The Bonneville Power Administration is an American federal agency operating in the Pacific Northwest. BPA was created by an act of Congress in 1937 to market electric power from the Bonneville Dam located on the Columbia River and to construct facilities necessary to transmit that power. Congress has since designated Bonneville to be the marketing agent for power from all of the federally owned hydroelectric projects in the Pacific Northwest. Bonneville is one of four regional Federal power marketing agencies within the U.S. Department of Energy . Wikipedia.
News Article | October 12, 2016
Early this month, a federal judge forced discussion of a radical step to save endangered salmon: taking out four somewhat large hydroelectric dams on the Lower Snake River in Washington State. These four dams include Ice Harbor, Lower Monumental, Little Goose and Lower Granite Dams. They are fairly old dams and were not optimized for salmon survival. They were built primarily for navigation of barge and various river traffic, for low-carbon power, and to lesser degrees for flood control and irrigation. And despite millions of dollars spent on fish passage improvements, adult salmon still die in the reservoirs behind the dams, especially as the water can get quite warm sitting there during the summer. In addition, the Snake River is the gateway to thousands of square miles of pristine, high-elevation habitat in Idaho, Washington and Oregon, essential for salmon survival in a warming climate. Significantly, the necessity of these dams for navigation has fallen since the region’s rail system has dramatically improved and truck transport can handle the rest. But it’s the power generation of these dams that gives us an environmental conundrum. Which is more important, salmon or carbon emissions? Ice Harbor Dam produces 1.7 billion kWhs/yr, Lower Monumental 2.3 billion kWhs/yr, Little Goose 2.2 billion kWhs/yr and Lower Granite 2.3 billion kWhs/yr, which total about 4% of the State’s electricity generation. For comparison, the nearby nuclear power plant at Columbia Generating Station produces over 9 billion kWhs/yr. Grand Coulee Dam, the largest electricity generating station in the State, and the second largest on the nation, produces 20 billion kWhs/yr. So the electricity lost by taking out these dams can be replaced by other sources, but if you care about the environment, it matters what you build to replace this power: - a single large nuclear plant like those being built in Georgia, - a small modular nuclear plant with 12 modules from companies like NuScale, - five solar plants the size of the biggest solar plant in the country, or - seven thousand MW wind turbines, as many as presently exist in the entire State. Even though a small modular nuclear plant would replace both the low-carbon power and the grid flexibility of these dams, natural gas is the obvious choice for the utility. Regulators are eager to approve gas plants, natural gas fuel costs are low, and the initial construction costs for gas are the lowest of any energy source. Most importantly though, like hydroelectric and small modular reactors, natural gas is a source that can be cycled up and down rapidly to buffer the increasing amount of renewables coming onto the grid. Dams presently provide almost all of that flexibility in the Pacific Northwest so losing these dams necessitates a replacement that can also cycle quickly. Elsewhere in the region, Washington State’s last coal plant is shutting down in 2025, which will result in almost a 50% drop in energy sector emissions overnight. But replacing these Snake River dams with natural gas would completely offset that reduction in emissions. The Bonneville Power Administration says it would replace these Lower Snake River dams with two modern gas turbines. Such a replacement would cost an additional $274 million to $372 million each year, and would increase carbon emissions by almost 3 million tons per year. U.S. District Court Judge Michael H. Simon sided with the State of Oregon, the Nez Perce Tribe, fishing groups, and environmentalists, saying that federal plans for protecting fish were not adequate, and ordered the agencies to prepare a new plan by early 2018. Moreover, Simon stated that federal agencies had "done their utmost" to avoid even considering breaching the Snake River dams, against the court’s previous suggestions to do so. While Simon said he wouldn't dictate what options agencies should consider, he said a proper analysis under federal law "may well require" considering breaching, bypassing or removing one or more of the four Lower Snake River dams. "Scientists tell us that removing the four Lower Snake dams is the single most important action we could take to restore salmon in the entire Columbia-Snake river basin," said Sam Mace of Save Our Wild Salmon. But Terry Flores, executive director of Northwest River Partners, representing public utilities, port districts and farm groups, disagrees, saying "We think those dams need to stay in place because of the multiple benefits they provide. They provide clean, carbon-free energy. We think they're an important part of the Northwest economy and the environment.” Taking out dams might sound easy, but there are some tricky issues. We have not yet decommissioned a huge hydroelectric dam, so it’s not easy to claim it will go as planned. Many positive effects like increased quality and quantity of fish species are offset by some adverse effects like decrease in mussel and other invertebrate species downstream. The relative dominance of good and bad depends strongly on how well the plan is designed and carried out. As a geologist, I have long worried about what to do with the huge sediment wedges behind the large dams. There are many upstream and downstream issues that have to be handled very well in order not to suffocate everything downstream and to protect the habitat upstream from gullying. Big dams must be decommissioned in stages in order to allow the sediments to be slowly eroded, hoping that most will not migrate downstream for decades. An excellent discussion of dam removal can be found at the U.S. Forest Service website and by Gordon Grant. Whatever is decided about the Lower Snake River dams, we can do it right if we want. Dr. James Conca is a geochemist, an energy expert, an authority on dirty bombs, a planetary geologist and professional speaker. Follow him on Twitter @jimconca and see his book at Amazon.com
News Article | April 11, 2016
The 20th-century power grid is an engineering marvel, delivering power generated at central power plants to millions of end customers through a transmission and distribution network that represents the world’s largest machine. The 21st century power grid will be all this, plus a lot more. This new grid will require technologies and business models that can link utilities and customers to turn distributed energy resources like rooftop solar and electric vehicles from grid disruptors into grid assets. It will also need new regulatory structures and energy markets to allow the cost-effective application of energy efficiency, demand management and energy storage systems required to integrate massive amounts of intermittent wind and solar power into the grid at large. For the past three years, Greentech Media has been highlighting some of the companies at the heart of this transformation with its Grid Edge Awards list. This year’s winners include some of the country’s biggest utilities and grid vendors, as well as behind-the-scenes technology providers and software startups, and several projects that bring utilities and third parties together in innovative ways. Awardees are nominated by and voted on by energy industry stakeholders, including the team of analysts at GTM Research. The energy storage industry could really use some standards, according to 1Energy Systems -- and the company wants its software to be at the heart of them. Since its 2011 founding, the Seattle-based startup has deployed its software to manage battery projects at home-state utilities Snohomish PUD and Puget Sound Energy, AES Energy Storage’s 20-megawatt Cochrane project in Chile, Duke Energy’s Rankin battery project, and Austin Energy’s 1.5-megawatt project. 1Energy has also gathered a growing roster of battery and inverter makers, grid technology vendors and utilities around its Modular Energy Storage Architecture (MESA) Alliance. The MESA Device specification, developed in partnership with the SunSpec Alliance, is meant to allow batteries, inverters and other energy storage components to interoperate smoothly. The MESA ESS specification extends that interoperability to utility SCADA and DMS platforms, and potentially to non-utility energy storage aggregators. 1Energy’s ambitions extend beyond batteries as well, with the October launch of its Distributed Energy Resource Optimizer, or DERO, platform. The proving points for this application of its underlying software are coming through its work with original utility partner Snohomish PUD, as well as in Austin Energy’s solar-storage integration work under its $4.3 million SHINES grant from the Department of Energy’s SunShot program. Managing the complexities of the grid edge requires managing an immense amount of data, coming in a multiplicity of formats and time signatures, from a wide variety of distributed energy resources. AutoGrid Systems has built its business on analyzing and making sense of this data, through its underlying cloud-based unstructured data analytics and management engine, dubbed its Energy Data Platform, and applications developed in-house and with a long list of energy industry partners. Since its 2012 unveiling, the Palo Alto, Calif.