could be considered a "nanogrid." To become a microgrid, the homes would have to be linked together and be able to be separated from the grid entirely. 

Still, he said, the addition of storage to the SunHouse homes offers some energy security, storing up power for times when the sun doesn’t shine or there are grid outages. According to a Brookfield press release, SunHouse homes could also send power back to the grid. Asmus said there is the potential for the Easton Park project to develop into a microgrid at a later date.

The 2013 R Street Midtown pilot from Sacramento Municipal Utility District (SMUD), for example, showed how blocks could become microgrids. In the project, 34 single-family homes were outfitted with a 2.25 kW solar array, a storage product, smart plug load controllers and smart thermostats. The neighborhood met its demand response targets and dispatched some energy from storage to the grid. Homeowners with solar and storage also saw lower energy bills, according to a report analyzing the project. 

Alabama Power also has a "smart neighborhood" microgrid pilot outside of Birmingham designed and deployed by PowerSecure. Emera Technologies has also launched the BlockEnergy smart platform for utilities to adopt community microgrids. 

A heavy concentration of solar panels in a neighborhood or community tends to lead to more homeowners showing interest in solar power, said Ben Delman, communications director for the nonprofit Solar United Neighbors. The group helps organize neighborhoods to purchase solar power in a co-op model. Increasingly, Delman said, those customers are looking to supplement their generation. 

"The questions we get the most now are about battery storage and EV charging, all the tech that’s complementary to solar," Delman said. "Tesla offering the Powerwall as part of this development tracks with everything we’ve been seeing."

Tesla's neighborhood ambitions

Easton Park isn’t Tesla’s first attempt to work on a neighborhood from the ground up. Tesla announced in November 2020 it would partner with Southern Company subsidiary Mississippi Power to build a smart neighborhood featuring homes with solar roofs. The Lauderdale County project is set to eventually have 150 homes with storage batteries, smart home automation and energy-efficient appliances. 

However, Mississippi Power spokesman Jeff Shepard said in an email that construction has been delayed "due to current challenges with building materials as a result of the pandemic, especially lumber." There is no updated timeline for when construction could begin. 

Tesla has also linked solar-powered homes in Southwest Australia in a virtual power plant. The 50,000-home, 250 MW project has been credited with helping to maintain grid stability, including during a 2019 incident when a coal-fired power plant temporarily went offline. 

Earlier this year, Tesla announced that it would package the Powerwall with Solar Roof sales as part of a push to increase its share of the U.S. residential storage market. The company also recently launched a sales page for its Megapack utility-scale storage product, which had previously been sold business-to-business. The company is inviting Powerwall owners in California to participate in a distributed battery system that would also create a virtual power plant.

Walters said the SunHouse project will be a good opportunity for Tesla to learn how its products impact the overall load of a neighborhood and how it could build its energy products at a larger scale. With the relatively high cost of the Solar Roof, he said, direct partnerships with developers and utilities could help address consumer concerns while giving the company a greater market share. 

"Partnering with residential developers to put Solar Roof on new high-end housing developments makes a lot of sense because then it becomes an attractive feature of a new home without drawing attention to its high cost," he said. 

Article top image credit: Permission granted by Mississippi Power

The costs to non-solar owning customers of net energy metering (NEM) policies that support rising levels of rooftop solar in more than 29 states have created division between utilities and DER advocates, but elements of a new policy that can balance the cost shift with system benefits for all customers are emerging, power system analysts say.

Distributed solar owners in many states pay only for the net kilowatt-hours on their meters after compensation for exported solar-generated kilowatt-hours is deducted at the retail electricity rate. This NEM policy does not significantly shift system costs to other customers at low solar penetrations, but the accelerating growth of distributed energy resources (DER) is creating growing concerns about a cost shift from customers who own solar to those who don't.

NEM "is a useful tool, but it's just a tool," Edison Electric Institute (EEI) General Counsel and Senior Vice President for Clean Energy Emily Fisher told a Feb. 9 National Association of Regulatory Utility Commissioners (NARUC) Winter Summit audience during one of three panels on NEM. "There are ways to reform it to allow even greater benefits from DER and still avoid imposing a cost shift."

DER advocates at the conference agreed NEM must evolve.

DER can be "leveraged for many grid services critical to achieving zero emissions goals," Strategen Managing Director for US Consulting Matt McDonnell said. But "rate designs need to evolve to more fully integrate DER for those services or we will miss taking advantage of customer investments, overbuild the system, and fewer customers will face larger fixed costs."

Discussions about an NEM successor tariff to sustain DER growth has, until recently, led only to controversy. But NARUC summit presentations suggested there may be some emerging consensus on policy elements like adding incentives for storage. And a new South Carolina proposal involving Duke Energy offers a "holistic product bundle" that could lead to "new possibilities," according to summit panelists. 

Action aplenty

An NEM successor tariff becomes important when DER penetrations of over 5% of system peak load threaten to impose significant costs for system infrastructure on non-solar owning customers, "and more states are moving toward that level," said North Carolina Clean Energy Technology Center (NCCETC) Senior Policy Program Director Autumn Proudlove.

Legislative and regulatory policy actions on distributed solar steadily increased from 2015 to 2020, Proudlove told the NARUC summit. In 2020, DER compensation was the focus of 92 actions in D.C. and 34 states, up from just 41 actions in 26 states in 2015.

Annual solar growth was forecast to be "10% to 15% between 2023 to 2025" without extension of the 30% federal tax credit, according to the Q4 2020 U.S. Solar Market Insight Report, published Dec. 15 by the Solar Energy Industries Association and Wood Mackenzie. The credit's extension in the December COVID relief bill is expected to increase DER growth even more and sustain it longer.

That growth increases concern about the cost shift, NARUC panelists said.

"When low-cost renewables penetrations rise, more of the costs in rates are not for generation but for maintaining, expanding, and running the grid," said Natural Resources Defense Council (NRDC) Climate and Clean Energy Program Senior Scientist Mohit Chhabra. When solar owners pay less, "system costs fall on other customers."

The cost shift tends to create an "equity problem" when those costs fall disproportionately on low and moderate income (LMI) customers, Chhabra added.

A wide range of alternative tariff strategies are being tested, Proudlove said. The most common proposals are moving away from the retail rate, and more frequent "netting" of credits, "which more accurately reflects system costs but is more difficult for customers."

Credits can be netted as infrequently as annually or as frequently as hourly intervals. The less frequently they are netted, the easier it is for customers to accumulate compensation, but the more frequently they are netted, the more accurately compensation reflects the system's real-time use of the distributed solar and the less predictable and apparent the customer's compensation will appear.

Also being considered to address the cost shift are time-of-use (TOU) rates, fixed fees like minimum bills or DER system capacity charges, and value of DER studies, she added. But there is no "real consensus" on which is best, she added.

DER advocates say properly compensating DER customers is necessary as they provide invaluable grid services that reduce system costs, Proudlove said. And utilities say utility-scale solar, now at a much lower cost almost everywhere, is more cost-effective than distributed solar.

But "it is not an either-or situation" because we need all solutions for reducing emissions, Solar Energy Industries Association Senior Director of Utility Regulation and Policy Kevin Lucas told the NARUC audience. NEM's "simplicity" for customers has allowed the rooftop solar solution to grow and regulators should not "create barriers" to state decarbonization efforts.

States at work

The NARUC conference panelists described the wide range of state trials of NEM successor tariffs.

Hawaii, the first state with distributed solar penetrations high enough to threaten system stability, struggled for years to design a successor tariff, Synapse Energy Economics Principal Associate Melissa Whited said. But regulatory rulings in October 2015 and November 2017 led to a TOU rate design for residential customers that is now shifting Hawaii's solar installations to solar plus battery systems.

In contrast, Georgia just started a retail rate NEM trial last year while Connecticut announced its first successor tariff Feb. 10. In Vermont, NEM is on its fourth iteration and "provides almost 30%" of the state's peak load, Commissioner Sarah Hofmann of the Vermont Public Utilities Commission said. But growth is now imposing transmission system constraints in Vermont and creating a need for a locational value in the tariff, she said.

California is now working on an NEM 3.0 successor tariff and looking for ways to use the time-based and location-based components of compensation, stakeholders recently told Utility Dive. A joint utilities proposal focuses on the cost shift, with solar owner-only charges. Solar advocates have proposed more targeted TOU periods they say would more accurately reflect the value of DER to the system and compensate solar owners for adding storage.

New York uses wholesale market time- and location-dependent granularity for its Value of DER tariff, Regulatory Assistance Project Associate Mark LeBel said. But that does not resolve cost shift concerns in states without wholesale markets or resolve questions in New York about other rate components like time intervals.

Emerging limited consensus

Ratemaking is "as much art as science," and the best way to structure an incentive for rooftop solar is through rates with both fixed and variable time- and location-based value components, NRDC's Chhabra said. 

But locational value "can be very difficult" without transparent wholesale market nodal pricing, he agreed with LeBel. And a January 2021 study of California's current NEM, which includes a time-based value in its mandatory TOU rate, concluded there is a cost shift allowing residential solar owners, the majority of net-metered customers, to pay less than the cost to serve them.

"Rates should be based on costs, and a fundamental principle of ratemaking is to avoid shifting costs," EEI's Fisher said. Utility-scale solar "is way less expensive" than distributed resources and also displaces emissions. Compensation for DER "should be based on where and when they produce" and NEM "is not the right tool."

The common ground that emerged among most NARUC panelists was that cost shifts must be prevented, and time-based and location-based valuation of DER is important to identify its precise value to the system at any specific time or place. They also agreed that carbon emissions need to be addressed and that the flexible use of DER can be critical to power system reliability.

"Policymakers know that DER growth is accelerating and there is value in rate design to integrate it into core operations," Strategen's McDonnell said. "That will grow with implementation of the Federal Energy Regulatory Commission Order 2222, which requires bringing DER into wholesale markets."

There is consensus among stakeholders on "more sophisticated successor tariff design elements" that more precisely reflect DER value to the system, McDonnell said. The newest successor tariff proposals tend to have more granular export compensation and netting intervals to make price signals accurate, non-bypassable charges to share the costs of public benefit programs equitably, and structures like TOU rates that drive self-consumption, he added.

