The Sacramento Municipal Utility District provides electricity to Sacramento County, California, and a small portion of adjacent Placer County. It is one of the ten largest publicly owned utilities in the United States, generating the bulk of its power through natural gas and large hydroelectric generation plants , and SMUD's green power energy output was estimated as 19% in 2009.SMUD owned the Rancho Seco Nuclear Generating Station nuclear power plant, shut down by a vote of the utility's rate-payers in the late 1980s. Although the nuclear plant is now decommissioned, its now-empty iconic towers remain on the site. Solar arrays and the 500-megawatt Cosumnes gas-fired plant have risen in proximity to the towers.SMUD's headquarters building, built in the late 1950s on the edge of the East Sacramento neighborhood, is notable for its mural by Sacramento artist Wayne Thiebaud. The mural wraps around the ground floor of the building and is accessible to the public. It is one of the earliest major works by the artist, and remains his largest installation to date. Wikipedia.
News Article | March 29, 2016
For Arlen Orchard, CEO and general manager of Sacramento Municipal Utility District, in order to understand how his utility will change over the next decade, it’s helpful to start by looking back. “It’s 2014. Our revenues are flat or declining despite [having] more customers; our customers want more options and choices; we can’t install technology fast enough to keep up with the changes in our industry; and we struggle to manage the data we have from technology we’ve already installed,” said Orchard, speaking at Opower’s PowerUp conference in Miami earlier this month. “And if that’s not enough, more than 70 percent of the electricity I sell to my customers has to be carbon-free by 2030.” “We didn’t see the sharp shift in the path. To be fair, a lot of folks in the industry didn’t, but that’s a really small consolation,” he added. “Now we’re playing catch-up, and that’s a pretty uncomfortable place to be and pretty unfamiliar for SMUD.” Sacramento Municipal Utility District (SMUD) is one of several electric utilities that’s now proactively looking for ways to address new customer preferences and capitalize on the change at the same time. For all types of utilities -- municipal, cooperative and investor-owned -- the growing demand for cleaner energy, at a lower price, with more convenient services and greater choice has become impossible to ignore. Results from a recent survey of residential customers conducted by E Source, in partnership with the Smart Electric Power Alliance, demonstrate this trend. The survey found that 80 percent of respondents believe policymakers should encourage people to install solar through subsidies. Support was strong across the country, across age groups and across income brackets. Before conducting the survey, E Source took several steps to educate customers about a utility’s need to cover its fixed costs to support the grid. Even with that information in hand, 69 percent of respondents said it’s fine for solar customers to zero out their utility bill if they produce enough electricity to cover their own needs in aggregate. “Given this overwhelming support, utility efforts to block subsidies for solar installations are likely to be seen in a negative light by most of their customers, resulting in a hit on the utility’s brand image,” the report states. While the policy outlook remains uncertain, an increasing number of utilities are positioning themselves to be a trusted provider of solar and other energy services -- mostly because they see no other choice. “I suppose I could have fought the changes at every turn and focused on self-preservation, but that would have meant ignoring my customers and betting against technology,” said Orchard. “At best, I’d end up as the Comcast of utilities, or at worst the Blockbuster.” To adapt its business, SMUD recently launched a consumer-experience study that includes mapping a customer’s journey through each of the utility’s services. Going through this exercise allows the utility to identify and fix pain points, as well as enhance operational efficiencies, said Orchard. In 2016, SMUD will focus on improving customer experience with billing and payment. In 2017, the utility plans to launch its own online marketplace for energy products and services. By 2025, Orchard said he envisions SMUD as the trusted advisor for all things energy-related. In a decade's time, nearly all of SMUD’s customers will have moved to digital services, there will be automatic payment systems and programs to control energy costs, customers will be able to communicate through the channel of their choice, and they’ll be able to use SMUD’s marketplace to buy everything from LED light bulbs to electric vehicles to home batteries. By that time, SMUD projects that revenues will be on the upswing from the adoption of electric vehicles, fuel switching, sales of new products and services, and by capitalizing on SMUD’s intellectual property. To transition to a 3.0 utility, “We at SMUD have to shift our perspective from a monopoly paradigm to a competitive mindset,” said Orchard. “We have to reimagine our business to be more robust, nimble and innovative.” “To be frank, I think SMUD had become pretty comfortable in our past successes, and that’s a real danger going forward,” he added. “We have to lean in to our discomfort to be successful.” Innovation isn’t only relevant to new products and services. There are many ways for utilities to improve customer satisfaction and engagement by making the basics better. At Con Edison, for instance, Twitter has become an effective communication channel that now operates year-round, 24 hours per day. At the PowerUp event, Craig Ivey, president of Con Ed, said the company boasts a 12-minute Twitter response time. In an unprompted test, the utility delivered with minutes to spare. Social media is just one part of Con Ed’s customer engagement strategy. The New York utility recently announced a partnership with Opower to modernize its relationship with customers as