-based startup has landed projects with utilities in California, Oklahoma and Texas, has secured funding from Japan’s NTT and Germany’s E.ON, the Bonneville Power Administration, and other partners. Its first application, dubbed its Demand Response Optimization and Management System, has grown from helping Oklahoma Gas & Electric optimize its smart thermostat-based load management program, to enabling Dutch utility Eneco create a “software-defined power plant” from responsive loads and generation resources at commercial and industrial sites. The behind-the-meter energy landscape is ripe with assets that can be enlisted to help serve both customer and utility energy needs. That’s the business that Blue Pillar has taken on. Starting from its roots designing and testing emergency backup power systems for hospitals, the Indianapolis-based company has since expanded into networking and automating control of a wide variety of behind-the-meter assets. Blue Pillar has converted this expertise and library of device data into a software platform, dubbed Aurora, that it’s now making available to utilities and energy service providers including NRG Energy. The idea is to turn its behind-the-meter smarts into a distributed energy resources management software platform, allowing for building energy needs and grid energy needs to be aligned. BMW Group isn’t just one of the many automakers that are building electric vehicles. It’s also building out a comprehensive strategy to integrate them, and the energy storage opportunities they represent, into a broader energy management strategy. That include BMW’s iCharge Forward program, which launched last year and unveiled its first major project with California utility Pacific Gas & Electric in January. It also involves the testing of “second-life” batteries in stationary applications, with an inaugural array featuring software from startup Geli, inverters from Princeton Power and Kaco, and EV chargers from ChargePoint and ABB. Earlier this year BMW denied reports that it’s planning an entry into the behind-the-meter energy storage market, although it’s also working with German heating systems maker Viessmann Group on a joint venture called Digital Energy Solutions to manage energy management systems at commercial and industrial customers in Germany and Austria. The country’s biggest utility is also one of its most innovative, in terms of bridging the gap between traditional utility business models and the grid edge. One of its most notable efforts is its “Coalition of the Willing,” which has gathered a growing number of companies to build equipment around common technology specifications to allow them to communicate and act in the field, sometimes independently of central control. That work has led to the creation of a new technical specification, the Open Field Message Bus (OpenFMB), now being developed as a standard by the Smart Grid Interoperability Panel. Omnetric Group, a joint venture between Siemens and Accenture, has played an important role in this work, taking on interoperability testing with the National Renewable Energy Laboratory. Duke has also committed to other interoperability standards, such as the MESA standard for energy storage, and is testing them out in real-world microgrid settings. While this work is going on at Duke’s regulated utilities, its unregulated arm is expanding into new business models through Duke Energy Renewables. The group includes acquisitions California solar installer REC Solar and energy management company Phoenix Energy Technologies, and it is working with partners including Green Charge Networks to bring comprehensive solar-storage-energy management solutions to commercial and industrial customers. More and more utilities are exploring how best to develop a long-term solution for supporting distributed solar, whether it’s through distribution grid upgrades to support net-metered solar or by seeking permission to own their own rooftop PV. But National Grid is the first electric utility in the country to collaborate with a solar marketplace, through its partnership with EnergySage. Its SolarWise Rhode Island project, launched this spring, allows customers to comparison-shop solar opportunities for their home or business and receive competitive quotes from prescreened installers via EnergySage’s online marketplace. National Grid, meanwhile, provides a long-term solar payment as an alternative arrangement to the state’s net-metering credit, with premiums for customers who reduce their energy consumption before installing PV. That potentially opens the rooftop PV proposition to homes and businesses for which it wouldn’t otherwise make economic sense, while also giving the utility some input and guidance for the process of bringing its customers solar. While other utilities, such as Georgia Power, have launched solar marketplace platforms, they’ve largely been tied to utility-specific offerings. National Grid and EnergySage are among the first to open the platform to the hundreds of installers linked up through the EnergySage platform. The startup has won the endorsement of the Solar Energy Industries Association, and is looking for other utilities that want to join forces. One might say that Green Mountain Power has more opportunities than your average utility. It’s the chief investor-owned utility in the state of Vermont, but the state’s alternative energy regulatory system has allowed it to bring novel business models and technologies to market, and to support expansion of solar net metering where other utilities have fought it tooth and nail. Green Mountain Power’s “Energy City of the Future” project is the centerpiece of this innovation. The project in Rutland, Vermont will combine rooftop solar, behind-the-meter batteries, smart thermostats, energy-efficiency improvements, and real-time connectivity to its distribution grid and customer data systems, with the goal of aligning customer and utility needs. The project includes Dynapower and SolarEdge inverters, solar installer groSolar, and up to 500 of Tesla’s Powerwall batteries, which will be made available through a first-of-its-kind utility sales and leasing program that allows the utility to reduce costs to customers in exchange for making the batteries’ capabilities available to the utility. Hawaiian Electric has been investing in many different technologies to help manage the increasing amount of intermittent wind and solar power coming onto its island grids. But one project in particular won an award for renewable-grid integration at this year’s DistribuTech conference -- its deployment of Gridco’s in-line power regulators (IPRs) to stabilize voltages on a set of west Oahu circuits heavily loaded with distributed PV. Gridco’s IPRs are among a class of new power electronics devices that can deliver an unprecedented level of digital control over the alternating current energizing the distribution grid, including voltage regulation, reactive power compensation and harmonic mitigation. HECO’s deployment, underway since last year, represents the first publicly disclosed use of the Woburn, Mass.-based startup’s technology to solve a problem specific to high-penetration PV -- reducing over-voltages caused by an excess of solar power, while also maintaining voltage levels when the sun isn’t shining. GTM Research has predicted that the U.S. market for these devices will reach $320 million by 2017 for the business case of solar PV integration, which is a particularly challenging problem to solve using traditional utility grid equipment and control systems. With its Gridco deployment, HECO is breaking ground on that business proposition. Over the past decade or so, Cincinnati-based Integral Analytics has quietly established itself in some of the leading grid-edge efforts underway in North America, with a suite of software tools that tackle both the real-time and the decades-ahead scope of distributed energy resource (DER) integration. Now the privately funded company’s approach is starting to bubble up into the regulatory framework of energy innovations in states like California. IA’s IDROP (Integrating Distributed Resources into Optimal Portfolios) software takes on the task of establishing the real-time values of DERs for dispatch and control, and it is being used in projects like Duke Energy’s McAlpine substation smart grid test bed and the PowerShift Atlantic project in Canada’s Maritime provinces. Its LoadSEER (Load Spatial Electric Expansion and Risk) platform expands these DER value calculations into decades-ahead forecasts and planning constructs, and it is being used by California utilities including PG&E and SDG&E. Integral Analytics has also coined the term "distributed marginal price," or DMP, to refer to the grid-edge values its software platforms deliver. The idea of DMP is similar to the New York Reforming the Energy Vision proceeding’s LMP+D metric, referring to the locational marginal price values used by grid operators, only broken down to distribution-grid levels of granularity. California’s Distribution Resources Plan proceeding has seen the DMP concept brought forward by distributed energy advocates eager to see it incorporated into the state’s valuation of DERs as grid replacements. Itron is North America’s biggest smart meter vendor, but it wants to be much more. In 2014, it staked its claim to the next generation of networked energy devices with the launch of its Riva platform. This IPv6-compliant, multi-communications-capable technology architecture, beefed up through a partnership with Cisco, was among the first from a major AMI vendor to embed Linux programmable processors in its endpoints, enabling its meters and communication devices to run applications that interact with a growing number of partner devices. Since then, Itron Riva has integrated with smart inverters from Fronius, EV chargers from Clipper Creek, and a number of smart thermostats, water heaters, pool pumps and other behind-the-meter devices. Itron’s New Business Innovations team has been experimenting with other intelligent devices, such as smart streetlights and solar gateways, and its Riva Developers Community has opened up its underlying technology to partners around the globe. Itron has also been expanding its extensive analytics capabilities to use in its new distributed computing environment. In October, CEO Philip Mezey set the second half of 2016 for the launch of OpenWay Riva, which will bring these new capabilities to the fore for utility customers. And that’s not counting the internet-of-things applications it’s looking for to expand its market beyond the utility. Kansas City Power & Light’s Interactive Energy Platform deployment is the utility’s attempt to tap the power of edge-of-grid resources to reduce costs of grid upgrades and meeting peak loads with new generation resources. Working with demand-side management software vendor Innovari, the utility has implemented a platform to monitor and control customer building loads and other edge-of-grid resources both to solve system constraints isolated to individual feeders/substations, and to improve overall system utilization. Innovari’s Interactive Energy Platform ties these multiple grid-edge systems into a generation-quality capacity asset with real-time, two-way verifiable, closed-loop control. That delivers performance akin to a peaker plant, but at half the cost and with none of the emissions. The New York Power Authority’s Energy Manager program may be the single biggest effort to integrate building-side energy management data with statewide energy goals. The energy monitoring operations center at SUNY Polytechnic Institute will provide comprehensive energy reporting for more than 3,000 public buildings, in order to help to meet the state’s BuildSmart NY goal to reduce energy consumption by 20 percent in state government facilities by 2020. Talisen’s Enterprise Sustainability Platform serves as the underlying data collection, analysis and reporting analysis platform for the operations center. The St. Louis, Mo.