Solutions for locational value are being trialed, he added. One is using interconnection or integration costs as proxy price signals, which fits with California's requirement that utilities identify the best areas to add DER. Another is Vermont's compensation adders for adding DER at agreed-on higher value locations.

Beyond these points of agreement, specifics of a successor tariff design are limited. But "the future will be integrated DER compensation through a tariff design that links all factors that impact system value, including things like non-wire solutions," McDonnell said. That should also include social justice objectives, "because this can't just be a transition, it has to be a just transition."

Jurisdiction by jurisdiction, "the core regulatory principal of gradualism will guide a methodical transition toward optimizing DER compensation," he added. "That will require better market valuation of flexible DER to allow new and more sophisticated tariff solutions."

But a policy jointly proposed by Duke Energy and DER advocates in South Carolina could represent a new compensation paradigm, most NARUC panelists agreed.

A holistic product bundle

The proposed settlement in response to South Carolina's current NEM structure was specifically designed to end the cost shift debate, said Duke Energy Vice President for Rate Design and Strategic Solutions Lon Huber.

"Our solution links a TOU rate with dynamic critical peak pricing, and new netting periods with an upfront rebate for participation in Duke's demand response and energy efficiency programs," said Huber, who represented the utility in the proposal's development.

If approved by South Carolina regulators, it would grow DER, reduce utility peak demand challenges, and support policy goals without imposing costs on other customers, NCCETC's Proudlove said.

The proposal provides dispatchability to meet winter peak demand more reliably through controllable DER, "which starts to drive more system value," Huber said. The concept's "technology coupling" will enable an "innovative and holistic product bundle," he added.

The proposal is "the exact opposite" of NEM's "bluntness," EEI's Fisher said. It "aligns DER deployment with larger clean energy goals instead of throwing DER anywhere, adding to curtailment issues, and imposing costs on the distribution system." 

If approved, "it could be a model for other states to move past the old cost shift debates," she added.

The holistic South Carolina concept "opens up a lot of new possibilities" by bringing in elements like demand response and multiple dynamic rates, Proudlove said. "It also showed different stakeholders can collaborate and agree, and that is in short supply in today's regulatory processes."

The holistic South Carolina approach to NEM and the cost shift has added to questions about how to address DER in today's regulatory paradigm.

Unanswered questions

Holistic solutions like the South Carolina proposal "should be on the table, but a better rate can provide most of the solution" to the cost shift, NRDC's Chhabra said. A way to remove barriers to LMI customer owning solar "without raising rates," for example, is "an equity charge to existing residential solar customers" that have paid off their initial investment under retail rate NEM.

Another approach to replacing retail rate NEM that faces pushback was proposed by NARUC panelist and E&E Legal's Director of Science and Technology Assessment Tom Tanton. He would introduce an auction process to set the price for DER.

"The preferred way to set value, but it is too complex, is an auction approach that would show the value of flexibility and other resources to customers," Tanton told Utility Dive. The South Carolina proposal and any other kind of innovation that builds compromise among stakeholders is acceptable if there is "a strong consumer advocate voice in the process," he added.

That would not eliminate the cost shift, but would be a negotiated agreement based on the "true cost of service" in which the utility's needs and the provider's costs are accepted by the consumer advocate, Tanton said.

South Carolina regulators now face what has in the past been challenging, which is "getting a holistic approach through the regulatory system's traditional single-issue dockets," Duke's Huber said. 

With regulators' ability to innovate limited by executive, legislative and judicial supervision, introducing new approaches "is a huge challenge," Proudlove agreed. "Utilities might be able to introduce pilots of new approaches for DER in large grid modernization proceedings, but it may ultimately be necessary to educate policymakers to enable the regulatory process."

Article top image credit: San Jose Inside

Where do today's load management activities - including demand response, energy efficiency, and renewable energy programs - fit in a distributed energy resource (DER) future of non-wires alternatives, storage and more? A recent publication titled “The Future of Distributed Energy Resources: A PLMA Practitioner Perspectives^TM Compendium” details eight industry initiatives where leading utilities are partnering with their customers and allies to demonstrate the path to a more integrated approach to DERs.

Peak Load Management Alliance (PLMA) members, utility companies, consultants, and vendors have deep experience in delivering practical solutions to the operational requirement to balance resources and loads. And while the first 100 years of the energy industry was focused on matching resources (generation) to loads, the next several decades will be focused on flexible loads efficiently meeting generation output at both the Transmission system and Distribution feeder level, incorporating renewable, distributed and intermittent resources. We are moving into the realm of dynamic management of the system every day. The last decade has seen a rapid increase in behind-the-meter solar installations; recent advances in battery and thermal storage, electric vehicle (EV) charging, and load flexibility resources are also indicators of the growing importance of distributed energy resources (DERs).

The PLMA community has a history of sharing experiences that enable others in the industry to understand, learn, and embrace industry change. In keeping with this mission, PLMA asked its membership to share case studies about current DER activities and projects. The initiatives detailed in the Compendium are:

• Planning/Foundational Category – Defined as those utilities taking bold steps to leapfrog pilots/technology straight to integrative planning and procuring, and change management.
  • Hawaiian Electric's Integrated Grid Planning, Hawaiian Electric Company
  • Distributed Resource & Flexible Load Study, Portland General Electric and Navigant
  • Integrating DER Planning, Research and Program Development, Tacoma Power
• “DR Plus” Category – Defined as customer-sited assets (with or without the involvement of an aggregator) to monetize DER operations for utility/grid benefits to a growing spectrum of network problems.
  • Deriving New Wholesale Market Revenue Opportunities and Maximizing Customer Utility Savings with Behind-the-Meter Distributed Energy Resources, Center for Sustainable Energy, Tesla, Conectric Networks, and Olivine
  • Expanding National Grid’s ConnectedSolutions Program to Include Energy Storage, Sunrun, EnergyHub, and National Grid
• Microgrids Category – Defined as customer-sited assets that have great degrees of flexibility and opportunity for monetization.
  • Microgrid Enables Military Facility to Participate in Utility Services, Eaton
  • Energy Storage and Microgrid Performance in Non-Wires Solutions and Other Demand Management Programs, Enel X
• International Category
  • First Movers in DER in Colombia, U.S. Energy Association

If management is asking "where do today's load management activities (including DR, EE, and renewable energy programs) fit in a distributed energy resource (DER) future?" the eight case studies in the Compendium offer a glimpse into the future that is unfolding today. If imitation is the sincerest form of flattery, then now is the time to embrace progress through plagiarism. Here, PLMA members provide the blueprints for utilities, regulators and service providers to follow. Read the Compendium at www.peakload.org/plma-publishes-future-of-der-compendium.

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.

There are now about 15 million smart thermostats, 2 million distributed solar installations, and 1.5 million EVs — and growth is forecast to continue, EnergyHub reported last October. "EEI forecasts that 18.7 million EVs will be on the road by 2030," according to Frader-Thompson.

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.

Utility-customer cooperation

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.

Customer cooperation

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."

 

Article top image credit: Photo illustration by Brian Tucker/Utility Dive; photograph by jhorrocks via Getty Images

Texans were left in the cold and dark this February, following extreme cold weather that had the Texas competitive energy market unable to prevent deadly power failures. Leaving behind its historic commitment to power system independence and joining the larger U.S. grid can relieve some of the consequences of extreme weather events Texas is likely to see again, many energy analysts in and out of Texas said.

"We designed this system for Ozzie and Harriet weather and we now have Mad Max," said Texas energy consultant Alison Silverstein, a former Public Utility Commission of Texas (PUCT) and Federal Energy Regulatory Commission (FERC) adviser, during a Feb. 24 webinar cohosted by the Advanced Power Alliance and Conservative Texans for Energy Innovation. "Texas is now reaping the bitter harvest of avoiding federal transmission regulation and state energy sector regulation."

The Electric Reliability Council of Texas (ERCOT) competitive, energy-only market "seemed like it was saving money until last week, when losses equaled the cost of three years of generation," agreed Rice University Associate Professor of Civil and Environmental Engineering Daniel Cohan. "The free-market ideology ignores risks. Most people want to keep the lights on more than to make a market theory work."

All types of generation, especially natural gas, failed, analysts have widely acknowledged. Leaders must enforce weatherization and build cooperation among the PUCT, ERCOT and municipal authorities to address future crises, many have added. But for its best future, Texas should also consider expanding demand-side resources and connect with out-of-state markets, because the benefits can justify the investments, analysts said.

What actually happened

The average Dallas, Texas, low temperature for February is 39°F. But from Feb. 14-16, 2021, temperatures were significantly lower.

On Feb. 11, power sector agencies began preparing for demand spikes, according to the PUCT. ERCOT asked customers to limit usage on Feb. 14 and announced generation capacity losses and outages starting Feb. 15. Boil water notices and reports of outage-related deaths soon followed.

Early on Feb. 15, when system frequency fell to 59.3 Hertz, the grid was less than 5 minutes from a cascading statewide blackout, ERCOT CEO Bill Magness said at a Feb. 24 ERCOT board meeting. ERCOT called a load shed event that lasted 70.5 hours, according to ERCOT's documentation.

Peak load and outages were significantly higher than Texas has seen, said ICF Wholesale Power Market Advisory Manager Patrick Milligan. Though wind and solar are increasingly important factors in the Texas power system, "they were not a big part of the overall story because both produced generally above the low levels forecast for them."

A data "snapshot" for the morning of Feb. 15 proved accurate for the whole event, Milligan said. The bulk of the "missing capacity" was from natural gas and coal generation outages as well as the loss of about 1.35 GW of nuclear power, he found. "Natural gas production in Texas dropped at least 16% due to frozen wells and plant shutdowns."

It was a cascading failure of all generation types and a failure of transmission at all levels, said Michael Jewell, an advisory board member at Conservative Texans for Energy Innovation and managing partner of energy and infrastructure policy consultant group Jewell & Associates during the Feb. 24 webinar.

Six ERCOT board members including Chair Sally Talberg resigned and another withdrew his candidacy. "I welcome the resignations," Gov. Greg Abbott, R, said. "The lack of preparedness and transparency at ERCOT is unacceptable. We will ensure that the disastrous events of last week are never repeated."