part of its Connected Homes demonstration project, which aims to make energy-saving and energy-generating as seamless as an Uber ride. Con Ed plans to spend $50 million to enhance the overall digital customer experience, as it rolls out advanced metering infrastructure starting in 2017. As the industry evolves, Ivey said utility call centers could soon deploy services similar to Amazon’s Alexa, Apple’s Siri and IBM’s Watson. These digital agents would know every rate schedule and rate change, and speak 150 different languages. “Imagine a world where we have Watson or Siri talking to any New Yorker in their own language. I think that’s pretty amazing, and I think that’s a trend that’s starting to happen,” said Ivey. Opower president Alex Laskey said it is easy to see how utility services will become increasingly automated, and how utilities could offer increasingly sophisticated energy programs like peer-to-peer solar sharing. But most utilities need a major digital upgrade before any of that becomes possible, he said. “There’s some basic infrastructure utilities have to have if they’re going to be this new energy market-maker -- they need a better website and customer experience,” said Laskey. “If it takes you four calls to start and stop service, how are you ever going to buy your neighbor’s power?” J.D. Power and Associates has been measuring electric utility customer satisfaction since 1999. The good news for utilities is that there’s been a noticeable increase in customer approval in the last three years, according to Jeff Conklin, senior director of J.D. Power's energy practice. The bad news is that non-utility segments are improving much faster. “Service expectations of the utility, from a consumer point of view, are set by the experiences they get from Amazon and American Airlines and other service providers,” Conklin said. “So that’s the challenge utilities have -- to continue to accelerate and have a sense of urgency about improving their overall customer experiences.” Some may argue that utilities have a harder time providing top-notch service because of the size and complexity of the electrical grid. But Conklin doesn’t think utilities are limited at all. In fact, they have the advantage of having a direct physical link to the customer -- and access to a mountain of customer data as a result. J.D. Power research shows that customer engagement goes a long way toward improving customer satisfaction. By providing customers with information on where the utility is investing in grid upgrades or how they’re responding to an outage, it makes customers feel like they’re getting more value for their money, which can benefit a utility’s bottom line. J.D. Power conducted a study looking at customer satisfaction one year before a rate ask and one year after a rate ask, over more than 10 years of rate cases. Utilities that came into the rate process with top-quartile-level satisfaction for the industry were allowed a much higher rate of return, said Conklin. Rate asks from high-approval utilities were also approved faster. Interestingly, the J.D. Power study found that rooftop solar customers are more satisfied with their local electric utility than customers without solar, Conklin said. A third of solar customers surveyed last year said they have a positive opinion of their utility. “The engagement, even while you’re assisting your customer to take away electricity sales, improves the satisfaction that customer has with [the utility] as a trusted energy services provider,” said Conklin. The challenges and opportunities distributed solar brings are likely only to continue to grow. Today, rooftop solar customers only make up around 1 percent of all residential electricity customers. But that number is expected to increase dramatically, with 28 percent of households surveyed by J.D. Power last fall saying they “probably will” or “definitely will” consider going solar in the next two years. More and more utilities see value in becoming a trusted energy services provider, but the economics are still messy. “When customers are satisfied, it doesn’t directly translate to a higher rate of return, but it translates to a higher confidence that we’re meeting customers' needs, which is exactly what we’re all supposed to be doing,” said Ed White, vice president of the New Energy Solutions unit at National Grid. Through New York’s Reforming the Energy Vision proceeding, utilities in the Northeast are working with regulators and industry stakeholders to find new ways to make money, so that utilities aren’t always reliant on the traditional rate of return. “Regulators are actually looking for us to find other ways to make money -- how to split some revenue, how to earn money for connecting customers to folks in the marketplace,” said White. National Grid created the New Energy Solutions group last year to take on this task. One part of the answer is the creation of a distributed solar marketplace in Rhode Island that allows customers to shop for solar in a transparent manner and receive an incentive for improving energy efficiency at the same time. These types of initiatives take time and money, and require policy shifts as well as business-model changes. It’s taken stakeholders in New York about nine months just to have a conversation around the various types of assets utilities have to offer -- be it infrastructure, IT capability or labor -- and how they can be leveraged to provide services that third-party vendors will pay for. “Do we have it all mapped out how [reforming the electricity industry] is going to be profitable? No,” said White. “But are we being thoughtful in how we put our businesses together? Absolutely.” “I think where other industries and other companies have struggled is if you’re fighting to preserve a business that needs to change, you’re in trouble,” he added. Interested in how other utilities are grappling with these issues? Experts will delve further into issues and opportunities shaping the next-generation energy system at GTM's Grid Edge World Forum taking place June 21-23, 2016 in San Jose, Calif. Register here.