-based company has deployed with its home city and state on similar building energy management and sustainability software deployments, and recently launched operations in Dubai. NYPA’s operations center has a larger role to play in the state’s Reforming the Energy Vision initiative, which envisions demand-side management becoming a commodity on future distribution system markets. The agency is already working with other cities in New York state, and intends to support effective measurement and verification tools for energy-efficiency projects and to support NYPA’s demand response programs. We first met Ohmconnect in 2014, shortly after it unveiled its plans for turning home energy-saving alerts into grid revenues. Since then, the bootstrapped San Francisco-based startup has landed some big wins, capped off with the January news that it had won a bid to provide more than 7 megawatts of capacity to California’s Demand Response Auction Mechanism (DRAM) pilot. Ohmconnect started out providing homeowners with smart meter energy data and usage alerts to encourage efficiency. But it has moved into the realm of getting lots of homes to reduce energy use quickly and reliably enough to meet the local demand-reduction needs of utilities and grid operators, and earn revenues as a result. It’s also moved into the world of smart devices, including its work with smart EV-charger startup eMotorWerks, and a partnership with Schneider Electric that’s one of the first to deliver the grid giant’s Wiser line of smart thermostats and energy management devices outside of utility channels. The first big test of its combination of motivated energy-saving customers and demand-responsive devices will come this summer, when it will begin to deliver the megawatts' worth of localized load reduction it has promised for the DRAM program. California’s DRAM program has its antecedents in a series of pilot projects that have laid the groundwork for how grid edge-enabled DERs can play a role in utility and grid operations. It started with Pacific Gas & Electric’s Intermittent Renewable Management Pilot Phase 2 (IRM2) in 2014, and was followed the next year by PG&E’s Supply Side Pilot (SSP) -- the first-ever opportunity for distributed, aggregated resources to bid themselves into the state’s wholesale power markets. We’ve covered how companies such as Stem, Ohmconnect and Green Charge Networks have taken advantage of these pilot programs. But the mastermind of these pilots is San Ramon, Calif.-based Olivine, the “scheduling coordinator” that manages the interaction of these third-party resources with programs run by the state’s grid operator, CAISO. That’s put Olivine in the position of arbitrating the state’s initial moves from traditional centrally controlled, siloed demand response, into a new paradigm based on market signals and broad-based participation by distributed energy owners and aggregators. The DRAM pilot is the next step, but CEO Beth Reid has also told us that we should stay tuned for PG&E’s Excess Supply Pilot (XSP), which will for the first time pay end users who can absorb excess solar and wind energy, as well as turn down energy to reduce peak loads. What does the microgrid of the future look like? To answer that question, one could do worse than to travel to Lancaster, Texas to visit the state-of-the-art microgrid unveiled by Oncor there last summer. Working with S&C Electric, Schneider Electric, Tesla Energy and other parties, the Dallas-area utility has put together a self-powered island of stability for its on-site telecommunications center, as well as a test bed for integrating multiple distributed energy resources in ways that can also serve the grid’s larger needs. The Oncor microgrid (PDF) has networked four different sites at its System Operating Services Facility, involving nine different distributed generation resources: two solar PV arrays, a microturbine, two energy storage units, and four generators. It’s capable of islanding and powering itself at a peak capacity of 900 kilowatts for two hours, or 550 kilowatts once its solar and battery power has fallen away. Beyond the system's real-world uses, Oncor wants to demonstrate how it could build, own and operate microgrids for its customers -- something that utilities around the country want to do. Operating in Texas’ competitive energy market, Oncor has been rebuffed in its attempt to rate-base billions of dollars in grid battery investments. Perhaps microgrids-as-a-service are another way to bridge the utility-grid edge divide. Hydro One Networks, one of Canada’s largest utilities, has been deploying a host of asset management and grid intelligence technologies to help it manage the growth of intermittent wind and solar power on its system and its Distributed Energy Management and Storage Network project is taking on the distribution side of this equation. Veridian Connections another large utility is also innovating with distributed energy resources in the form of two residential microgrid systems, including 10 kilowatts of solar, 14 kilowatt-hours of batteries, EV-charging systems, and the GridOS software platform developed by Opus One. Opus One uses real-world electrical models and sophisticated power flow optimized state-estimation algorithms to help assess DER interconnection impacts, make real-time loss calculations, and enable the intelligent dispatch of energy storage and demand-responsive loads. The Ontario-based company's software is also being used in an “integrated urban community energy” project in Toronto, single-site and community microgrids, and volt/VAR optimization systems. With other North American utilities, it’s developing the information and intelligence to integrate data from various distribution automation devices, and develop and deploy applications that provide situational awareness of the electric system. Opus One is also engaged with utilities in New York that are focused on REV, the state's plan to reform their energy vision. The term “distributed energy resources management system,” or DERMS, gets thrown around a lot in the pages of Greentech Media. It's used to refer to a wide variety of software platforms that network, monitor, manage and control DERs for various needs. Some approach the challenge of connecting DER-equipped customers with grid operators, while others are moving from utility control rooms and distribution grid management systems toward the edges. Scottish startup Smarter Grid Solutions has carved out an important niche in the utility-centric approach to DERMS, with a software and hardware suite that enables real-time communication and orchestration of dispatchable assets. It’s being used by U.K. grid operators to help balance hundreds of megawatts of wind and solar energy and open the grid to more renewable power interconnections. On this side of the Atlantic, SGS’ software is being piloted by customers including New York utility Consolidated Edison, Southeastern utility Southern Co., Ontario, Canada-based utility PowerStream, and, reportedly, California utility PG&E. Last summer, SGS landed a spot to test its software with the National Renewable Energy Laboratory, the Department of Energy lab that’s orchestrating a broad array of grid-edge technology integration projects. These efforts, along with its inclusion in NYSEG and RG&E’s Flexible Interconnect Capacity Solution demonstration project under New York’s Reforming the Energy Vision initiative, have won the company a place on our Grid Edge Awards list. In the race to challenge Tesla’s Powerwall for dominance in the behind-the-meter battery market, Sonnen is seeking top-contender status. The startup formerly known as Sonnenbatterie has built up a significant presence in its home market of Germany, where thousands of homeowners have bought its batteries and home energy management systems. In February Sonnen announced the shipment of its 10,000th battery, providing a statistic that may or may not match Tesla’s Powerwall sales to date -- Tesla isn’t revealing those figures. Last year it announced its intentions to move into the U.S. market, starting with commercial applications in California and residential installations in Hawaii, with 1,000 orders placed as of mid-December. In January it unveiled a partnership with PV manufacturer SolarWorld and roofing company PetersenDean, and announced plans to create an energy storage financing scheme with Spruce, the company formed by the merger of Clean Power Finance and Kilowatt Financial. In the meantime, it’s been working on new models for aggregating its batteries for purposes beyond the customer meter, starting in Germany’s deregulated energy market. In November, it launched SonnenCommunity, a network of producers, consumers and storage operators that can trade self-generated renewable electricity with each other through a virtual grid. It was about 25 years that Steffes released its first Electric Thermal Storage (ETS) space heating system that provided utilities with a behind the meter energy storage while delivering low cost heating to consumers. Over the next 20 years or so, the Dickinson, N.D.