But others said more blame should be attributed the the governor. Energy experts, Texas Democrats and others, "were warning of this for years," former Texas congressperson and senate candidate Beto O'Rourke tweeted Feb. 16. "Abbott chose to ignore the facts, the science and the tough decisions and now Texans will once again pay," he added.

There has been a lot of discussion about what some Texans paid for electricity during the freeze.

About those thousand-dollar bills

In regulated electricity markets, regulators keep rates stable, but in "energy choice" markets like Texas, retail electricity providers (REPs) compete for customers and most of Texas' PUCT-certified REPs offer fixed and variable payment plans. February 2021 demand drove ERCOT's average January real-time $20.79/MWh energy price to an average of $6,579.59/MWh and, at moments, to the PUCT-imposed $9,000/MWh cap.

Some customers discovered variable bill plans can come with price spikes. Houston's Lisa Khoury filed a $1 billion class-action suit against REP Griddy Energy over a $9,546 electricity bill. Other residential customers got $4,000, $5,000, and $7,000 bills. Denton Municipal Electric's $207 million power bill was nearly its $231.4 million annual budget. Brazos Electric Power Cooperative, Texas' biggest co-op filed for bankruptcy. 

"The theory is that a high price will bring investments, but people don't invest in things that might only make money sometime in the future unless they are required to," said Jussi Heikkinen, North America Director of Growth and Development for global power plant developer Wärtsilä.

Many choice customers were urged to change plans as the crisis emerged and the biggest responsibility for the economic burdens should fall on regulators, Griddy and other choice providers said in public statements.

"Markets with guardrails can work if they are managed well, but we have managed the ERCOT casino badly and imposed risks on Texas customers," Rice University's Cohan said in the webcast.

"Retail markets did not cause the Texas power outages, and the exact same thing would happen if it was in a regulated structure," former FERC Chair and GridPolicy CEO Jon Wellinghoff disagreed. "Texas does not need to do away with retail energy choice. It probably needs better oversight to ensure that consumers understand the risk, but they should be allowed to take risks if they are fully informed."

Three big fixes

Avoiding future outages involves addressing multiple related issues and "thinking bigger" about what the changing climate and rising renewables penetrations require, Silverstein said.

Transmission

Texas' historical opposition to FERC regulation has made it an "electrical island," ERCOT CEO Bill Magness said in a 2016 interview.

Renewables were more than a quarter of Texas electricity generation in November 2020, based on DOE data. With ERCOT's increasingly dynamic supply and load, Texans may prefer being able to access out-of-state markets, even under federal regulation, to being without electricity, Silverstein said. 

Texas should "immediately start negotiations to interconnect with the rest of the country," Wellinghoff said. "That's the fastest route to thousands of MWs of support and it would allow Texas to profit by selling its now-curtailed thousands of MWs of West Texas wind into other systems," he added.

"It is not a political issue," he insisted. "There are no red or blue electrons. This is about saving money and keeping consumers safe."

Texas leaders should also immediately order a study to identify the true costs and benefits of interconnection, both Silverstein and Wellinghoff added.

ERCOT, the PUCT, and the New York grid operator have testified to FERC that wide geographic access to diverse resources strengthens reliability and lowers costs, said Grid Strategies Vice President Michael Goggin. Those benefits were demonstrated in the MISO and PJM markets during the January 2019 Polar Vortex, he said.

In February, the "network inside Texas allowed solar, in-land wind, and coastal wind to work together," Goggin added. "More inter-regional transmission connecting ERCOT, MISO, PJM and the West could have relieved the shortages."

"In times of trouble, it may be that your neighbor or your neighbor's neighbor can help," said Energy Systems Integration Group (ESIG) Associate Director Debra Lew during a Feb. 23 webinar introducing ESIG's white paper on the urgent need for national transmission planning.

ESIG is a global energy industry consultant to power providers, developers, planners, and regulators.

The transition to a renewables-dominated, zero-emissions economy is accelerating, but transmission development is not keeping up, ESIG's Transmission Planning for 100% Clean Electricity reported.

An example is Pattern Energy's 2 GW Southern Cross transmission project to interconnect Texas with Louisiana, Mississippi and the MISO system. First proposed in 2011, construction has not begun, though both FERC and PUCT approvals of the high voltage direct current line "do not affect ERCOT's independent status," Pattern Vice President of Business Development Glen Hodges said.

"The ability to import up to 2 GW of power into Texas during such a crisis would be a tremendous benefit to stability of the ERCOT grid" and "a huge help to Texas consumers," Hodges added.

With unpredictable events and high power prices becoming more common, planners should recognize that inter-regional transmission allows responding "to anything, anywhere," Goggin said.

Planning

But ERCOT does not plan with load or supply forecasting scenarios informed by science-based, climate change-driven extreme weather, Silverstein found in her May 2020 study of the system operator's planning practices.

The freeze raised "legitimate questions" about ERCOT forecasting and modeling datasets because actual conditions "blew through" the forecast, ICF's Milligan said. Whether or not the Texas event was due to climate change, planning models too often overlook critical new correlations in extreme weather events, he added.

"It is not that ERCOT failed, but that new inputs to planning models may be needed," Milligan said. Higher load and increased outages "are not always completely independent of one another" and new broad conditions like fuel supply shortages or weather "can cause widespread outages."

Correlated outages simultaneously affecting many generators have occurred in "about a dozen similar events over the last decade" around the country, Goggin added. "Planners don't recognize correlated outages in extreme weather events, but correlations in planning can show "the value of generation diversity" and confirm that "because all energy sources can be disrupted, being overly dependent on any one isn't wise."

Customer-owned resources

Texas must also ensure adequate market rules, mechanisms, and financial structures to allow distributed resources to provide system services, former FERC Chair Wellinghoff said. The ancillary services market in Texas spiked during the event "because barriers and prohibitions keep the full array of resources from being utilized in the market."

Texas needs a "demand response-energy efficiency-energy storage package" across the state, starting with low income and multifamily housing to address social, health and economic issues," Silverstein agreed. "Energy efficiency is even cheaper than renewables and creates more jobs, which also makes it good politics."

With smart energy management devices, distributed resources can act as "automated demand response" and "buffer the variability of ERCOT's high renewables grid," she added. "ERCOT can take advantage of customer-owned resources as ancillary services products and encourage aggregators to provide them."

But Texas may not be ready to go to work on these opportunities yet, Silverstein said. "We're still in the hand wringing phase, but the next step is to stop looking for villains and start looking for solutions."

 

Article top image credit: The image by TimothyJ is licensed under CC BY 2.0

Acceleration of the growth of distributed energy resources (DER) has power system analysts anticipating big changes on utility distribution systems in 2021 and throughout the 2020s.

Continued falling prices of DER, ambitious new state and federal policies, and customer demand in 2021 will drive growth, power industry representatives said. And while utility-scale renewables growth will still boom, DER, including rooftop solar, batteries and electric vehicles (EVs), can be central to protecting reliability, according to a new Southern California Edison (SCE) paper describing the evolution of tomorrow's grid.

SCE’s Reimagining the Grid "is to help establish where and why we should turn right or turn left in building a distribution system to address evolving needs," said SCE Vice President of Asset Management, Strategy & Engineering Paul J. Grigaux. Those turns "will be determined by the growth of distributed resources and we want to have the system technologies to see and manage their impacts."

"We're reaching a threshold where distributed energy resources add up to enough megawatts to matter," Brattle Group Principal Ryan Hledik added. "And the idea of managing them in an aggregated coordinated way is being taken more seriously now."

There is likely to be much more attention in 2021 on proposals like SCE's for a future distribution system that can use DER to provide grid services, other power system analysts agreed. That attention is now needed because the DER are increasingly showing up and will accelerate in the coming year, the analysts said.

Growth and trends

Concrete predictions about growth are difficult only because economies of scale are driving costs down and growth up faster than forecasts can be made, according to DER advocates.

Prices continue to steadily fall, the December 2020 Lawrence Berkeley National Laboratory distributed solar data update confirmed. From approximately $12/watt in 2000, prices had fallen in 2019 to between $2.30/watt and $3.80/watt, depending on system size and market.

Residential solar 2020 installations were forecast by the 2020 Q4 SEIA-Wood Mackenzie U.S. Solar Market Insight Report, released Dec. 15, to have "13% growth in 2021." And that was before the recent extension of solar’s federal tax credit, which will help drive even greater growth into the early 2020s.

The COVID-19 relief bill’s functional extension of the tax credit through 2025 and anticipated further clean energy support from the Biden administration and a Democrat-controlled congress are likely to accelerate distributed solar growth and cost declines, analysts agree.

The newest policies to compensate solar include incentives that will also drive distributed battery storage growth, according to Autumn Proudlove, senior policy program director for the North Carolina Clean Energy Technology Center (NCCETC) policy quarterlies on solar, grid modernization and electric vehicles (EVs).

"Increasing growth is the biggest thing expected for storage in 2021," Energy Storage Association (ESA) Vice President for Policy Jason Burwen agreed.

The U.S. energy storage market is set to grow from 1.2 GW in 2020 to nearly 7.5 GW in 2025, representing sixfold growth, according to December’s Q4 2020 ESA-Wood Mackenzie Energy Storage Monitor. The total market value is forecast to cross the "$1 billion annual threshold in 2020" and "be a $7.3 billion annual market in 2025," the report added. 

"This year’s installations alone almost match cumulative U.S. battery storage, and 2021’s total capacity is forecast to reach over 3.5 GW," Burwen said. Residential storage represents about 20% of growth, he added.

The cost of battery storage has also declined "much faster than predicted, and will continue in 2021, though the curve may decline more gradually," he said.

FERC Order 2222, approved Sept. 17, requires wholesale market operators to develop rules and tariffs for DER, and is therefore expected to eventually bring aggregated distributed storage into wholesale markets, but the 2021 focus will be developing compliance filings, Burwen said. ESA will be working on that and "other ways to allow better utilization of behind-the-meter storage for grid services."

At the state level, key 2021 proposals will be Arizona’s value of DER tariff and Connecticut’s storage program design, Burwen said. "Progress will be state by state because some state regulators and lawmakers will lean forward on this and others will not, and progress is most often in response to regulatory pressure."