News Article | March 4, 2016
New research suggests that in the future, one of the most lowly, boring, and ubiquitous of home appliances — the electric water heater — could come to perform a surprising array of new functions that help out the power grid, and potentially even save money on home electricity bills to boot. The idea is that these water heaters in the future will increasingly become “grid interactive,” communicating with local utilities or other coordinating entities, and thereby providing services to the larger grid by modulating their energy use, or heating water at different times of the day. And these services may be valuable enough that their owners could even be compensated for them by their utility companies or other third-party entities. “Electric water heaters are essentially pre-installed thermal batteries that are sitting idle in more than 50 million homes across the U.S.,” says a new report on the subject by the electricity consulting firm the Brattle Group, which was composed for the National Rural Electric Cooperative Association, the Natural Resources Defense Council, and the Peak Load Management Alliance. The report finds that net savings to the electricity system as a whole could be $ 200 per year per heater – some of which may be passed on to its owner – from enabling these tanks to interact with the grid and engage in a number of unusual but hardly unprecedented feats. One example would be “thermal storage,” which involves heating water at night when electricity costs less, and thus decreasing demand on the grid during peak hours of the day. Of course, precisely what a water heater can do in interaction with the grid depends on factors like its size or water capacity, the state or electricity market you live in, the technologies with which the heater is equipped, and much more. “Customers that have electric water heaters, those existing water heaters that are already installed can be used to supply this service,” says the Brattle Group’s Ryan Hledik, the report’s lead author. “You would need some additional technology to connect it to grid, but you wouldn’t need to install a new water heater.” Granted, Hledik says that in most cases, people probably won’t be adding technology to existing heaters, but rather swapping in so-called “grid enabled” or “smart” water heaters when they replace their old ones. In the future, their power companies might encourage or even help them to do so. Typically, a standard electric water heater — set to, say, 120 degrees — will heat water willy-nilly throughout the day, depending on when it is being used. When some water is used (say, for a shower), it comes out of the tank and more cold water flows in, which is then heated and maintained at the desired temperature. In contrast, timing the heating of the water — by, say, doing all of the heating at night — could involve either having a larger tank to make sure that the hot water doesn’t run out, or heating water to considerably higher temperatures and then mixing it with cooler water when it comes out to modulate that extra heat. Through such changes, water heaters will be able to act like a “battery” in the sense that they will be storing thermal energy for longer periods of time. It isn’t possible to then send that energy back to the grid as electrical energy, or to use it to power other household devices — so the battery analogy has to be acknowledged as a limited one (though the Brattle report, entitled “The Hidden Battery,” heavily emphasizes it). But the potentially large time-lag between the use of electricity to warm the water and use of the water itself nonetheless creates key battery-like opportunities, especially for the grid (where utility companies are very interested right now in adding more energy storage capacity). It means, for instance, a cost saving if water is warmed late at night, when electricity tends to be the cheapest. It also means that the precise amount of electricity that the water heater draws to do its work at a given time can fluctuate, even as the heater will still get its job done. These services are valuable, especially if many water heaters can be aggregated together to perform them. That’s because the larger electricity grid sees huge demands swings based on the time of day, along with smaller, constant fluctuations. So if heaters are using the majority of their electricity at night when most of us are asleep, or if they’re aiding in grid “frequency regulation” through instantaneous fluctuations in electricity use that help the overall grid keep supply and demand in balance, then they are playing a role that can merit compensation. “If the program is well-designed, meaning in particular, you have a well-designed algorithm for controlling the water heater in response to these signals from the grid, then what’s really attractive about a water heating program is that you can run these programs in a way that customers will not notice any difference in their service,” says Hledik. In fact, using electric water heaters to provide some of these services has long been happening in the world of rural electric cooperatives — member-owned utilities that in many cases control the operation of members’ individual water heaters, heating water at night and then using the dollar savings to lower all members’ electricity bills. Take, as an example, Great River Energy, a Minnesota umbrella cooperative serving some 1.7 million people through 28 smaller cooperatives. The cooperative has been using water heaters as, in effect, batteries for years, says Gary Connett, its director of demand-side management and member services. “The way we operate these large volume water heaters, we have 70,000 of them that only charge in the nighttime hours, they are 85 to 120 gallon water heaters, they come on at 11 at night, and they are allowed to charge til 7 the next morning,” Connett explains. “And the rest of the day, the next 16 hours, they don’t come on.” Thus, the electricity used to power the heaters is cheaper than it would be if they were charging during the day, and everybody saves money as a result, Connett says. But that’s just the first step. Right now, Great River Energy is piloting a program in which water heaters charging at night also help provide grid frequency regulation services by slightly altering how much electricity they use. As the grid adds more and more variable resources like wind power, Connett says, using water heaters to provide a “ballast” against that variability becomes more and more useful. “These water heaters, I joke about, they’re the battery in the basement,” says Connett. “They’re kind of an unsung hero, but we’ve studied smart appliances, and I have to say, maybe the smartest appliance is this water heater.” Of course, those of us living in cities aren’t part of rural electric cooperatives. We generally buy our electricity from a utility company. But utilities also appear to be getting interested in these sorts of possibilities. The Brattle Group report notes ongoing pilot projects in the area with both the Hawaiian Electric Company and the Sacramento Municipal Utility District. Thus, in the future, it may be that our power companies try to sign us up for programs that would turn our water heaters into grid resources (and compensate us in some way for that, maybe through a rebate for buying a grid-interactive heater, or maybe by lowering our bills). Or, alternatively, in the future some people may be able to sign up with so-called demand response “aggregators” that pool together many residential customers and their devices to provide services to the grid. And as if that’s not enough, the Brattle Group report also finds that, since water heating is such a big consumer of electricity overall — 9 percent of all household use — these strategies could someday lessen overall greenhouse gas emissions. That would be especially the case if the heaters are being used to warm water during specific hours of the day when a given grid is more reliant on renewables or natural gas, rather than coal. Controlling when heaters are used could have this potential benefit, too. Granted, these are still pretty new ideas and the Brattle Group report says they need to be studied more extensively. But as Hledik adds, “I haven’t really come across anyone yet who thinks this is a bad idea.”