-based company has grown a sizable portfolio of grid-interactive thermal storage systems which includes both space and water heaters -- and now, with utilities around the world searching for affordable behind-the-meter storage assets, that portfolio is coming into its own. In 2014 Steffes launched the software side of its business, via its “dynamic dispatch” system that brings utility-grade telemetry and data analytics to the challenge of using thermal energy storage to help balance intermittent wind and solar energy for grid stability and reliability. The company claims some two dozen utility deployments, including Canada’s PowerShift Atlantic project and the Department of Energy-funded Pacific Northwest Demonstration Project. Steffes is also working Hawaiian Electric’s Grid-Interactive Water Heater initiative, which is deploying smart water heaters with technology partner Shifted Energy. This project is trying out water heaters for far more than traditional demand response, with use cases including frequency regulation and contingency reserves to mitigate the sudden loss of generation capacity. Pretty much every grid battery vendor likes to say that it’s trying to take on Tesla Energy -- a testament to how the electric-vehicle maker’s entry into the energy storage market last year has made the world aware of the fact that there is such a thing as an energy storage market to begin with. Tesla’s launch of its Powerwall systems for behind-the-meter uses and its Powerpack for utility-scale grid storage came with the promise of some eye-popping low prices, driven by the company’s ability to supply itself with batteries from its Gigafactory in Nevada. Tesla CEO Elon Musk has cited “pretty nutty” preorder figures for the company’s new storage system since the launch, with a long list of partners including AES Energy Storage, EnerNOC, Advanced Microgrid Solutions, Oncor, Southern California Edison, Austin Energy, Green Mountain Power, and of course, sister company SolarCity. Tesla appears on target to meet its low price goals, according to a recent analysis. That will help it compete in the utility-scale energy storage marketplace, where Musk has suggested about 80 percent of the company’s battery business lies at present. Its behind-the-meter strategy is being bolstered by moves into markets like Germany, Australia and Hawaii, where the economics of solar-plus-storage are more attractive -- and muddied a bit by last month’s news that it has quietly discontinued its larger 10-kilowatt-hour Powerwall battery. Join Greentech Media June 21-23 in San Jose, CA for Grid Edge World Forum, a conference and exhibition showcasing innovation shaping the next-generation energy system. Compare different perspectives from utilities and regulators from around the globe. Hear from large energy customers and the companies and technology providers engaging directly with them. Learn more here.
News Article | November 14, 2016
This GTM Squared insight has been unlocked for you by: Spokane, a city of some 210,000 people in the foothills of eastern Washington state, is not the first place that comes to mind when one thinks about cutting-edge smart city deployments, or the latest efforts in transactive energy. But utility Avista and smart metering giant Itron want it to earn its place on that map. At Itron Utility Week last month, Itron and Avista laid out some details of their participation in an urban renewal project, called Urbanova, which will use Itron’s meters and wireless networks as the foundation for a broader internet of things (IOT) rollout. Two years in the making, Urbanova’s plan was formalized in September with partners including the Spokane city government, engineering firm McKinstry, and Washington State University. The project in Spokane’s 770-acre University District will start with networked streetlights -- a fairly common and cost-effective smart city application. But it will eventually grow to include air quality sensors, medical devices, and distributed energy resources (DERs) such as solar panels, behind-the-meter batteries, plug-in electric vehicles and energy-smart building control systems. It’s the first smart city project of its kind in Washington state, though only one of many being tested out around the world. It’s also a showcase for Itron’s next-generation technology platform, dubbed Riva. Finding ways to extend smart meter networks’ capabilities and business cases has long been a part of the Liberty Lake, Wash.-based company’s plans, along with those of competitors like Silver Spring Networks and Toshiba’s Landis+Gyr. In his opening speech at last month’s Itron Utility Week in Orlando, Fla., Itron CEO Philip Mezey laid out the business case for using advanced metering infrastructure (AMI) to connect customers outside the utility. “The systems we have built for you and with you to address the meter-to-cash cycle are a foundational basis for doing so much more -- for, really, the same price,” he said. “We need to advance our thinking in what we call the active network.” Urbanova will also take on a challenge facing utilities that are trying to incorporate DERs into their daily operations and long-term planning -- how to understand and monetize the value they offer the grid, both as individual units and together. This concept goes by different names, including transactive energy, or as the Avista project is called, the “shared energy economy.” For Avista technology strategist Curt Kirkeby, these separate but commonly networked deployments represent a natural extension of the utility’s existing smart grid infrastructure to the endpoints of the system -- and beyond. “We’ve been trying to model the grid since way back in the 1970s,” he said at last month’s Itron event. “Now we’re getting into the customer side of things.” Itron and Avista are well known to one another -- in fact, Itron was spun out of Avista in 1977. The two have been working on AMI since 2009, when Avista rolled out 13,000 Itron meters in Pullman, Wash. under a federal smart grid investment grant. In May, Avista picked Itron for a broader rollout across its 375,000-customer service territory over the next six years, featuring its OpenWay Riva technology, which is deployed with grid routers and networking technology from partner Cisco. While contracts are still being finalized and deployment schedules haven’t been set, the University District will be an early target. The benefits of AMI for Avista will start with the core meter-to-cash proposition, Kirkeby said. They’ll also use the meter data for revenue protection -- finding wasted or stolen electricity -- and pinpointing outages in its distribution network, which are common uses for a growing number of smart meter-equipped utilities today. In the meantime, Avista has rolled out some significant smart grid projects. Its largest, funded by a $20 million investment grant in 2009, is a distribution automation (DA) project that covers about one-third of its customers, featuring wireless networks from ABB’s Tropos and substation automation, smart switches and digital relays from grid vendor Efacec ACS. Beyond preventing and limiting outages, Avista has been using its DA system to do conservation voltage reduction (CVR), or fine-tuning voltages at different parts of the grid to save energy. Smart meters will be able to provide minute-by-minute data on energy, voltage and power quality at the endpoints of the grid, a critical piece of data for a system that must keep every customer within certain voltage limits. Next, Avista plans to extend the smart meter wireless network to non-grid devices, particularly those it doesn’t own, Kirkeby said. This is a realm where most AMI projects haven’t gone yet, since only the latest technologies, like Itron’s Riva or Silver Spring’s Starfish platform, support real-time, two-way communications across technology standards outside the utility realm. To test this capability, Avista is starting with streetlights. Last year, it embarked on a 28,000-streetlight LED replacement program, driven by the energy savings and reduced maintenance costs. These LEDs also come with digital controllers that offer a lot more flexibility than old-fashioned high-pressure sodium lights, making them useful targets for connecting to the network. They’re also distributed around the city, making them useful nodes for extending it to more devices. This is an important new market for Itron. Riva has supported streetlight connectivity since last year, but Itron hasn’t announced nearly as many deals on this front as has rival Silver Spring Networks, which bought vendor Streetlight.Vision in 2014 and has tens of thousands of lights networked in the U.S. and Europe. But there’s plenty of competition for traditional AMI vendors to contend with in this space, including giants like Verizon, which acquired LED networking startup Sensity Systems this fall, or GE’s Current, which bought Daintree Networks in April. Moving from energy assets to the broader world of IOT devices, Itron and Avista will start with air-quality sensors being deployed as part of a five-year, $1.5 million project with researchers from WSU’s Voiland College. WSU already runs one of the country’s most effective air-quality monitoring programs through its Laboratory for Atmospheric Research, and it’s a big partner in Avista’s Pullman microgrid projects. The goals of the Urbanova deployment combine both fields, to “monitor, predict and control energy and air quality in an urban environment and to record resulting health impacts” on people living and working in the University district. “Health monitoring is a core area where we’re leveraging the IOT platform” that Itron provides, Kirkeby said. Spokane’s University District is the home of three medical schools, and they’re going to be looking at the potential for using the Urbanova wireless network to connect different types of medical devices, he said. Beyond that, there’s a lot of room to add connectivity with Itron’s platform to the new construction being promoted for the district’s