As the penetration of EVs grows, their load will eventually also be a major factor on the distribution system.

Though all car sales slowed sharply in 2020, Q3 2020 EV sales, led by California, were up nearly 60% from Q2 2020 and down only around 3% from Q3 2019, according to transportation electrification advocacy group Veloz.

But a "five-fold growth" will still take 2020’s 1.4 million EVs sold in the U.S. to 6.9 million units in 2025, according to a Nov. 19 report by global business research and consulting firm Frost and Sullivan.

Important transportation electrification policy priorities in 2021 will be returning to Obama-era tailpipe emissions standards and setting new financial and non-monetary incentives that drive growth, Boone added.

Federal action on EVs is likely to increase with Democrats controlling the White House and Congress. President-elect Biden, his Secretary of Transportation nominee Pete Buttigieg, and incoming Senate Majority Leader Chuck Schumer, D-N.Y., have described ambitions to expand transportation electrification.

But state mandates for EV procurement like those that drove renewables growth are the current emerging trend, NCCETC’s Proudlove said. At least 11 states are working on EV adoption policies that will add to growth, according to NCCETC’s Q3 2020 policy update, released in November.

This cumulative growth of solar, storage, EVs and other DER can lead to integration of new load in a way that supports the system and is a bigger part of system planning, Proudlove said. "It will be important to understand the effects on demand and load and on the need for distribution system modernization, and recent state utility commission proceedings about flexibility are likely to increase in 2021."

The new grid

Advancing a discussion about distribution system modernization will require alignment between utilities and DER advocates, Proudlove said.

The next phase of a debate that started with SCE’s 2018 rate case is leading to that kind of alignment, SCE’s Grigaux said. The California Public Utilities Commission "and other stakeholders see a new future evolving very quickly because of what's happening in the customer-driven marketplace in response to climate adaptation and technology costs and technology advances."

Greater reliance on variable wind and solar resources will require managing "challenges to safety, grid stability, asset condition, reliability and resilience," according to SCE’s recent white paper, the newest addition to its Pathway 2045 vision of how to meet California’s net zero emissions by 2045 mandate.

The direct impact of the growing "frequency and magnitude of climate-driven disruptions" will drive grid "evolution" by increasing customer demand for DER, the paper said.

Impacts of climate disruption and customer adoption of DER will vary by location and depend on things like urbanization, demographics and infrastructure, and "grid planning, design and operations will need to evolve," the paper continued.

The challenge of "inverter-based customer-owned technologies such as distributed solar and batteries is that their fluctuations can impact system voltage and frequency and threaten system stability," Grigaux said.

The utility needs visibility into "how the grid is operating at any node in the system to be able to respond to disturbances or outages," he said. "Today’s inverters and current technology limit that visibility," and the growth of system variability "will require a higher performing communications network."

There will be a new need for "more region-specific, ‘modular’ grid designs" and for strengthened "forward radar" to foresee customer adoption of technologies and the system issues they present, the paper said. Planning must take a "multiple scenario-driven, adaptive and more proactive approach using probabilistic analyses" to create "system flexibility" to address "future uncertainty."

A "reimagined" system must have the sensors, and communications and analytic technologies to provide "a targeted real-time response" to changing load, supply, and infrastructure conditions created by increasing amounts of DER, the paper added.

Building this "intelligent secure information and operations network" to manage DER and the poles and wires to support it "will require significant investment," Grigaux said. The paper is intended to make 2021 a year in which stakeholders’ "collective commitment to new technologies" grows and regulators and policymakers begin to understand the obstacles "to deploying the needed technologies."

SCE’s proposal is at the "cutting edge" of distribution system planning, Vote Solar Senior Director for Grid Integration Ed Smeloff said. "It builds on successes in New England and other states that allow customer resources to provide grid services, but I have not seen anything this advanced."

Preparing to "orchestrate DER flexibility is complex," Smart Electric Power Alliance Director of Research and Industry Strategy Brenda Chew added. "This is a design for a granular, forward-looking capability that can allow the situational awareness to anticipate changes in technology adoption and prepare to manage them."

Analysts say SCE’s vision can be put to use in two key ways.

Uses of the new grid

The distribution system envisioned by SCE can use today’s just emerging DER penetrations in 2021 for load flexibility, customer engagement, peak demand reductions and new infrastructure cost deferments, analysts said. And soon, SCE’s vision will enable DER as energy supply.  

"Regulators have already approved utility expenditures for incentives to customers for use of their DER for grid services, and that trend should not slow in 2021," Brattle Group Principal Ryan Hledik said. "Those programs are now reducing costs to ratepayers for distribution system upgrades and allowing utilities to increase system flexibility by offering customers new products and services," he said.

Regulators are also likely to consider performance rewards to utilities in 2021 for load flexibility offerings, Hledik said. "Where regulators see the system benefits of load flexibility but their utilities remain reluctant to support DER, regulators may pressure utilities to do more this year."

That may include trials of a new concept that couples a fixed bill with residential customers' DER technologies in return for participating in load flexibility programs, he added.

The SCE paper describes what different distribution systems will need as DER evolve at different times across the country, said Newport Consulting Managing Partner and former SCE Vice President for Advanced Technologies Paul De Martini. He co-originated the use of the "walk-jog-run" concept to describe the emergence of DER and other new power system technologies.

Places like California are "in the jog phase with DER and by the end of this decade will be into run mode," De Martini said. "The bottlenecks to the future everybody wants will be the areas of high DER penetrations on the existing distribution system."

DER can be a valuable source of flexibility now, but there is a "false narrative" that DER can make it unnecessary to do "significant physical upgrades," he said. "The real value from distributed resources is the energy and capacity value on the supply side," but that will require better wires and poles along with new control technologies and better planning to realize that value.

Customer demand will make energy supplied by DER "much more than a marginal contribution," but using it "will require thinking about the distribution system in a different way," De Martini said. Paired with utility-owned or customer-owned storage, it can be "a firm resource that can be scheduled and used as supply, it can be shaped and compensated and lead into a new realm of DER value in which it is much more than a load modifier."

SCE’s paper articulates the need for investments in advanced information, operations, communications and control technologies in the near, mid and long terms, he said. There will also be a need for investment in physical infrastructure, and for planning that recognizes "how much DER will grow and preparation to unlock its potential."

"The progress of DER is unlikely to slow in 2021 or after because customers will continue to want them," De Martini said. "There is likely to be exponential growth as innovation makes these technologies more cost competitive and capable, and that means power system planners must be ready to use thinking like the ideas in SCE’s paper to enable these technologies."

Article top image credit: Enel X

Utilities are pushing for a bigger role in integrating distributed energy resources (DER) in their service territories, saying their ownership would benefit customers. They also see economic opportunity and other advantages in the flexibility of DER, which is becoming vital in today's power sector transition.

"Utilities are now critical in decarbonization and, as power grid experts, they are leading innovation," said Duke Energy Vice President of Rate Design and Strategic Solutions Lon Huber. "All clean energy options should be on the table, and if a program is structured in a way that provides benefits to all customers — participants and non-participants — it is a win-win that should be pursued."

Meanwhile, a new study from the Department of Energy's Lawrence Berkeley National Laboratory finds benefits of utility DER ownership, though private sector advocates say the data may not tell the whole story.

Utilities competing against private providers exposes shareholders to unnecessary risk, former Federal Energy Regulatory Commission Chair Jon Wellinghoff said, reaffirming his 2015 position, which was cited in the LBNL study. Utilities should instead "host" the "grid marketplace" and "allow third parties to bear the risk of selling DER to end customers," Wellinghoff wrote in a 2015 op-ed.

Though many regulators have accepted utilities' move from traditional, centralized generation to utility-scale renewables, until recently states such as Mississippi and Florida have seen utility DER ownership as intruding in the private market.

But a debate in Florida over whether utilities should be allowed to own community solar may foreshadow a shift in power sector dynamics.

Rooftop solar could increase utility shareholder earnings

Utility-owned rooftop solar programs could increase total shareholder earnings by 2% to 5% over 20 years, LBNL modeling found, compared to an estimated 2% loss over 20 years from the same amount of customer-owned or leased rooftop solar.

Shareholder benefits come largely from ratepayer-paid returns for utility capital expenditures on solar and from limiting compensation to private, net-metered solar owners, LBNL found.

Under LBNL's scenario, rates increase due to additional utility spending, but only by 2%, comparable to the 2.2% bill increase non-rooftop solar customers would see because of net metering compensation and other costs, LBNL Research Scientist and study co-author Galen Barbose said.

"Shareholders win and customers break even in our base case assumptions," Barbose said.

Less certain assumptions could further improve the value proposition for utilities, he added. Better visibility and control of solar, lower interconnection costs, and potentially deferring system upgrade costs, could all make it "a win for utilities and a marginal win for customers."

The role of regulated utilities in private markets "raises thorny policy questions for regulators and stakeholders," Barbose acknowledged. But this study addresses "a simple and perhaps threshold question of the basic economics for utilities owning rooftop solar."

As the market moves beyond early adopters, there is some logic in utilities owning DER when the value proposition is potentially neutral for customers and better for shareholders, Rábago Energy Principal Karl Rábago, a former Assistant Secretary of Energy and Texas utilities commissioner acknowledged.

But utility ownership is only "the second-best solution," Rábago said. Shareholder and non-participating customers benefits are small and should not justify allowing DER ownership by "institutions which typically innovate more slowly and at higher costs than the competitive market."

Solar installers oppose utility interference

Not surprisingly, solar installers agree with Rábago. The private market is "the best way to achieve cost reduction and innovation," Sunrun Chief Policy Officer Anne Hoskins said. Utilities' best role is in "enabling network access." 

Sunrun is working on virtual power plants and non-wires alternatives in which utilities will "play a central role" but will not own the resources, said Hoskins, a former Maryland utility regulator and utility executive.

Utilities do fill one key role in distributed solar ownership, Rábago, Hoskins and Huber agreed — addressing underserved or hard to serve markets.

That "is the reason utilities were given monopoly franchises," Rábago said. "LBNL's paper shows there is not a legitimate shareholder argument against utilities owning solar in those markets."