News Article | October 23, 2015
There’s definitely a value to storing solar energy in batteries, and then discharging that energy to meet grid and customer needs. Measuring that value -- and finding a way to share it between battery-equipped solar customers and their utilities -- is a trickier matter. Out in Sacramento, Calif., a long-running solar-storage pilot project has been testing out this interplay. The city’s utility, Sacramento Municipal Utility District (SMUD), has been working with startup Sunverge to align the operation of 34 battery-backed, PV-equipped homes with its needs to shave peak demand in late summer afternoons, when air-conditioning loads put stress on the grid. SMUD is using critical peak pricing as its lever. Since 2012, the utility has been running an experiment with residential rate plans that charge extra-high prices during “critical peak period” days, in exchange for extra-low prices at other times. Some customers were offered the option of signing up for the plan -- and others were automatically enrolled. For the past two summer seasons, Sunverge has been making some of its battery-solar home systems available to respond to these critical peak prices, to see how stored solar energy can defer those peaks. Here are some of the results from June through September of this year -- and according to the data, stored solar energy can have a significant role to play. Here are two charts, representing customers on SMUD’s critical peak rates and those who aren’t. As you can see, peak-pricing-sensitive customers were able to significantly lower their demand profile, and even inject energy into the grid, on nine separate critical peak pricing days. That’s in contrast to homes that aren’t on critical peak pricing, which lacked an incentive to tap their solar batteries. Here's the effect on the homes’ overall demand profile. The top chart shows homes on the CPP rate, and the bottom chart, those without it. The deep-green-colored valley on the top chart indicates battery power being injected back into the home, and on a net basis, back into the grid. According to Sunverge’s calculations, homeowners on critical peak pricing saved a collective $445 over the course of these nine “conservation days,” compared to what they would have spent without that peak-time contribution from Sunverge’s battery systems. These homes weren’t storing any grid energy, CEO Ken Munson said in a recent interview -- they’re strictly charging from rooftop PV at the home. “There’s more value to unbundle when you get into the very specific nuances of taking these distributed energy resources and optimizing them in concert with the grid,” he said. Sunverge also incorporates smart thermostats, whole-home energy data from utility smart meters, weather forecast data, and a communications platform that taps utility grid data from SCADA and distribution management systems, he noted. This is the same concept pushing so many residential solar companies into partnerships to bring behind-the-meter batteries and home energy control systems to commercial scale. The most well-known is the partnership between Tesla and SolarCity, but we’ve also got Sungevity and Sonnenbatterie, Sunrun and Outback Power, Enphase and Eliiy, Tabuchi Electric and Geli, and SunPower and Sunverge, to name a few.
News Article | October 28, 2016
Enbala Power Networks has been selected by General Electric Global Research as a key partner in its DOE-funded ARPA-E Network Optimized Distributed Energy Systems (NODES) project. The $3.9 million project’s objective is to create transformational distributed flexibility resource (DFR) technology that aggregates responsive flexible loads and distributed energy resources (DERs) to provide synthetic reserve services to the grid while maintaining high customer quality-of-service. Specifically, a fast reserve similar to a regulating/spinning reserve and a multi-hour, ramping reserve will be developed to provide the same kind of grid balancing flexibility now provided by power plants and large-scale demand response. Other project participants include GE Energy Consulting, the Lawrence Berkeley National Laboratory, Consolidated Edison, Inc., Southern California Edison, Sacramento Municipal Utility District and California Independent System Operator. The 12 NODES projects, including this one, aim to develop innovative and disruptive technologies for real-time management of T&D networks through system-wide control and coordination of flexible load and DERs. In a DOE press release ARPA-E Director Dr. Ellen D. Williams commented, “The research and development of these grid control technologies will make the concept of virtual energy storage a practical reality. The result will enhance the resiliency, security and flexibility of our nation’s electric grid and allow the U.S. to make the best use of its abundant renewable energy resources.” One novel aspect of the GE ARPA-E project is development of a tool that will use short-term and real-time weather forecasts along with other data to estimate the reserve potential of aggregate loads and DERs on a day-ahead basis. An optimization framework that will enable aggregation of large numbers of flexible loads and DERs and determine the optimal day-ahead schedule to bid into the market will also be developed. This will provide the flexible resources required to meet the transformational requirements of today’s evolving grid, while also opening up new opportunities for customers to monetize their assets. Using its Symphony by Enbala distributed energy resource management platform, Enbala is responsible for the project’s control infrastructure and for working collaboratively with Consolidated Edison to recruit a diverse set of customers and distributed energy assets. The advanced control functionality developed within the NODES project will be implemented as micro-services leveraging the GE Predix cloud platform. “This is an innovative project that will effectively demonstrate how grid edge assets can be effectively networked into virtual storage systems that manage the intermittency of renewable energy and help us meet the growing operational challenges of grid infrastructure management,” commented Enbala President and CEO Arthur “Bud” Vos. The DFR technology being created must be able to aggregate and control thousands of customer DERs in real time and match them with production projections. GE electrical engineer Naresh Acharya explained that this project will enable a grid that can reliably manage a power mix where nearly half or more is supplied by renewables. About Enbala Power Networks® Enbala Power Networks is focused on making the world’s power grids greener and more reliable, efficient and predictable by harnessing the power of distributed energy. Enbala’s real-time energy-balancing platform - Symphony by Enbala - is transforming energy system operations through its revolutionary, highly flexible approach for creating controllable and dispatchable energy resources. It unobtrusively captures and aggregates available customer loads, energy storage and renewable energy sources to form a network of continuously controlled energy resources. The platform dynamically optimizes and dispatches these resources to respond to the real-time needs of the power system – all without impacting customer operations. For more information, visit http://www.enbala.com or follow @enbala on Twitter.