undeveloped parcels. These types of applications are still years out, though. While the Urbanova partners have signed a memorandum of understanding, they haven’t gotten to the nitty-gritty details of how they’ll share responsibility and ownership of the devices and data that will be part of this networked vision. In August, the Urbanova partners got a $7 million grant from the state’s Department of Commerce to launch the distributed energy portion of its project. It will start with a microgrid, planned to include 200 kilowatts of solar from two arrays and a combined 2.5 megawatt-hours of battery storage, and integration with the two buildings’ energy management systems. While eastern Washington isn’t the hottest spot for rooftop solar, Avista is the host of the state’s first community solar project, a 425-kilowatt array that will serve more than 500 residential and commercial customers. The utility also has a pressing need to manage the ups and downs of the state’s wind generation, which can reach up to 17 percent of overall supply at times, and can’t be curtailed even when it’s producing more power than is needed, Kirkeby said. Avista also has a fair share of experience with batteries. Since April 2015, it’s been operating a 1-megawatt, 3.2-megawatt-hour vanadium redox flow battery from UET, which is also working on the shared energy economy project, at a substation in Pullman, providing load shifting, frequency regulation, and voltage regulation. One of the biggest customers served by that substation is grid technology vendor Schweitzer Engineering Laboratories (SEL), which is also providing the microgrid controls for the Urbanova project, he said. That will give Avista the tools to monitor and control each of its grid-connected energy assets, whether they’re controllable loads within buildings, or the inverters that connect the project’s solar arrays and batteries to the grid. In all of these use cases, “you need predictability, and you need dispatchability,” Kirkeby said. “We want to be monitoring state of charge, managing baseline schedules or active schedules, and revising it all on the fly. The Riva IOT platform is the perfect way to do that.” Beyond technically controlling these DER interactions, the shared energy economy project will be extending the work of the regional Pacific Northwest Smart Grid Demonstration Project. This multi-year project, involving 11 utilities and the Bonneville Power Administration, connected 27 different “nodes” across the Pacific Northwest’s transmission grid to calculate current and predicted electricity demand and costs, and communicate those values to power plants, industrial demand response systems and behind-the-meter controllable loads like adjustable water heaters and batteries. The shared energy economy project will shrink this concept down to the scale of the local distribution grid. “We’re working on methodologies for valuing different DERs,” including solar PV, energy storage and natural-gas-fired turbines. Avista is studying the potential for battery power to support critical loads such as the area’s medical facilities during outages like the one caused by a freak windstorm last year, he said. But it will also be asking its batteries and controllable loads to perform valuable tasks when the grid isn’t down, from balancing out ups and downs in solar output to providing reactive power to help stabilize voltages, he said. This chart from a recent presentation on the project (PDF) shows how the system will be configured, with SEL’s microgrid controller receiving optimization data from the utility’s DMS, collecting the status and availability of its various DERs, and controlling them to serve a ranked series of grid needs. This kind of “transactive microgrid” architecture is on the cutting edge of microgrid technology, and is being tried out in a select set of pilot projects, including several being funded by ARPA-E's $33 million NODES program, as well as the U.S.-Canadian Transactive Energy project that’s linking microgrids in Maine, Nova Scotia and Toronto. This GTM Squared insight has been unlocked for you by:
News Article | November 7, 2016
AutoGrid DROMS secured highest scores for overall strategy, vision, partners and geographic reach REDWOOD CITY, CA--(Marketwired - Nov 7, 2016) - AutoGrid Systems, the Energy Internet leader, today announced that Navigant Research has positioned AutoGrid as a Leader in its 2016 Demand Response Management System (DRMS) Leaderboard report. AutoGrid was one of only two companies that Navigant Research placed in its highest ranked "DRMS Leaders" category, and the only pure play software provider to be named a Leader. The complete report, including the Leaderboard graphic, is available at https://info.auto-grid.com/2016Q4-navigant-leaderboard-report.html. The Navigant Research report states, "All vendors in this ranking are competitive; however, there is a significant differentiation between the Leaders and the Challengers." All companies ranked in the report were evaluated against 10 criteria across strategy and execution. AutoGrid secured the highest score on strategy, and also secured the highest score in five out of the ten individual categories including vision, product portfolio and partners. Navigant Research's DRMS Leaderboard report highlights AutoGrid's differentiated positioning by stating that AutoGrid "DROMS has a modular design, so it can be scaled for all types of customers -- from large IOUs to small municipal utilities, electric cooperatives, and retail electricity suppliers." The report also states "since DROMS is a cloud-based offering, it can also be implemented quickly and at low cost." The report further states that AutoGrid DROMS "blurs the line between DRMS and DERMS [distributed energy resource management system], and it allows operators to manage DER alongside DR programs from the same dashboard, enabling the monetization of DER in wholesale markets...The company's SaaS focus can reduce costs and implementation times compared to on-premise DRMS solutions." "Key market drivers in the DRMS market include simplified DR program management, the ability to use DR to reduce capital investment and energy procurement costs and integration with other utility IT systems -- three areas where AutoGrid scored highly," said Brett Feldman, principal research analyst with Navigant Research. "In addition, a comprehensive DRMS system with strong customer engagement capabilities and support for distributed energy resources beyond just demand response, capabilities which AutoGrid displayed in the Leaderboard, addresses some of the most important needs of DRMS customers as they seek to increase the value delivered by their DR programs, both today and in the future." AutoGrid Flex: A Comprehensive, Dispatch-Grade Flexibility Management Solution The Navigant Research report highlights several key market trends that are impacting energy companies as they face a rapidly evolving and increasingly complex industry landscape, and seek new ways to provide differentiated and value-added grid-edge services to their customers by harnessing flexible capacity. These trends include the need to manage all customer-owned demand response (DR) and distributed energy resources (DERs) from a single unified dashboard, the need to provide a personalized and engaging customer experience to increase end-consumer acceptance of these services, and a worldwide shift to cloud-based IT deployments and Software as a Service (SaaS) business models that allow energy companies to become more agile and reduce system cost and implementation times compared to legacy on-premise solutions. The AutoGrid Flex™ application suite, consisting of the AutoGrid DROMS™, AutoGrid DERMS™ and AutoGrid VPP™ applications, is a comprehensive flexibility management system that addresses these trends, and can be deployed on premise or in the cloud and in both regulated and deregulated energy markets. AutoGrid Flex: "AutoGrid's ranking as a Leader in Navigant Research's DRMS Leaderboard further validates our overall strategy -- to deliver energy companies the most comprehensive and versatile flexibility management system for cost-effectively launching and rapidly scaling new services for their customers," said Dr. Amit Narayan, CEO of AutoGrid. "AutoGrid Flex provides energy service providers with a powerful new tool for launching new business models that use battery storage, EVs and other customer-owned assets to increase revenues, reduce their operating expenses, enhance reliability and improve customer satisfaction." Click to Tweet: News: @AutoGridSystems positioned as a Leader by @NavigantRSRCH in its 2016 DRMS Leaderboard #DemandResponse http://ctt.ec/9BaFw+ About AutoGrid Systems AutoGrid builds software applications that enable a smarter Energy Internet. The company's suite of Energy Internet applications allows utilities, electricity retailers, renewable energy project developers and energy service providers to deliver cheap, clean and reliable energy by managing networked distributed energy resources (DERs) in real time and at scale. AutoGrid applications are all built on the AutoGrid Energy Internet Platform (EIP), with patented Predictive Controls™ technology that leverages petabytes of smart meter, sensor and third-party data, along with powerful data science and high-performance computing algorithms, to monitor, predict, optimize and control the operations of millions of assets connected across global energy networks. The world's leading energy companies, including E.ON, Bonneville Power Administration, Florida Power & Light, Southern California Edison, Eneco, Portland General Electric, CPS Energy, New Hampshire Electric Cooperative, NextEra Energy, Xcel Energy and CLEAResult, are using AutoGrid's software to improve their operations, integrate renewables and drive deeper engagement with their customers. AutoGrid has been recognized with several prestigious industry awards including Greentech Media's Grid Edge Award 2016, Bloomberg New Energy Pioneer 2016, World Economic Forum Technology Pioneer 2015, Red Herring Top 100 North America 2015, Cleantech Global 100 for 2015 and 2014, and Industrial Innovation Company of the Year 2014 by the Cleantech Group.