The value proposition for utility-owned rooftop solar is especially strong for low income customers who lack the resources to invest in solar for themselves, and do not have access to community solar, Huber said.

Nevertheless, the private market has usually won regulatory protection because it is growing rooftop solar impressively, Hoskins said.

Utility-led rooftop solar programs have been approved in Arizona and Texas, and utility-led rooftop solar pilot proposals are pending before regulators in Arkansas and Mississippi. But many utilities are seeing greater benefit in community solar, leading to a shift in focus that raises the same ownership questions, said North Carolina Clean Energy Technology Center Senior Manager of Policy Research Autumn Proudlove.

This suggests the marginal benefits of rooftop solar ownership identified by LBNL may not be the whole story.

Arizona Public Service (APS) is methodically testing new use cases for its groundbreaking utility-owned rooftop solar programs, but concluded it has limited peak load reduction value, spokesperson Jill Hanks said in an email. APS, along with San Antonio's CPS Energy and Tucson Electric Power, all leaders in piloting utility-led rooftop solar pilots, are all now focused on community solar.

These proposals raise the question of what the appropriate boundary is between regulated and competitive markets. Florida regulators may soon need to define that boundary. 

Florida's community solar debate

Duke Energy Florida proposed a 749 MW Clean Energy Connection program in July that would give customers bill credits for community solar participation. Up to 65% of capacity will go to large business customers, 10% to local governments, 25% to residential customers and small businesses, and 28% to low income customers.

Some stakeholders, including solar advocates Southern Alliance for Clean Energy (SACE) and Vote Solar, agreed utility ownership was "in the public interest" after coming to an agreement with Duke on adding the carve-out for local government and low income customers.

The yet-to-be approved program is already fully subscribed, Duke's Huber said.

But other stakeholders fear the program will result in unfair rates. The program's design includes "numerous fatal flaws" and is "not in the public interest" because it would impose a "rate burden" of "several hundreds of millions of dollars" on the utility's non-participating customers, Rábago wrote in October comments. The program only benefits participating customers, making it "a subsidy program for the very few, and a travesty of the concept of community shared solar."

Duke contradicts this assertion, saying 12.7% of the projected $465.1 million in net benefits will go to program participants while 87.3% will go "to the general body of customers," in its filed comments.

But Rábago questioned the assumptions in these numbers about "value derived from avoided costs" for infrastructure building and maintenance by deploying community solar. Those assumptions are uncertain, "increasing the risk to non-participants," he wrote.

The proposal provides benefits that induce customers "not to pursue free market options" like rooftop solar and "reduces or eliminates the opportunity for competitive developers," Rábago added.

The program is structured to provide net benefits to all Duke Energy Florida customers and avoid any "long-term cost shift to non-participating customers," Huber responded. That is "because the cost of the solar is so low for larger installations."

Their disagreement reverses a long-standing debate about the value of solar.

Solar advocates have long argued that the true value of distributed solar includes the infrastructure costs utilities avoid when customers install it. Rábago said those costs are uncertain. Regulated utilities have long denied there are significant avoided costs from distributed solar.

But community solar does avoid infrastructure costs, Huber said. Duke's calculations are based on assumptions used by solar advocates, including Rábago, in value of solar proceedings across the country that typically include avoided costs as part of the value, Huber said.

Florida regulators may choose to protect the private market by ruling against Duke ownership of community solar. But they also may affirm a new "convergence" between utilities and the private sector in which a new generation of utility leaders may now be able to pursue utility ownership of DER more aggressively.

A potential convergence between regulated and free markets

The potential convergence is clear in Duke's agreement with stakeholders. In addition to its provisions for local governments and low-income customers, Duke commits to protecting retail rate compensation for rooftop solar owners' exported electricity through 2023, making the utility's solar "complementary to rooftop solar," SACE Solar Program Director Bryan Jacob said.

Duke will also consider using solar and solar-plus-storage systems to defer or replace investments in new natural gas generation. And its competitive solicitation for developers gives the private sector a role in the program, Vote Solar Southeast Director Katie Chiles Ottenweller added.

While Rábago sees utilities as a "second best" option for DER development, he also sees why parties are converging toward it.

"The distributed solar market is expanding and utilities don't want to lose that market share," Rábago said of the compromises in the agreement. "The LBNL paper adds the argument that there is shareholder value in distributed solar."

Duke's proposal demonstrates how once clearly partitioned markets "are now overlapping, intersecting and interacting through a series of convergences," he said. For example, "the cost of solar is now so low that even the relatively economically inefficient, traditional electric utility can make money for shareholders in this business."

Hints of these debates over utility DER ownership have been seen in Arkansas and Mississippi, and in the Colorado debate over Xcel Energy's ownership of community solar.

Solar has also converged with "things the utility has the regulatory and economic leverage to do something about," he added. "It can't do anything about things like natural gas prices, but it can attempt to control the solar market segment."

Utilities' ability to bring DER ownership proposals to regulators, and the low costs of distributed solar, are converging with utilities' growing need for distribution system modernization, Rábago said. They can now argue their massive capital investments in DER and system infrastructure are for reliability and resilience, but that spending will also accelerate returns and increase shareholder earnings, he added.

Finally, there is "a generational convergence in which utility management is, like much of the public, evolving," he said. As the generation of leadership that resisted DER growth retires, "new managers are emerging who do not see risks but opportunity" in distributed technologies.

"The LBNL paper is a postcard from the convergence that says owning assets on the distribution system is an opportunity," Rábago said. "Regulators may let utilities do this because it suits their jurisdictions, but that will erode the principle of the free market."

"We need to dramatically scale up dependable and cost-effective clean energy solutions to meet aggressive climate goals," Duke's Huber responded. Some solar advocates are "still stuck in the outdated 'If it is from the utility, it is bad' narrative," but Duke's innovative rooftop solar policy in the Carolinas and its intention to link storage with the proposed community solar program in Florida "show it is driving innovation," he said.

Regulators and policymakers should now recognize that "this kind of fundamental decision about regulated and competitive markets is before them, or will soon be," Rábago said. "Their answer will test their belief in free market principles against their confidence in regulated monopolies' ability to deliver value in this rapidly evolving market."

Article top image credit: RREAL

While the costs of distributed energy resources (DER) continue their remarkable decline, potentially more important new data reveals their growing value to both customers and the bulk power system, experts say.

Planning by utilities and system operators has traditionally been based on complex forecasts about bulk system factors like resource cost and customer demand to balance supply and load. Local resources have been an afterthought. A new modeling tool claiming unprecedented processing power and detail offers the potential for a new level of joint transmission-distribution planning strategy not undertaken before.

"I don't know how this modeling tool fits into regulatory proceedings, but it's unreasonable for regulators whose duty is to protect customer interests to not investigate it," said former Maryland utility commissioner and Sunrun Chief Policy Officer Anne Hoskins. "If I were still a regulator, I would ask our energy staff to determine whether the commission should require its study or use."

Technical documentation of Vibrant Clean Energy's WIS:dom-P modeling tool shows it offers significantly more granularity about where and when distributed and other energy resources are available than other common planning tools. And more detailed planning can lead to better investments on behalf of customers, stakeholders agreed.

"If I ran a utility, I would definitely want to understand the added value of distributed energy resources because they will be an important part of the overall energy supply," Wells Fargo Renewable Energy & Environmental Finance head Philip Hopkins said. Knowing the value that DER offer the distribution system "will allow them to be used sooner and more efficiently."

But the new modeling tool faces two hurdles to overcoming doubts by traditionally-minded planners.

The biggest is how to get utilities and their regulators to compare it with current modeling tools. It must also demonstrate real-world validity of the computations, as Vibrant sought to do with "Roadmap for the Lowest Cost Grid," released Dec. 1. The roadmap shows hypothetically how computing power and granularity — in assessing where utility-scale and distributed resources will be most cost-effective — can find hundreds of millions of dollars in savings for utilities and their customers.     

A better planning tool

In today's power system modeling, analytic software focuses on protecting reliability but emphasizes limited variables, like cost-effectiveness and resource capacity, over others. Planners understand the "uncertainty" in that modeling and are pursuing ways to "enable more-optimized resource plans," according to a 2018 Department of Energy overview of planning tools.

Vibrant's tool uses larger processing capability to optimize for more variables at a more granular level, according to Vibrant CEO and tool lead designer Christopher Clack, who previously co-developed National Oceanic and Atmospheric Administration modeling.

Unlike typical system planning, which focuses on five or ten years and no more than 20 years, Vibrant assessed U.S. system needs decades ahead in its hypothetical representations of generation, storage, transmission and DER, Clack said. And WIS:dom-P included policy factors, like renewables mandates, and engineering and system constraints in modeling system needs in 105,120 annual five-minute time segments at approximately 1 million 3-kilometer square, neighborhood-level sites, he added.

Regional Energy Deployment System (ReEDS) is the National Renewable Energy Laboratory's "flagship capacity planning model for the power sector," according to its website. But in contrast to WIS:dom-P, it models only 356 U.S. geographic regions and 17 annual time slices, according to the lab's 2019 documentation.

Aurora and PLEXOS, modeling tools from power system software provider Energy Exemplar frequently used by utilities for planning, are potentially configurable to greater granularity. But they typically forecast out only 20 years, with limited zonal resolution and hourly time slices.

The widely-known EnCompass tool from Anchor Power Solutions offers configurable geographic and temporal granularity that may match the Vibrant tool in granularity, but does not have WIS:dom-P's distribution-utility interface. The distribution-utility interface optimizes between bulk system resources and DER on the distribution system, Clack said. "I know it's a first-of-its-kind because I invented it during this project."

Planning for DER

The WIS:dom-P interface optimized between utility-scale and distributed resources in the hypothetical modeling and answered two basic questions, Vibrant reported. Its main scenario showed adding DER maintained "resource adequacy, reliability and resilience" at lower costs and met "clean electricity goals."

Vibrant first simulated U.S. energy supply and demand scenarios through 2050 using traditional modeling with and without the distribution-utility interface. It then ran scenarios with and without the interface, but with a national clean energy standard that would reduce carbon emissions 95% below 1990 levels by 2050.