News Article | October 13, 2016
Germany’s Sonnen is hot on Tesla’s heels in the small but fast-growing U.S. market for behind-the-meter batteries, mainly used to provide emergency backup power for solar-equipped homes. But like every other player in the field, Sonnen is looking for additional revenue streams to bolster its business case, like aggregating lots of smaller batteries to provide services at grid scale. That’s the goal of Sonnen’s new partnership with Silicon Valley startup AutoGrid. On Wednesday, the two announced they’re integrating their software to “help energy project developers, utilities and other energy service providers better manage, optimize and aggregate sonnenBatterie systems and other distributed energy resources.” Sonnen is already doing this kind of grid aggregation in Germany, through partnerships with retail energy providers and distribution utilities. It launched its U.S. residential energy storage offering last year, and now has more than 100 installation partners in 40 states. That list includes big markets like California and Hawaii and off-the-beaten-path states like Utah and North Dakota, said Olaf Lohr, Sonnen’s development director, in a Wednesday interview. While Sonnen hasn’t disclosed figures on how many customers have bought and installed its solar-battery systems in the states it’s working in, “We’re getting to the point of critical mass,” he said. But as the company will admit, there are cheaper ways for homeowners to get emergency backup power than a solar system and a battery. Meanwhile, maximizing your self-consumption of solar may be an economically effective use case in Germany, but it doesn’t pencil out in almost any U.S. markets, Hawaii being the possible exception. That’s leading Sonnen, along with every other residential solar-battery contender, to look to the other side of the meter for value. While a single 5- to 10-kilowatt battery isn’t of much use on its own, blocks of them can be aggregated into larger units of energy capacity and stability that have value to utilities, grid operators or retail energy providers. “We’re looking to add more value to justify the hardware side, and utility control becomes a more and more sought-after asset,” said Lohr. “For this market, we’re looking to add various partnerships to the mix. We know that the utility landscape is very diverse in the U.S., and we absolutely believe that partners like AutoGrid can add to our offering.” AutoGrid has spent the past decade building a data analytics platform to manage the complexities of distributed energy resources and the resulting challenges for customers that own them. Its software has been deployed by U.S. utilities including Palo Alto’s municipal utility, Sacramento Municipal Utility District, Oklahoma Gas & Electric, Austin Energy, Florida Power & Light and Hawaiian Electric, and in Europe, it’s managing a virtual power plant with Dutch retail energy provider Eneco. AutoGrid, which recently raised $20 million from investors including the utility consortium Energy Impact Partners, has been working for some time behind the scenes to integrate its software with Sonnen’s networking and control platform, said Shane O’Quinn, the company’s strategic accounts director. “One of the real advantages of this partnership is that we can go to both independent customers who bought the Sonnen battery and do more with those assets, or go to utilities that want to deploy batteries to solve their specific problems,” he said. While the opportunities for aggregated distributed energy resources are scarce at present, they’re starting to emerge in bellwether states like California, Hawaii and New York. AutoGrid recently won 1.5 megawatts of contracts under California’s Demand Response Auction Mechanism program, for instance, although it hasn’t decided whether it will use batteries for any of that commitment, O’Quinn said. Sonnen isn’t the only battery contender seeking residential energy storage business cases beyond backup power. Earlier this year, Tesla discontinued its 10-kilowatt-hour Powerwall model designed for backup power, to shift its focus to using batteries for solar self-consumption and for grid services through its partner, SolarCity. Tesla also deployed its batteries with Vermont utility Green Mountain Power in a project that will pay customers to use their stored solar power to reduce load on the grid. Startup Sunverge has made utility and grid services the core of its behind-the-meter battery and solar systems, and is doing a 300-home virtual power plant project with Con Ed in New York and smaller projects in California and Kentucky. Like Tesla, Sonnen has recently rolled out a cheaper and smaller battery designed around self-consumption and grid services instead of backup power. While it hasn’t yet announced any grid aggregation projects in the U.S., it’s working on a few behind the scenes, Lohr said. Meanwhile, AutoGrid has been putting its data analytics platform to use hunting for value out there on the grid for Sonnen’s current and future battery fleet. “In a big service territory, you need quite a few of our devices to make a measurable impact,” Lohr said. “But because we can pinpoint it by substation, a utility could roll it out to provide capacity in certain sub-territories, or to avoid infrastructure upgrades" -- both use cases that are being considered for energy market reforms in California, New York and a few other states.
News Article | October 23, 2015
Rooftop PV and behind-the-meter batteries can team up to reduce customer energy bills, shave off expensive peaks in building energy consumption, and store midday solar-generated electrons for evening discharge to help smooth out their impact on the grid. But more complicated functions, like balancing voltage on distribution grid circuits, or disconnecting and reconnecting to the grid for emergency backup power, require a third technology: smart inverters. On Thursday, the SunSpec Alliance, the University of California-San Diego, and SolarCity launched a project meant to test this emerging standard for advanced inverter functionality. It’s the first real-world test of a technology set to be mandated for all new solar and battery projects in California in 2016, a fact that’s drawn some of the world’s biggest inverter makers into the project. “We have an ensemble cast of partners here,” SunSpec Alliance chairman Tom Tansy said. Funded by a $2 million California Energy Commission EPIC grant, the $4 million project will run interoperability tests featuring inverters from seven different global manufacturers -- ABB, SMA, KACO, Outback, SolarEdge, Enphase and Ideal Power. Starting late this year, each company will submit their smart inverters, along with chosen battery and solar integration partners, to testing by UCSD. The university’s state-of-the-art microgrid, which includes pretty much every form of distributed energy known to humanity, will provide a useful control and renewable power resource for the testing, Tansy said. “That’s where we’ll prove out our communications interoperability, via the SunSpec standard,” he said. SunSpec and partners have built a set of standards around linking inverters with components like batteries, solar panels, and energy