News Article | December 7, 2016
Industry's first fully integrated flexibility management solution, with more than 2,000 megawatts of distributed energy resources under contract AutoGrid Flex enables utilities and other energy service providers to use distributed energy resources to increase revenues, drive customer engagement and enhance grid reliability REDWOOD CITY, CA--(Marketwired - Dec 7, 2016) - AutoGrid Systems, the Energy Internet leader, today announced that it has launched AutoGrid Flex™ 3.0, the energy industry's first comprehensive flexibility management solution for demand response (DR) management, distributed energy resource (DER) management and virtual power plants (VPPs). Now generally available for the first time, the AutoGrid Flex 3.0 application suite features several new energy storage co-optimization capabilities that enable utilities, electricity retailers, renewable energy project developers and other energy service providers to maximize the value of energy storage systems at the local site level, manage energy storage assets in combination with demand response and other types of DERs and optimize aggregation and dispatch from a portfolio of energy storage and other DERs. These innovative storage co-optimization capabilities, along with new DER integration, enhanced user interfaces (UIs) and other new features further strengthen AutoGrid customers' ability to use the Energy Internet to predict, optimize and control DERs at scale in real time, helping them launch new services that increase revenues, reduce operating expenses, drive customer engagement and enhance grid reliability. "At Gexa Energy we are always looking to provide additional value to our customers," said Brian Landrum, President of Gexa Energy. "We look forward to working with AutoGrid to deliver energy cost management solutions to customers leveraging energy storage and our existing demand response, energy efficiency, renewable energy, and other energy services." "Mitsubishi is working on several large-scale energy storage projects, and flexibility management software that can optimize local self-consumption, aggregate a large number of energy storage systems and other DERs into a VPP and provide energy service providers with centralized, real time control of these systems would significantly improve the economics of these projects," said Atsushi Suzuki, Deputy General Manager of the New Energy and Power Generation Division, Mitsubishi Corporation. "AutoGrid Flex 3.0's new energy storage capabilities and proven track record in VPPs directly address our customers' needs for these projects, and we look forward to working with AutoGrid to determine how we can use AutoGrid Flex to maximize the ROI of these projects." "Energy storage is one of the key enabling technologies in the development of a cleaner, more efficient distributed energy world. However, despite the fact that energy storage costs continue to fall, we still need to dramatically improve energy storage project economics through intelligent software if we hope to truly accelerate energy storage adoption," said Dr. Amit Narayan, CEO of AutoGrid. "By optimizing the value of local energy storage systems, integrating energy storage systems with other DERs and maximizing the ability of energy storage and other DER portfolios to generate payments from wholesale energy markets, AutoGrid Flex 3.0 significantly improves energy storage system economics, making energy storage a more attractive investment for energy service providers and end-customers alike." Improving Energy Storage Economics Energy storage's load-smoothing and supply and demand balancing capabilities enable it to serve as a powerful source of flexible capacity in the transformation of the traditional, centralized grid into a modern, distributed, renewable-friendly energy network. However, while energy storage costs are rapidly falling, using energy storage for only a single application -- such as demand charge reduction or backup power -- still often results in project economics that fail to deliver the returns needed to justify investment in the project. However, AutoGrid Flex 3.0 delivers a fully integrated flexibility management solution that includes three key energy storage co-optimization capabilities -- local site optimization, storage integration with other DERs, and portfolio optimization -- that allow energy service providers to use energy storage to realize multiple business objectives, dramatically improving energy storage project economics while also increasing flexible capacity at the grid edge. AutoGrid Flex 3.0 also now includes energy storage system sizing and ROI calculators. The calculators use the open Green Button standard to secure energy use and other data from end-customers' utilities and other energy service providers. With these AutoGrid Flex calculators, energy service providers, energy storage project developers and end-customers can optimize energy storage system size and estimate long-term system ROI, helping them maximize the impact of their energy storage project investments. Currently AutoGrid is actively working with customers and partners on VPP and other energy storage projects in Germany, the United Kingdom, Japan, California and New York. New Features Further Enhance Flexibility Management In addition to the innovative storage co-optimization capabilities described above, AutoGrid Flex 3.0 further integrates its three flexibility management applications into a unified suite that allows energy service providers to view, control and optimize all their DER programs and assets with a single system. AutoGrid Flex 3.0 features an enhanced user experience with new real-time data visualization capabilities, as well as configurable dashboard widgets. These enhancements provide more personalized, relevant information to users when and how they need it. In addition, new multi-level account hierarchies provide the sophisticated visibility and management tools needed to serve large commercial and industrial (C&I) end-customers. AutoGrid Flex 3.0 also features improved DER integration, enabling users to monitor DERs in real-time on their dashboards and also secure detailed reports on asset performance over time. Additionally, AutoGrid Flex 3.0 provides expanded integrations for DERs such as the DNP3 protocol, native SCADA integrations, and template-based device configuration including popular devices. Flexibility Management Increase the Value of Energy Storage and other DERs The number and capacity of Internet-connected DERs is dramatically increasing -- not just energy storage systems, but also demand response programs, distributed solar power systems, smart inverters, smart thermostats, water heaters, pool-pumps, residential EV chargers, heating ventilation and air conditioning (HVAC) systems, building lighting systems, industrial control equipment and more. Flexibility management software enables utilities, electricity retailers and other energy service providers to use the Energy Internet to manage these diverse resources across all their customers and also launch new services that increase revenues, drive customer engagement and improve overall system reliability. AutoGrid Flex integrates AutoGrid's three flexibility management applications -- AutoGrid DROMS™, AutoGrid DERMS™ and AutoGrid VPP™ -- into a single unified application suite, providing energy service providers with a comprehensive flexibility management solution for DERs. Energy service providers can use AutoGrid Flex to integrate demand response programs, DERs and VPPs into capacity and other energy markets. AutoGrid customers have currently integrated AutoGrid Flex into CAISO, PJM, ERCOT MISO, ISONE energy markets in the United States and the TenneT energy market in Europe. About AutoGrid Systems AutoGrid builds software applications that enable a smarter Energy Internet. The company's suite of Energy Internet applications allows utilities, electricity retailers, renewable energy project developers and energy service providers to deliver cheap, clean and reliable energy by managing networked distributed energy resources (DERs) in real time and at scale. AutoGrid applications are all built on the AutoGrid Energy Internet Platform (EIP), with patented Predictive Controls™ technology that leverages petabytes of smart meter, sensor and third-party data, along with powerful data science and high-performance computing algorithms, to monitor, predict, optimize and control the operations of millions of assets connected across global energy networks. AutoGrid Flex has more than 2,000 megawatts of DERs under contract with more than 25 global energy companies around the world. Several of the world's leading energy companies, including E.ON, Bonneville Power Administration, Florida Power & Light, Southern California Edison, Eneco, Portland General Electric, CPS Energy, New Hampshire Electric Cooperative, NextEra Energy and CLEAResult, are using AutoGrid's software to improve their operations, integrate renewables and drive deeper engagement with their customers. AutoGrid has been recognized with several prestigious industry awards including the 2016 Energy Productivity Innovation Challenge (EPIC), Greentech Media's Grid Edge Award 2016, Bloomberg New Energy Pioneer 2016, World Economic Forum Technology Pioneer 2015, Red Herring Top 100 North America 2015, Cleantech Global 100 for 2015 and 2014, and Industrial Innovation Company of the Year 2014 by the Cleantech Group.