The most cost-effective way to meet that 2050 clean energy standard is to deploy 247 GW of distributed solar and 160 GW of distributed energy storage, Vibrant concluded. The modeling showed it would save utility customers up to $473 billion cumulatively on electricity by 2050. Any transition to clean energy will lower customer costs, but using DER was $88 billion less expensive than transitioning with today's planning focused on utility-scale resources.

However, DER is not the whole solution.

Having more local DER available "unlocks the potential of utility-scale solar and wind," Vibrant found. "Retiring fossil-fueled power plants that run infrequently and deploying local storage more efficiently will help integrate 798 GW of utility-scale solar and 802 GW of utility-scale wind by 2050," Vibrant found.

The interface allows WIS:dom-P to recognize, unlike other modeling tools, that DER can "reshape" demand, the paper added. It can take advantage of accelerating customer investments in DER to obtain system load and peak load reductions and reduce spending on new utility-scale generation, transmission and distribution infrastructure.

This "reshaping" of demand also reduces peak period system ramping stresses, burdens on the transmission system, and enables the use of load flexibility on the demand side, Vibrant added.

With one planning tool that "accounts for total system costs and benefits," modeling will identify the solution with the "highest value," Vibrant said. It "will not select utility-scale resources with low energy cost if transmission and distribution costs to serve load are too high," but if those costs make utility-scale resources more cost-effective, the model "won't select more costly local solar."

Does it add up?

Not everyone is confident that scaling of DER will be affordable.

"Utilities and commissions should be looking for a better way to identify the value of local DER because they are now more important than ever," said Jeff Bodington, president of energy investment bank Bodington and Company. But "their characteristics are not completely known" and potential costs of reconfiguring utility system operations should not be overlooked.

More DER does create greater challenges, but it also adds opportunities for utilities, Wells Fargo's Hopkins said. "Solar on a home can contribute to midday overgeneration, but it also defers or delays expenditures for the distribution system, which can have a profound effect on utility costs."

The introduction of DER into operations can complicate the way a utility must manage reserves, he acknowledged. But if the utility has some control over the DER, it has additional flexibility, and "there will be savings opportunities in making that flexibility work."

Conventional wisdom is that large central station power plants are the most cost-effective way to meet demand and utility-scale renewables are falling in cost while local solar and storage are too expensive, said Rábago Energy Principal and former Texas electric utilities regulator Karl Rábago.

"But integrating and optimizing DER requires little investment, and sometimes small solutions can be more cost-effective than big ones," Rábago added. "Planners' cost estimates often overlook the costs to deliver central station fossil fuel generation and how scaling local solar and storage reduces overall system costs, allowing for more large-scale renewables to meet policy goals."

Distribution planning should not be separate from integrated resource planning (IRP), he said. "Plan the system with a full accounting of what's available and get the savings on the big stuff."

Utility system planners typically "solve for supply-side resources and then estimate how many distributed energy resources are cost-effective," Natural Resources Defense Council (NRDC) Climate and Clean Energy Program Senior Analyst Mohit Chhabra agreed. "Cleaving the analysis leads to imperfect estimates of the need for distributed resources."

But today's planning tools have long protected reliability and customer costs and will make regulators reluctant to consider new alternatives, some stakeholders said.

Will regulators try it?

No utility representatives were named as reviewers of the modeling, and state commissioners listed by Vibrant as reviewers declined to comment for this story. That may be due to potential conflicts in pending proceedings rather than a reluctance to endorse, but it suggests acceptance for WIS:dom-P could meet opposition.

There are still uncertainties associated with introducing DER into system operations, people interviewed for this story acknowledged. Availability and costs for technologies needed to integrated DER and to protect reliability are unclear, they agreed. And there is no guarantee customers will adopt DER at the pace needed to serve system needs, utility executives often argue.

"Regulators should consider this type of modeling, but there is lot of inertia in regulation of planning because the top priority is protecting reliability," Sunrun's Hoskins acknowledged.

In energy efficiency proceedings, Maryland regulators have required utilities to use alternative approaches to evaluating benefits "along with the planning tools they had always used," Hoskins said. "The utilities and regulators were not compelled to choose the alternative models' findings, but it is reasonable to think planning tools should change in response to changes on the system."

That change will accelerate as Federal Energy Regulatory Commission (FERC) Order 2222 is implemented, former FERC Chair and GridPolicy CEO Jon Wellinghoff said. The order requires tariffs and rules for bringing aggregated DER into wholesale markets.

When that happens, it will allow state commission-established distribution system market platforms, Wellinghoff said. Models like the one Vibrant designed "will be essential in market planning and operations because they show the value of DER to the whole system."

Another pathway for getting the new planning tool accepted in standard planning is for stakeholders to use Vibrant modeling in state proceeding testimony, he added. That could allow regulators and utilities to see both the value of the tool and the value of DER.

But there are "two daunting barriers" to including DER in planning proceedings, NRDC's Chhabra said. It is "computationally hard," and it is difficult and expensive to obtain "good quality data" on which modelers can make sound assumptions.

WIS:dom-P analysis "solves for both demand and supply side together," but it does not yet solve the location question that advanced distribution planning is working toward, he added. The next step is using its locational data to assure DER is built "in the right places."

Vibrant's tool "is exactly what is needed in state commission proceedings, in distribution planning and resource planning cases, and in the general policy conversation with legislators," said Environmental Law and Policy Center Senior Attorney Bradley Klein, a veteran of Midwestern state proceedings.

"The tools used to make critical regulatory decisions were built for a different set of resources and a different system and they undervalue local distributed resources," Klein said. "Decisions are only as good as the analyses used to reach them."

Vibrant's modeling tool "should be tested in litigated proceedings before commissioners," he said. "Experts can present the data and justify it, and highly motivated adverse parties can pick through the testimony to reveal its weaknesses. That will reveal its true value."

WIS:dom-P "can make cases stronger where commissioners are interested in data-driven evidence," Klein said. And "it has an important role in distribution planning, but it should not be confined there. We are considering using it in the upcoming Minnesota and Michigan IRP and distribution planning proceedings," he added.

Another way this can be useful is in the convergence between state retail markets and wholesale markets that will follow from FERC Order 2222, Klein said, agreeing with Wellinghoff. "That may be where it evolves over the next couple of years, as a way to quantify the types of services and compensations local resources on utility distribution systems should get in wholesale markets."

Decisions on "billion-dollar investments should not be made based on the output of a single model chosen by a single utility in an IRP proceeding," Rábago said. "The same old modeling leads to the same old solutions. This analysis asks better questions and gets better answers."

 

Article top image credit: Getty Images

The growth of distributed energy resources (DERs) has increased the urgency of finding solutions to new complexities introduced by rising penetrations of variable renewables.

There is "growing interest in a more decentralized electric grid and new types of distributed resources," the North American Electric Reliability Corporation's (NERC) 2019 Long-Term Reliability Assessment reported. At lower penetrations, DERs "may not present a risk," but as penetrations increase, "the effect of these resources can present certain reliability challenges that require attention."

Those challenges are driving power system stakeholders to rethink resource adequacy (RA).

"As the power system's resource mix changes, the resource adequacy analysis used to determine reliability needs becomes more nuanced and more complex," said Derek Stenclik, an energy consultant focused on power grid planning and resource adequacy. "There is a better way to evaluate risk and reliability in a power system."

Aggregated distributed solar, storage and demand response that make load and generation more flexible can offer customized solutions to reliability needs, power system authorities said. Aggregation can also avoid unnecessary resource buildouts or capacity procurement — if market participants are appropriately compensated and any barriers to entry are removed.

But that may only be possible if the sector exchanges an outdated concept of capacity markets for a new kind of reliability.

Qualifying for capacity markets

Wholesale electricity markets use capacity markets, RA measures and reserve margins in order to ensure NERC reliability standards are met, but DER aggregators have trouble qualifying.

Capacity market prices are set through forward auctions, and generators bid a price "equal to the cost of keeping their plant available," according to Resources for the Future (RFF). When bids match the needed capacity, all generators that "cleared" the auction are paid "the bid price of the last generator used to meet demand," which is typically higher than the energy market price and "essentially a reward" for being available, according to RFF.

Sunrun became the first and thus far only DER aggregator to qualify for a capacity market in ISO-NE's market in February 2019, bidding through a participation pathway available to DER aggregators and other generators who can meet certain market obligations.

Unlike other markets' participation models, which limit behind-the-meter resources' compensation to demand response load reductions, the developer will also be compensated for exported energy, said Sunrun Policy and Storage Market Strategy Director Chris Rauscher. But because the rules of this participation pathway were not designed for DER aggregations, qualifying was difficult for Sunrun and is likely the reason other DER aggregators have not qualified since.

Several gigawatts of new DER, including 8 GW of electric storage and 35 GW of distributed solar, is expected to be added to the bulk power system by 2024, NERC found in 2019. Because this consumer-driven growth of DERs could come without the visibility and control that system operators and planners are used to, grid operators will need to "evolve with the desires of customers and policy makers" or "become less relevant," a 2019 Brattle Group paper concluded.

NYISO is leading that evolution, Electric Power Research Institute Senior Technical Leader Erik Ela told Utility Dive.

DERs emerge as a resource adequacy tool

Wholesale markets are still grappling with how to utilize the unique attributes of DER aggregation and ensure barriers to participation are lowered.

DERs are "already contributing toward meeting peak demand on the distribution system, and that is what resource adequacy is," Ela said. The challenge is aggregating different technologies and determining how they should be valued and managed, he added.

In 2016, the Federal Energy Regulatory Commission initiated a rulemaking to target barriers that energy storage and aggregated DERs face in capacity, energy and ancillary service markets, but the resulting 2018 Order 841 was limited in its scope to storage. The commission concluded in its order that more information was needed about DER aggregations.

Driven by stakeholder pressure, NYISO developed a participation model for aggregated DERs in capacity markets that compensates load reductions and exported generation, and creates a "peak load window" for resources with "duration limitations," Ela said.

But other grid operators have not moved ahead with similar participation models for DER aggregations.

"The level of information that is needed [to reliably integrate DER aggregations] is not yet fully understood," MISO testified after a 2018 FERC-led technical conference on DER aggregations. And "there is less clarity" about DER use cases at the wholesale-level.