management systems. “They’ll be doing things like curtailment, voltage regulation, frequency regulation, both on power from the solar array and from storage.” Almost all of today’s solar and battery inverters come with advanced features that fit this description of “smart.” But very few companies are turning them on, let alone communicating with utilities and grid operators about what they’re doing, and what they’re capable of. That’s largely because most utility and grid regulatory frameworks haven’t kept up with distributed energy’s growth. There isn’t even an Underwriters Laboratories specification for smart inverters yet, although a California-led group is working with UL and inverter makers to fill that gap by next year. UCSD is also providing its digital models of its distribution circuits -- the campus is like a grid in miniature, and submetered to an unusual degree for public buildings. OSIsoft, the biggest provider of data management software for utility SCADA deployments and other resources of circuit-level data, is participating in that part of the project as well, he said. Project partners will also pull data from the distribution circuit maps newly unveiled by the state’s big three utilities, including UCSD’s utility, San Diego Gas & Electric. The broader goal is “to see how deeply a circuit can be penetrated,” he said. At most utilities, “there’s an artificial cap of about 15 percent of the total demand capacity that can be offset with renewable energy” and other distributed energy resources (DERs), he said, in terms of how much a distribution grid circuit can bear before causing potential problems. But tests at Department of Energy labs, and analyses of real-world circuit data in DER-rich grid locales in Hawaii and California, indicate that many circuits can bear a much higher portion of distributed energy -- and even benefit from it -- as long as it’s planned and managed well. CEC’s grant request form (PDF) describes the project’s goals: “To develop a complete smart inverter data communication standardization and go-to-market solution to enable photovoltaic (PV) penetration beyond the 15% Institute of Electrical and Electronics Engineers (IEEE) guideline, incorporate energy storage as a standard building block of PV systems, and evaluate the market-expansion potential of a standardized communication interface.” This brings us to SolarCity’s part in the project, which is distinct from the UCSD work. The aggregator of hundreds of thousands of solar systems across California will seek out about 50 customers on a specific test circuit of Southern California Edison’s sprawling distribution grid, and equip each with a lithium-ion battery system, capable of providing roughly 7 to 10 kilowatt-hours of storage, Tansy said. That just happens to also be the range of specs for Tesla’s new Powerwall home energy storage systems, by the way. Ryan Hanley, senior director of grid operations for SolarCity, wouldn’t say which battery and inverter partners the company planned to work with on the project, which is set to start some time early next year. But SolarCity is “cost-sharing more than we’re getting from the grant -- we’re putting up more in R&D and program support than we’re receiving.” “We are going down to one circuit and finding 50 residential customers, and deploying 50 smart energy homes on that circuit,” he said. “In each home, we’ve got solar PV, a smart inverter, a residential battery, and a smart thermostat.” That last control point allows access to air conditioning, a key ingredient of household electricity load that could provide more flexibility in absorbing and redirecting solar power. Think of precooling a home with plentiful solar energy, and “storing” that cool to let the AC idle through the late afternoons and early evenings, when large swaths of Southern California circuits reach their peak, for example. On the inverter-grid interconnection front, SolarCity plans to provide three main services with its aggregated 350 to 500 kilowatt-hours of storage. “The first one we’ll do is support voltage needs on the feeder,” he said -- something that requires advanced inverter functions to operate in concert with each other and utility-facing grid sensors and controls. Second, 50 homes will also support local capacity needs for the substation serving the circuit, much as SCE’s local capacity resource procurements are doing with storage from Stem, Ice Energy/NRG and Advanced Microgrid Solutions. “The third one, which is my favorite, is we’re aggregating all 50 of those systems and providing wholesale grid support,” Hanley said, through the Proxy Demand Resource demand-response program run by grid operator CAISO. “What’s of note here is that it’s a heterogeneous portfolio. It’s the first time we’ve aggregated different technologies and bid them into CAISO. The rules were just recently changed to allow this,” he said, with a big demand-response auction set for later this year, and rules for how distributed assets can play in DR markets still under development for rollout over the next few years. SolarCity’s control platform, which manages its small but growing fleet of Tesla battery-backed solar homes and businesses, will also control this 50-home fleet as a virtual power plant, capable of responding to utility signals and, in some instances, turning themselves over to utility control, he said. The combination of customer and utility benefits from this arrangement are complex, and “part of the goal of the project is to quantify that,” he said. SolarCity isn’t the first to bid behind-the-meter battery flexibility into California’s grid markets -- behind-the-meter startup Stem has done that in pilot projects in the past two years. Nor is it the first to test solar-battery grid support and load shifting capabilities. The Sacramento Municipal Utility District has a big residential solar-battery test underway. Southern California Edison has the stimulus-grant-funded Irvine smart grid demonstration test bed, and California’s big three IOUs want to do many more pilots over the next few years as part of their distribution resource plans. But the project SolarCity is part of is the first to use the standard smart inverter specification so soon to become a mandatory part of California’s new solar fleets. UCSD’s inverter tests will serve as a blueprint for SolarCity to interconnect its various distributed energy assets, Hanley said, although it’s not planning to test every new inverter in its 50-home pilot -- “We’ll probably be using one inverter, maybe two,” although that could expand over time. More broadly speaking, “we believe the industry is better off the sooner smart inverters are widely deployed, and we want to do everything we can to accelerate that,” he said. California is in the midst of reworking its utility regulations to bring DERs into play with utility grid operations and planning, and stand in for part of utilities' multi-billion-dollar investment plans, to reward what they do for the state's renewable energy and carbon reduction goals. The sooner advanced inverter functionality is part of that DER market, the faster new rules and markets will evolve to express that value in terms of kWh and kVAR, and eventually, dollars and cents.