News Article | November 22, 2016
AutoGrid extends its market leadership in the flexibility management software category as the only vendor to be simultaneously positioned as a Leader on Navigant Research's Virtual Power Plant (VPP) Software and Demand Response Management System (DRMS) Leaderboard reports REDWOOD CITY, CA--(Marketwired - Nov 22, 2016) - AutoGrid Systems, the Energy Internet leader, today announced that Navigant Research has positioned AutoGrid as a Leader in its Navigant Research Leaderboard Report: Virtual Power Plant Software Vendors. Navigant Research also recently named AutoGrid a Leader in its Navigant Research Leaderboard Report: Demand Response Management Systems, making it the only company with the distinction of being positioned as a Leader in both the virtual power plant (VPP) and demand response management system (DRMS) flexibility management categories. VPP and DRMS are two of the leading use cases within the broader flexibility management software category. Flexibility management software allows regulated and deregulated energy companies to manage and monetize the vast network of connected distributed energy resources (DERs) that are rapidly being deployed at the grid edge. These DERs include distributed solar power systems, smart inverters, battery storage systems, smart thermostats, water heaters, pool-pumps, residential EV chargers, heating ventilation and air conditioning (HVAC) systems, building lighting systems and industrial control equipment in large factories. Flexibility management software enables utilities, electricity retailers and other energy service providers to manage these diverse resources across all their customers from a single dashboard, and also launch new services that increase revenues, drive customer engagement and improve overall system reliability. Unlike other point solutions, AutoGrid Flex™, the first fully integrated flexibility management software solution, supports all flexibility management use cases -- demand response management systems (DRMS), distributed energy resource management systems (DERMS) and virtual power plants (VPPs) -- across all assets and all customer segments from a single, easy to deploy dashboard. With more than 2,000 megawatts (MW) of DERs under contract, AutoGrid Flex is the industry's most proven flexibility management software solution on the market today. Capturing New Revenue Streams with Additional Flexible Capacity Navigant Research's VPP Software Vendor Leaderboard report states that the AutoGrid VPP™ application, part of the AutoGrid Flex application suite, "can aggregate and monetize tens of thousands of flexible resources in energy markets in real-time, enabling energy providers to create additional flexible capacity and capture new revenue streams." The report further states that "by providing utilities and aggregators with forecasting and asset optimization capabilities, the AutoGrid VPP helps them capture more value from flexible resources in wholesale energy markets through granular aggregation and control capabilities." "The energy industry is increasingly demanding VPP solutions that can analyze streaming, real-time data from thousands of energy resources to deliver accurate and granular insights on future and real-time VPP performance -- one capability where AutoGrid scored highly," said Peter Asmus, principal research analyst with Navigant Research. "In addition, VPP solutions that can integrate a diverse mix of demand response, battery storage, generation and other flexible energy resources -- functionality provided by AutoGrid VPP -- is one of the ultimate goals for VPPs, as a synergistic sharing of grid resources allows energy service providers to wring more value out of these resources, increasing return on investment while reducing capital costs." "Utilities, electricity retailers and other energy service providers are quickly recognizing that they need a proven and scalable flexibility management solution to serve all their residential, commercial and industrial customers, and to manage a variety of resources across multiple regulated and deregulated markets, as they seek a competitive edge in the rapidly evolving new energy landscape," said Dr. Amit Narayan, CEO of AutoGrid. "We are delighted that Navigant Research has recognized AutoGrid's leadership in this fast growing market segment by naming AutoGrid a Leader across two of the most important flexibility management software categories, VPPs and DRMS." Flexibility Management: Extracting Maximum Value from Distributed Energy Resources The Navigant Research report highlights several key VPP market trends that are impacting energy service providers as they seek to aggregate customer-owned flexible battery storage, distributed generation and demand-side resources, and turn these resources into new sources of revenue by monetizing them in energy markets. These trends include the need for solutions that can collect and analyze multiple types of data from a variety of internal and third-party sources, support new types of distributed energy resources, particularly energy storage and demand response resources, and integrate VPPs seamlessly into wholesale energy markets and other transactive energy exchanges. The AutoGrid Flex application suite, consisting of the AutoGrid VPP, AutoGrid DROMS™, and AutoGrid DERMS™ applications, is a comprehensive flexibility management system that addresses these trends, and can be deployed on premise or in the cloud and in both regulated and deregulated energy markets. About AutoGrid Systems AutoGrid builds software applications that enable a smarter Energy Internet. The company's AutoGrid Flex™ suite of Energy Internet applications allows utilities, electricity retailers, renewable energy project developers and energy service providers to deliver cheap, clean and reliable energy by managing networked distributed energy resources (DERs) in real time and at scale. AutoGrid applications are all built on the AutoGrid Energy Internet Platform™ (EIP™), with patented Predictive Controls™ technology that leverages petabytes of smart meter, sensor and third-party data, along with powerful data science and high-performance computing algorithms, to monitor, predict, optimize and control the operations of millions of assets connected across global energy networks. AutoGrid Flex has more than 2,000 megawatts of DERs under contract with more than 25 global energy companies around the world. Several of the world's leading energy companies, such as E.ON, Bonneville Power Administration, Florida Power & Light, Southern California Edison, Eneco, Portland General Electric, CPS Energy, New Hampshire Electric Cooperative, NextEra Energy, Xcel Energy and CLEAResult, are using AutoGrid's software to improve their operations, integrate renewables and drive deeper engagement with their customers. AutoGrid has been recognized with several prestigious industry awards including the 2016 Energy Productivity Innovation Challenge (EPIC), Greentech Media's Grid Edge Award 2016, Bloomberg New Energy Pioneer 2016, World Economic Forum Technology Pioneer 2015, Red Herring Top 100 North America 2015, Cleantech Global 100 for 2015 and 2014, and Industrial Innovation Company of the Year 2014 by the Cleantech Group.