MISO has begun using DER aggregations in demand response programs, spokesperson Brandon Morris said in an email. But it does not have "market products specific to distribution-located generation" and creating such products is "not currently a focus."

At PJM, "DER is growing in importance," Joseph Bowring, president of the PJM Interconnection's independent market monitor, Monitoring Analytics, acknowledged. "The challenge will be to integrate wholesale and retail market designs and rules," he said in an email.

ISO-NE will not use Sunrun's DER aggregation until 2022 and now only uses aggregated DERs for demand response, ISO-NE spokesperson Matthew Kakley said in an email.

CAISO also allows DER aggregations to participate in its markets as demand response tools to reduce loads, but not as generation, spokesperson Anne Gonzales said in an email. Utilities in California use DER aggregations through the state-authorized Demand Response Auction Mechanism (DRAM) to meet part of their resource adequacy must-offer obligations.

The grid operator is currently developing another model — the Distributed Energy Resource Provider participation model — that will allow DER aggregations "to offer wholesale market services comparable to other generating resources," Gonzales said.

"Though it is technically possible, no system operator has implemented a practical participation model that addresses both the load and generation capabilities of DER aggregations," said Ted Ko, vice president of policy and regulatory affairs for Stem, a smart storage provider, which has aggregated storage participating in the CAISO DRAM.

When FERC develops a final rule for DER aggregations, it should follow a set of "principles" for participation, Ko wrote in his comments following the 2018 technical conference. DER aggregations should be allowed full participation, not be denied participation without proven risk of market distortion or threat to reliability, and rules should enable "multiple uses" of DERs with "multiple market values" as load reduction or generation, he argued.

Perhaps most importantly, aggregations should be "treated as a single resource, with the ISOs designing rules and processes at the pricing node level of granularity, not individual sites," Ko wrote.

The DER aggregation regulation pursued in FERC's 2016 rulemaking and 2018 proceeding "is still sitting there," former FERC Chair Jon Wellinghoff said. But "the recent circuit court decision on Order 841 made clear FERC has jurisdiction to implement market rules that can deliver a flood of consumer-owned flexibility to the system."

New technologies could "enable consumers to participate in wholesale markets individually and give retail aggregators a new opportunity to supply wholesale markets," Wellinghoff added.

DER aggregation may be an important factor in moving away from capacity markets, former FERC Chair Pat Wood III agreed. "Power system operators who become familiar with the new flexible resources' variability can use them to change the need for capacity markets and big reserve margins," he said.

Rethinking RA

RA analysis is "the quantitative work to determine the procurement needed to serve load and protect reliability," Stenclik said. "Historically, serving load meant serving peak load, but with the pandemic and extreme weather events and changes in consumer usage, reliability threats are no longer always at peak load."

Flexible loads and flexible generation can shave and shift peaks with distributed renewables, storage, demand response or managed electric vehicle charging, Stenclik added. To do that effectively, "the power sector must understand this new flexibility well enough to rethink its approach to RA and metrics like outage rates, and methods of analyzing reliability must evolve."

Five new principles can "ensure that enough resources are available for modern power systems, regardless of the technologies," according to Stenclik's just-published paper. The paper is one of the first efforts to develop such principles — "really important work," according to Ric O'Connell, executive director of power market and regulatory proceedings consultant GridLab.

The first principle says that DER, the technologies that manage it, and advanced rate design can make demand more responsive to price signals. That "may shift the resource adequacy planning challenge away from reliability needs toward economic considerations, as customers determine and differentiate which loads matter most."

Second, as NERC foresaw in 2017, DER penetrations on distribution systems are reaching high enough levels that RA analysis must include both near- and long-term planning, the paper said. And analyses and planning approaches that include long-term forecasts of costs, benefits and risks must become "the new gold standard" for RA analysis.

Third, changing demand makes conventional RA metrics for estimating outages too narrow, the paper said. New metrics should quantify outages' "frequency, duration, and magnitude in MW and MWh" to "put the emphasis on individual, rather than aggregate, event characteristics." That will lead to mitigations with "appropriately sized" resources and "avoid over-procurement."

Perhaps the paper's most important principle is that "there is no such thing as perfect capacity," Stenclik said. Different resources address different needs. Batteries can serve short-duration shortages, but demand response or pumped hydro storage may be better for long-duration outages. RA analyses should recognize "there is no perfect resource" and "all resources have limitations."

Finally, the economic or financial aspects of reliability should be transparently assessed to ensure that "customers are not being asked to pay more for reliability than it is worth," the paper said.

Because today's power system is complicated, applying the principles will be complicated, Stenclik acknowledged in his paper.

For example, forecasting any one individual's potential to supply capacity "is impossible," Stenclik said. But aggregated data "can assess behavior across masses of customers and derive uncertainty ranges for aggregated DER availability through the law of large numbers to normalize behaviors and make RA more predictable."

The need to use aggregated DERs for RA will grow in importance, according to Sunrun's Rauscher. "Many states have very aggressive clean energy goals or mandates, but the markets are not structured to accommodate aggregated DERs and other resources needed to meet them," he said.

ISO-NE planners have inconclusively modeled multiple new approaches to reliability, including shifting RA to states, imposing a carbon price, creating a clean energy capacity market, and using an energy-only market, Rauscher said. "No matter how the paradigm changes, it is absolutely necessary to harmonize wholesale markets with the reality of the state laws already in place."

Article top image credit: www.inhabitat.com

Investor-owned utilities (IOUs) are keeping final responsibility for maintaining a reliable power system as California pursues new resource adequacy (RA) solutions to address the challenges from rising renewables penetration.

System operators have long relied on reserve generation to supplement basic capacity for meeting system peak demand. A new law and a new regulatory proposal are allowing the state's three dominant IOUs to remain final backups.

But renewable generation's variable supply and a shifting customer load due to increased adoption of distributed energy resources (DER) demand new solutions to protect reliability California power system stakeholders agree.

Today's RA paradigm "is based on central generation to meet a few predictable peaks," Energy Innovation Senior Fellow Eric Gimon told Utility Dive. "Today's digital economy makes a new approach possible. But implementing that approach could threaten [to create] turmoil that is self-defeating unless policymakers see that implementing flexible demand can produce rewards without excess risk."

California's energy transition includes another disruptive force, the proliferation of load serving entities (LSEs). Changes in resources, demand and providers have accelerated the state's need to protect reliability.

Many stakeholders have urged the state's policymakers to set a national precedent by balancing the IOUs' traditional centralized solutions with a bigger role for DER in maintaining reliability. The new law and regulatory proposal don't do that but stakeholders say the debate is not over.​

RA basics

RA "is pretty much a universal concept in electricity planning," Energy Innovation Vice President Sonia Aggarwal told Utility Dive. "All generation is counted in some kind of resource adequacy framework, and most are based on capacity plus a reserve margin."

California's RA program was put in place following the state's 2000-2001 energy crisis. Its goals are "to ensure the safe and reliable operation of the grid in real time" and to provide incentives for "new resources needed for reliability in the future," according to the California Public Utilities Commission (CPUC).

All Load Serving Entities (LSEs) under CPUC jurisdiction, including IOUs, energy service providers (ESPs), and community choice aggregators (CCAs) must meet three resource adequacy obligations.

System RA obligations, which apply to the 80% of California load served by the California Independent System Operator (CAISO), require procurements to meet the annual system demand forecast plus a 15% reserve margin. Local RA obligations require capacity to meet a 1-in-10-year weather event and an N-1-1 contingency event determined by the CAISO. Flexible RA is to meet an LSE's biggest monthly three-hour ramp.

Until around 2015, procurement to meet all these RA obligations was largely done by California's three IOUs — Pacific Gas and Electric (PG&E), Southern California Edison (SCE) and San Diego Gas and Electric (SDG&E). Each managed reliability in its territory.

Rising penetrations of variable renewables have raised concerns from regulators and system operators about RA because fluctuations in solar and wind can compromise reliability, stakeholders told Utility Dive. Rising penetrations of DER add to the urgency because customers' use of them can shift load unpredictably.

But in the last four years, procurement for RA obligations set by the CAISO has become disaggregated across 44, more narrowly focused LSEs, including 19 CCA programs serving over 10 million former IOU customers. The CPUC expects CCAs to take over 80% of IOU customers by the mid-2020s. And a 2018 law increased the 21 registered energy service providers' share of IOU commercial-industrial load to 15.4%.

Policymaker concerns that disaggregated RA procurements could leave unfilled local needs that prevent reliably balancing supply and demand led to regulatory and legislative proposals to protect reliability.

The new law

The CPUC's proposed decision in the state's RA proceeding (R.17-09-020) was the second big step taken by California in recent months to resolve reliability concerns. The first, Senate Bill (SB) 520, signed by Gov. Gavin Newsom, D, last October, requires IOUs to be the electricity providers of last resort (POLR) if any LSE does not meet its obligations to its customers.

The bill also orders the CPUC to establish a process through which an IOU can file a "joint application" with another LSE in its territory to transfer the POLR responsibility, under CPUC jurisdiction.

While PG&E did not take a position in last fall's SB 520 debate, SCE supported it. But CCAs adamantly opposed the bill, East Bay Community Energy (EBCE) Senior Director of Public Policy and Deputy General Counsel Melissa Brandt told Utility Dive.

"The IOUs essentially have veto power over whether CCAs can be the POLR, and even if the CPUC prefers a CCA as the POLR, if the utility doesn't want to go along, the CCA cannot do it," Brandt said.

SB 520 also imposes costs and criteria on CCAs in the POLR role that are stricter than those imposed on IOUs and could over-reach CPUC authority to regulate CCAs, she added. Because CCAs oppose this kind of use of commission authority, they are unlikely to be willing to take on POLR responsibilities.

Since SB 520 is now law, they are likely to accept the IOUs in the POLR role, unless it drives up CCA costs, because it is unlikely to impact concerns about the use of local distributed energy resources for RA. They are, however, not ready to accept the RA procurement entity defined in the proposed decision, Brandt said.

The proposed decision

The proposal addresses the bigger question of how to implement a centralized procurement process to meet local RA needs if individual LSEs fail to do their share.