News Article | February 15, 2017
LOS ANGELES (Reuters) - A firm controlled by Philip Anschutz, the billionaire entertainment and pro sports magnate, will soon build the largest wind farm in the United States to serve utilities in California, where officials have set ambitious green power goals. The $5 billion project, however, will be constructed 700 miles away in Wyoming, a state better known for coal mines and oil fields. The vast distance between the two states provides a different Anschutz-owned firm with another big opportunity: a $3 billion project building transmission lines to deliver the power - one of a dozen similar power-line projects by other companies across the West. In all, about 5,700 miles of transmission lines are in development with the goal of delivering renewable energy to California from other states, according to the Western Interstate Energy Board. Such investments are an outgrowth of an emerging paradox of California’s well-known political bent toward aggressive environmentalism. Green power advocates and state officials want more wind power – but California conservationists increasingly oppose more wind farms as an environmental blight on the state’s pristine desert landscape. Those conflicts are pushing wind farm development to other states, creating new opportunities for wind power and transmission firms to deliver electricity to California's nearly 40 million residents. "It's the right project, in the right place, at the right time," said Bill Miller, chief executive of the two Anschutz-owned companies - Power Company of Wyoming LLC and TransWest Express LLC. Though wind power is surging nationally, the future of wind farms in California suffered a major blow last year when regulators completed an eight-year process designed in part to identify locations for new renewable energy projects. The U.S. Bureau of Land Management, the California Energy Commission and state and federal wildlife agencies sought to balance green power development with preservation of scenic vistas, Native American tribal lands and critical habitats for threatened species such as the desert tortoise and the Mohave ground squirrel. But the solar and wind power industries have argued that the resulting plan unfairly favors land conservation over projects needed to wean California off fossil fuels and combat climate change. The California Wind Energy Association estimates that only 2 GW of additional wind power can be developed here, a figure its executive director, Nancy Rader, called “a stretch.” California will need about 15 GW to meet its goal of deriving half of its power from renewable sources by 2030 - and far more if the state succeeds in a separate effort to promote electric vehicle adoption, according to state estimates. Anschutz, who lives in Denver, got his start in the oil drilling industry in Wyoming. He has amassed a fortune of $12.5 billion, according to Forbes, through real estate and entertainment properties including the movie theater chain operator Regal Entertainment Group. Anschutz Entertainment Group holds ownership interests in professional sports teams including hockey’s Los Angeles Kings and basketball’s Los Angeles Lakers, along with dozens of major arenas, theaters and music festivals. The billionaire’s backing helped the Power Company of Wyoming and TransWest Express support their wind and transmission projects through an eight-year permitting process that Miller said cost $100 million. Now other developers are watching those projects as a bellwether for their own planned investments in transmission lines to bring renewable power to California. "If we see another project being successful, then we'll be a lot more willing to invest $100 million in permitting," said Michael Skelly, president of Clean Line Energy Partners LLC, which has proposed two separate transmission projects in the West but is currently focusing on the Midwest. Factors beyond California's environmental politics are driving investments in wind farms outside the state. Nationally, the costs of wind power generation have dropped 66 percent in seven years, according to the American Wind Energy Association, an industry trade group. Further, California already has wind farms in the areas best suited for them, and states such as Wyoming offer lower construction costs and higher winds. Those lower costs are what make billion-dollar transmission projects feasible. A report prepared for California state agencies last year estimated that Wyoming and New Mexico wind power, using new transmission, would cost $21 per megawatt-hour, compared with $43 to $58 per MWh for in-state wind. California state policy, meanwhile, offers a virtual guarantee of high demand for renewable energy. The state is currently only about halfway to its goal of deriving half of its electricity from renewable sources by 2030, according to the California Energy Commission. Helping the state meet that target is the "next big market opportunity" for a project under development by Duke American Transmission Co., a partnership between Duke Energy Corp and American Transmission Co., said DATC spokeswoman Luella Dooley-Menet. Since 2011, the company has been developing the $2.6 billion Zephyr transmission line to run from Wyoming to Utah, where it will connect with existing lines running into California. Power would be supplied by another wind power project under development in Wyoming, the $4 billion Pathfinder wind farm, from a company backed by privately-held conglomerate Sammons Enterprises Inc and investment firm Guggenheim Partners. Transmission spending by utilities has more than doubled since 2010 and is projected to reach $22.5 billion this year, according to the Edison Electric Institute, a utility trade group. That spending, however, has largely not included large, multi-state projects, which are more difficult to get approved and built. "The big systems that are going to allow for a much more dynamic bulk power market, within regions and between regions - those are the tough ones," said Jim Hoecker, an energy attorney who advises the transmission trade group WIRES. Developers of the SunZia line - a $1.5 billion transmission project that will stretch 500 miles between New Mexico and a major transmission hub in Arizona - understand the permitting challenges. Its owners agreed to bury segments of power lines that will run near the White Sands Missile Range in New Mexico - at substantial additional cost - after the U.S. Department of Defense raised objections. The SunZia line, scheduled to start construction next year, is owned by MMR Group, Royal Dutch Shell Plc's wind energy unit, and Tucson Electric Power, a unit of Fortis Inc. It aims to transport wind energy from a Pattern Energy Group LP project in New Mexico. Pattern partnered with SunZia's developers last year after reaching two deals in 2015 to supply electricity to Southern California Edison and Sacramento Municipal Utility District with low-cost wind from New Mexico. Pattern realized it couldn't continue to invest in the state without new transmission. "SunZia was the best alternative to bring additional power from New Mexico into Arizona and California," Pattern CEO Mike Garland said. In Wyoming, construction started late last year on the Anschutz-owned Chokecherry and Sierra Madre wind project, and the company is in talks with utilities to buy the power and suppliers to provide about 1,000 turbines that will spin on the site. After eight years in development, the project seems to align well with the needs of California regulators and utilities, which need more wind power from out of state to augment in-state solar installations that can’t provide power during nighttime hours. "A whole bunch of things kind of had to line up," Miller said. "Now, they have pretty much lined up."
News Article | October 28, 2016
FOLSOM, CA--(Marketwired - October 21, 2016) - The California Independent System Operator (ISO) welcomes today's announcement by the Balancing Authority of Northern California (BANC) and Sacramento Municipal Utility District (SMUD) of their intent to join the ISO's western Energy Imbalance Market (EIM). The EIM is a real-time, wholesale power market managed by the ISO that enables participating utilities to buy low cost energy available across eight western states, including California, Oregon, Washington, Utah, Idaho, Wyoming, Nevada and Arizona. The efficiencies created by pooling resources across a wide geographic area provide cost savings and environmental benefits. After completing a study on the benefits of joining the EIM, BANC -- a joint powers agency whose members include the Modesto Irrigation District, the City of Redding, the City of Roseville, SMUD, the City of Shasta Lake and Trinity Public Utilities District -- announced their intent to begin negotiations with the ISO on behalf of their members. SMUD, the nation's sixth largest municipal utility, has elected to be the first BANC member to participate. "We are extremely pleased to see a major regional public power utility, like SMUD, step forward to engage in the EIM," said Steve Berberich, ISO president and CEO. "We are confident we can create an agreement that provides efficiencies and savings to SMUD and other BANC members." The EIM uses state-of-the-art software to automatically analyze western grid needs and find low-cost generation to meet demand every five minutes. Participating utilities also can access low-cost renewable energy across state lines in real-time to offset power generated from local fossil-fueled plants. The cost and environmental benefits produced by the EIM to date have been significant. Since it began operation in November 2014, the western EIM has realized more than $88 million in cost benefits and reduced carbon emissions by more than 126,000 metric tons by using excess renewable energy in place of fossil-fueled generation resources. BANC, SMUD and the ISO will begin crafting an agreement that will recognize BANC's unique circumstances as a public power entity and enable them to phase-in their EIM participation while continuing to meet their existing power supply arrangements. Current EIM participants include Portland-based PacifiCorp, NV Energy of Las Vegas, Arizona Public Service, and Puget Sound Energy of Washington. Portland General Electric and Idaho Power have agreed to participate beginning in 2017 and 2018, respectively. Earlier this week, Mexican grid operator El Centro Nacional de Control de Energía (CENACE) announced that it is exploring participation in the EIM. For more information on the EIM, visit the overview webpage. For more information on SMUD, visit here and on BANC, visit here. The California ISO provides open and non-discriminatory access to one of the largest power grids in the world. The vast network of high-voltage transmission power lines is supported by a competitive energy market and comprehensive grid planning. Partnering with about a hundred clients, the nonprofit public benefit corporation is dedicated to the continual development and reliable operation of a modern grid that operates for the benefit of consumers. Recognizing the importance of the global climate challenge, the ISO is at the forefront of integrating renewable power and advanced technologies that will help meet a sustainable energy future efficiently and cleanly. The following files are available for download:
News Article | October 28, 2016
Associated reductions in carbon emissions using renewables now total about 144,000 metric tons FOLSOM, CA--(Marketwired - October 26, 2016) - The California Independent System Operator (ISO) reported today that benefits of the western Energy Imbalance Market (EIM) for third quarter 2016 were $26.16 million. This brings the total benefits since the western regional market was launched in 2014 to $114.35 million. The favorable results were driven primarily by the impact of the change in seasons on energy supply and demand. A similar trend was noted in the results for Q2 to Q3 in 2015. During Q3 2016, the western EIM also reduced carbon emissions by 14,164 metric tons. These emission reductions were made possible by using 33,094 megawatt-hours of excess renewable energy instead of using energy generated by fossil fuels. "The western EIM continues to be a healthy and robust marketplace that is delivering substantial benefits for its participants," said ISO President and CEO Steve Berberich. "Besides enhancing grid reliability, the EIM helps parties in the West to share low cost, renewable energy, which helps reduce carbon emissions and enables the achievement of clean air goals across the region. The benefits will grow as more utilities elect to participate in the EIM." NV Energy realized a total benefit of $5.6 million in the third quarter. Benefits to PacifiCorp came in at $15.12 million, while the ISO realized $5.44 million. Puget Sound Energy of Washington state and Arizona Public Service entered the EIM in October; their results will be noted in the Q4 2016 report. Meanwhile, Portland General Electric will begin participating in October 2017 followed by Idaho Power in April 2018. Most recently, the Sacramento Municipal Utility District (SMUD) and the El Centro Nacional de Control de Energía (CENACE) have separately announced their intention to enter or explore entering the EIM. The EIM uses state-of-art technology to automatically optimize the real-time grid and find lower cost energy regardless of its location to serve consumers in California, Arizona, Oregon, Washington, Utah, Idaho, Wyoming and Nevada. More efficiently using resources from across the West reduces the need to curtail renewables by using excess energy in one region to serve demand in another. Another benefit comes from lessening the amount of energy reserves utilities must carry as they can lean upon resources outside of their service area to serve their load at less cost. Click here to view the third quarter 2016 EIM benefits assessment report. Here is the news release announcing SMUD's intention. Follow this link to read the CENACE announcement. The California ISO provides open and non-discriminatory access to one of the largest power grids in the world. The vast network of high-voltage transmission power lines is supported by a competitive energy market and comprehensive grid planning. Partnering with about a hundred clients, the nonprofit public benefit corporation is dedicated to the continual development and reliable operation of a modern grid that operates for the benefit of consumers. Recognizing the importance of the global climate challenge, the ISO is at the forefront of integrating renewable power and advanced technologies that will help meet a sustainable energy future efficiently and cleanly. The following files are available for download:
News Article | March 4, 2016
The board of directors at Sacramento Municipal Utility District has decided not to proceed with construction of the 400-MW Iowa Hill pumped-storage hydro project.