CCAs have consistently challenged any proposals from lawmakers that might threaten the emerging LSEs' "right to self-procure," Brandt said.

In an August 2019 Settlement Agreement that preceded the CPUC's proposed decision in the RA docket, CalCCA, representing all of the state's CCAs, SDG&E, the Independent Energy Producers Association (IEPA) and five other stakeholder groups proposed a "residual central procurer" for RA. Reliability procurement would be left to the LSEs, unless there were residual unfilled needs after an LSE's procurements were reported.

The agreement did not "identify or designate" who the residual procurer would be, but required it be "a competitively neutral, independent, and creditworthy entity" that coordinates with state regulatory agencies.

SDG&E declined Utility Dive's request for comment but its support of the agreement aligns with its November 2018 proposal for "a glide-path out of the energy procurement space."

Utility-scale renewables developers "have completed transactions with CCAs" and have also endorsed the agreement because they could see "a residual central procurer would address procurement gaps," IEPA CEO and former CAISO Board of Governors member Jan Smutny-Jones told Utility Dive.

But the CPUC, in its proposed decision, rejected the settlement, because it represented only eight of 60-plus stakeholders, was not the best solution for overall grid reliability, and omitted the "critical component" of identifying a specific procurement entity.

The proposed decision also rejected the Settlement Agreement's residual central procurement concept, and named PG&E and SCE as central procurement entities for local RA in their territories, largely eliminating the right to self-procure of the emerging LSEs, including CCAs.

A central procurement entity for SDG&E's territory was deferred because system, local, and flexible RA capacities overlap, the proposed decision says. LSEs there "will continue to receive a local requirement and self-procure local resources as is currently done."

The proposed decision would have the IOUs do "hybrid procurement," which "is similar to full procurement" in that it gives the IOUs most of the control, but gives LSEs an opportunity to procure local resources for RA.

SCE and PG&E, as hybrid central procurement entities, are allowed cost recovery for procurements that mitigate "load uncertainty and migration" and align with "the state's environmental goals and preferred resource procurement mandates," the proposed decision adds.

The residual model in the Settlement Agreement seemed to balance meeting the system's needs with some LSE autonomy, IEPA's Smutny-Jones said. "But there was no meeting of the minds between parties on who would be the central procurement entity and the commission understandably chose to settle that important question."

The proposed decision does not give CCAs and other LSEs the opportunity to procure for themselves, and that is "a step backwards for what California is trying to achieve," EBCE's Brandt said. "It is going to be very highly contested."

Stakeholder comments are due in mid-April and the final decision is expect in June.

While the CCAs were dissatisfied with the control given to the IOUs by the proposed decision, most stakeholders, including the IOUs, saw the decision as a failure to come to terms with reliability in a transitioning power system.

A new paradigm

While there are different opinions on the best approach to a central procurer, IOUs, CCAs and others agreed significant changes are needed for RA in California.

The existing RA program is "based on capacity available over peak hours" but high penetrations of renewables and DER creates a need for RA "not just during peak hours" as the dynamics of supply and load change, PG&E spokesperson Ari Vanrenen emailed Utility Dive.

SCE Manager of Wholesale Market and GHG Market Design Eric Little agreed, calling for "a more complete integration" of RA and resource planning. He also noted SCE's proposed new metrics for valuing co-located renewables and storage as RA, which could begin opening up a role for DER in RA.

Here, CCAs agree. "Historically, we've relied on the 15% planning reserve margin for meeting the system peak," EBCE Principal Regulatory Analyst Stefanie Tanenhaus told Utility Dive. But variable resources create "capacity needs to serve load at all hours of the day."

Regulators have committed to addressing the impacts of rising renewables, DER, and shifting load on reliability in Track 3 of the proceeding that led to the proposed decision, Tanenhaus​ said. It will begin this summer and consider "alternate reliability metrics to replace the reserve margin and new ways to value the reliability contribution" of all resources, including local DER and, especially, solar plus storage.

Efforts by regulators to develop new metrics within the existing program show RA is "stuck in an outdated paradigm," Energy Innovation's Gimon said. "New metrics will accommodate new resources, but will not make that [old] paradigm work."

The solution begins with moving away from a "commodity mindset," said Gimon, who just published a paper on RA's role in the energy transition. "Capacity as a commodity needs to make way for technology portfolios that accommodate a variety of possibilities."

Planners also need "to get away from the idea that demand rises until there is no more supply and then the system drops off a cliff," he added. System operators have reserves, the ability to curtail load, and out of state markets and resources that prevent a "cliff."

And demand side resources can now be foundational in the resource mix as a way to increase reliability, Gimon said. "In a digital economy, customers can respond to prices and consume more electricity when it's cheap and consume less when it's expensive, which also prevents the cliff."

It is, though, "not clear how to transition away from the existing RA paradigm without the perception of undermining regulatory authority and creating turmoil that defeats the transition," he acknowledged. It would require showing that the threat to reliability is greater than the threat of change.

But in California's haunted institutional memory, change is a real threat. "The argument in the 1990s was a strict market approach would be more efficient, and it worked perfectly until market failures led to the energy crisis," IEPA's Smutny-Jones remembered. "We have been down that road before and it does not have political traction."

Article top image credit: Photo illustration by Brian Tucker/Utility Dive; photograph by thinkreaction via Getty Images

Avista Energy is preparing to launch a "micro-transactive grid" in Spokane, Washington, that experts say illustrates the future of distributed energy resource (DER) management.

Beyond maintaining resilient power, the microgrid will provide visibility and control of smaller loads and enable trading of energy between two buildings in a way that could lead to new businesses cases and increased market participation for DERs. 

And Avista is already working on other similar DER pilots that could help to expand the size and efficiency of the transactive microgrid.

The microgrid is located in the city’s University District, adjacent to downtown, and will allow two buildings operated by Washington State University to trade energy back and forth, charging batteries when prices are low or when there is abundant renewable energy. The system will allow the energy to be consumed when prices are high or during power outages to maintain system resilience.

The two buildings each include a pair of battery storage systems: a 500 KW / 1,500 KWh battery and a 167 KW / 337 KWh battery. A rooftop solar array on the buildings provides 100 KW each. The buildings also utilize advanced energy management systems that can monitor and control 60 individual loads.

"One of the great things we're doing here is more granular load control," Heather Rosentrater, Avista's senior vice president of energy delivery, told Utility Dive.

Engineering work on the two-building grid is largely being handled by POWER Engineers. The project is expected to come online in March 2021.

"This project is a bit broader in scope than traditional microgrids," Power Engineers project manager Greg Clark told Utility Dive. "A lot of times microgrids are constructed mostly for resiliency and to be able to support critical loads for longer periods. ... We wanted to investigate four goals."

Funded by the Washington State Department of Commerce, the project will examine how a combination of buildings and distributed energy resource assets can work together to provide grid services. The transactive environment will also tackle questions of DER optimization, including how utilities can best utilize the combination of battery storage and solar generation, and will consider how groups of buildings can be managed through the use of a central microgrid controller to manage assets in separate buildings.

Resilience is the fourth goal of the project, said Clark.

"Avista wants to understand better what kind of economic models they could provide for wider adoption of these types of systems," Clark said.

Microgrids go beyond resilience

Microgrids in smart buildings are evolving beyond resilience use cases, according to Mark Knight, member chair of the Smart Electric Power Alliance's (SEPA) Transactive Energy Working Group. He also serves as an industry adviser at Burns & McDonnell.

These buildings "have the potential to support their own transactive energy systems, but can also interact with a microgrid, for instance on a campus grid, and with other buildings to create a lot of flexibility and thus integrate renewables more effectively," Knight said in an email.

A core component of a microgrid is the ability to balance supply and demand to maintain grid stability while disconnected from the greater power grid, according to Ben Ealey, principal of grid integration at SEPA. That requires different energy resources within the microgrid to be capable of providing flexibility.

A project like Avista's "serves as an excellent entry point for new opportunities for the grid including transactive and market opportunities for community level aggregation" potentially including smart communities, buildings and campuses, Ealey said in an email.

Other microgrid opportunities, challenges

While the Avista project will focus on assessing multiple business cases for distributed resources, there are hurdles to integrating DERs into the wider grid on a large scale.

DERs can cause potential disruptions to the power grid by generating energy at the edge of the grid, said Knight, incentivizing utilities to coordinate them locally. "Using transactive energy systems to enable non-wires alternatives that coordinate DER use at a local level is a great approach for this," he said.

Doing that will require the broad implementation of new smart grid technology with advanced communication capabilities.

"Most DER do not provide utility-facing capabilities today," said Ealey. Smaller generation-based distributed resources typically do not have communications built in, he said, but a push to standardize communications for demand response technologies is helping overcome the difficulty, he said.

"As the number of connected, grid-facing, interoperable DER increase it will be easier for communities, campuses, and buildings to provide more flexibility in an affordable way," said Ealey.

Avista says it sees more and more of its customers interested in having on-site generation to have more control, clean energy and greater resilience. "As more customers are interested, we want to make sure they are getting the most value out of those assets," Rosentrater said.

Avista's microgrid could be connected to a new 'eco-district' 

Along with the micro-transactive grid pilot, Avista is participating in another public-private partnership in the same University District to test a shared energy model called an eco-district. Like the microgrid pilot, Avista’s multi-building eco-district project will be partially funded by a separate grant from the Washington Department of Commerce’s Clean Energy Fund. 

"We're doing a lot of the same things," Rosentrater said, but the eco-district project will take the shared energy model "to a new level."

The larger project involves a centralized heating and cooling system located in the University District's mixed-use Scott Morris Center for Energy Innovation, that will initially provide energy for an adjacent building and later to other buildings that will be added to the development.

Eventually, that project could be operated in conjunction with the two-building microgrid coming online next year. And the transactional system could eventually participate in the Western Energy Imbalance Market, which could provide new revenue streams for the utility, though it will not have that capability to start.

"We're looking at how that could operate," Rosentrater said. "Right now, the two buildings are the same customer and so we're not trading energy between different customers — but ... what we learn through this project will help us design those types of systems or tariffs in the future as that becomes a more viable option for customers."

Article top image credit: Ron Reiring