News Article | November 22, 2016
Omaha Public Power District (OPPD) completed the final requirements for permanently withdrawing Ft. Calhoun Station's electricity generation from the Southwest Power Pool. According to an email from Kim Tracy, the Corporate Secretary Executive Division OPPD, the board of directors pressed forward with their decision to decommission the site and sent the death certificate letter to the NRC on November 13, 2016. OPPD has no immediate need to replace the output of the plant; the power it was generating was excess to the internal needs of the power district. Most of it was being sold into the competitive market with the revenues being used to help reduce customer rates inside the system. Though that arrangement was lucrative when wholesale electricity prices were high, it did not cover the operating costs of the plant when market prices were low. Competitive power sources, including other plants controlled by the OPPD, should capture the benefit of higher average sales prices than would have otherwise been achieved if the plant had continued to reliably and steadily send its 478 MW of clean electricity into the grid. No longer will people seeking to capture the financial benefits of the sweet deal provided by the federal investment tax credit for wind farms worry about whether their output will be crowded out of the market by the power supplied by FCS. Killing off FCS has opened up a little room on the grid so they can sell their output whenever it happens to be available. Attempting To Derail A Train That Had Left The Station Journalists are taught to report stories, not to make them or get involved in their outcome. Writers with moderate technical knowledge, a bit of leadership and management experience and a penchant for tilting at windmills don't necessarily adhere to those journalistic principles. I apologize if the below story includes too much use of the first person, or if it sounds too self promoting. After publishing Another U.S. Nuclear Plant Killed By Competition I took some unsuccessful steps to preserve FCS's potential for future restoration and operation. My analysis indicated that the OPPD board of directors decision was either hasty or predetermined. Aside: This section's subhead probably needs explanation. During my service as a staff officer at Navy headquarters in DC, I was often told "That train has left the station," in response to a request to reconsider an ill-advised decision. My response was often, "It might be moving, but I can still see it. Why can't we use this new information about track conditions to halt its progress before it goes to a bad place?" Not surprisingly, few people were willing to join me and rush out in front of a moving train. End Aside. My first action was to contact a couple of lawyers who are sympathetic to the cause of preserving nuclear plants that are licensed and already operable. Both of them offered useful suggestions for courses of action, but both noted that the actions they recommended probably required more time and resources that were available, given the fact that the plant had already been shut down. We knew that the calendar pages were being ripped off rapidly and that precedent established at Kewaunee and Vermont Yankee indicated that removing fuel and sending the final death certificate could happen within weeks of the final operating day. Briefly, the course of action that the lawyers proposed was to first obtain as much information about the decision analysis and process as possible from OPPD, relying on state open records provisions for a public body. The next step would be to file an injunction asking for a delay to give time for the public to determine if the OPPD board had met its fiduciary responsibility to customers. The analysis would help determine if the permanent step of destroying FCS was the best action to take. Part of the difficulty in promptly following the legal advice was the fact that I'm not an OPPD customer/owner, so I had no standing for an injunction. I was visiting the geographical area at the time and considered tapping others to provide the required "standing" to get involved legally, but time was limited. In addition, I didn't feel right in inviting a friend or family member who doesn't share my passion to stand by my side while I tried to halt a moving train. I had tenuous contact with a couple of FCS employees who were also OPPD customers, but I chose not to ask them to take financial risks associated with participating in legal actions that challenged their employer. The Washington County Enterprise, the Washington County Pilot-Tribune, and the Omaha World-Herald have all published multiple stories about the announcement that board had asked management to evaluate the plant's viability, a nascent effort to save the plant, and the announcement of the board's final decision. Katie Rohman of Enterprise Publications and Cole Epley of the Omaha World Herald, the authors of those articles, individually agreed to meet with me. They were interested in hearing about ideas for preserving the plant in a condition that would allow a restart. They acknowledged that it would be welcome news in the community if the board or someone else with sufficient resources could find new outlets for the plant's electricity or maintain it while waiting for market conditions -- like the temporarily low price of natural gas -- to change. They suggested a few additional local contacts, including Connie Green, the business correspondent for KBLR - River Country 97.3 FM. Though I never had a chance to catch the piece when it aired, Connie recorded our discussion and broadcast the message that preserving the plant was remotely possible. One reason that the loss of FCS is so frustrating is that there is little or no evidence of community opposition to the plant or to nuclear energy in general. That 660 acre nuclear power plant site could have been used for a couple of more clean power plants without much risk of a NIMBY response. As a result of more than 20 years of covering nuclear energy issues, I've developed contacts throughout the industry, including some in top leadership positions. Though they were receptive to hearing me out, they were unable to help. They expressed interest in having a mothball option created in the regulations, but are not sure how to fund the effort required. They explained how finding a lead plant would be challenging, the plants that might benefit from having that option are already in financial difficulty and need to shed expenses as quickly as possible. There is also a growing body of experience in moving quickly from operations to decommissioning and transferring the burden onto the resources saved up in the fenced off decommissioning fund. Those funds are not available to plant owners unless they are actually in the decommissioning process. From the corporate point of view, spending money from the decommissioning fund is like spending free money; they reported the expenditure on their income and expense reports at the time they set the money aside. Traditional plant owners are also not terribly interested in owning and caring for facilities that are not operating or generating revenue, so they don't see any real advantage to a mothball option. When asked how they would handle a dramatic increase in natural gas prices, most indicated that they thought that was a remote possibility. They said there were less costly ways to provide financial protection against that eventuality than keeping a nuclear plant mothballed. There is a new movement with groups who are trying to join forces to keep operating plants on line. When I began my tardy effort to try to save FCS, they had just held a summit meeting in Chicago to develop strategies for actions that would help keep economically distressed plants in Illinois on line. I contacted Eric Meyer from Environmental Progress, one of the organizers of the "Save the Nukes" coalition. We had some productive discussions and will certainly work together on other projects, but there simply wasn't enough time to mobilize effective actions that could preserve FCS. During the time between FCS's last day of operating and the submission of the plant's death certificate, the American Nuclear Society held its winter meeting. I attended and took the opportunity to talk with as many people as possible about the need to create a way to temporarily remove nuclear plants from service when the market signals were saying their power wasn't needed and then returning them to service when the market signals indicated that the power was wanted and valued. Pete Lyons, the former Assistant Secretary of Energy for the Office of Nuclear Energy, said that he thought the mothball option wasn't practical and that it wasn't enough of a step forward to invest a lot of time and energy. He said he would prefer to investigate other options for keeping plants operating, including a possible federal takeover that would allow nuclear plants to be operated by an organization something like the Tennessee Valley Authority or the Bonneville Power Administration. John Kotek, the Acting Assistant Secretary of Energy for the Office of Nuclear Energy, indicated interest but also said that no one in industry had mentioned this as an option that they were interested in pursuing. I communicated with Ms. Tracy, the OPPD corporate secretary to attempt to notify the OPPD board that there were courses of action related to Ft. Calhoun that had not been evaluated during the brief time between asking senior management for advice and making the final decision to decommission the plant and the site. She told me to send her an email and she would ensure that the board received it. The email described the informal discussions about establishing a mothball option and asked the board to consider being the lead plant for an effort to create the rules that would make it a safe and economical option. It asked the board to recognize that the Clean Power Plan's lack of credit for operating nuclear plants might be changed and that it was possible to make a good case that a mothballed plant would be eligible for credit if it is restored to service. That letter obviously did not alter the board's decision. The windmills won this round. It's time now to gather lessons, learn from them and begin preparing for the next opportunity. I'm searching for at least one Sancho Panza, but it would be better to gather a more substantial group of supporters.
News Article | November 15, 2016
AutoGrid named winner in the award's "systems category" for flexibility management applications that leverage the Energy Internet to harness flexible capacity from distributed energy resources (DERs) MARRAKECH, MOROCCO and REDWOOD CITY, CA--(Marketwired - Nov 15, 2016) - AutoGrid Systems, the Energy Internet leader, today announced that is has been was named a winner in the systems category of the Energy Productivity Innovation Challenge (EPIC). A global initiative devised and delivered by Energy Unlocked (a hub for innovation in global energy systems) and ClimateWorks, the winners were recognized at a ceremony hosted by the World Business Council for Sustainable Development on November 15 at the Low Emissions Solutions Conference, taking place during the COP22 UN climate summit in Marrakech, Morocco. Energy Unlocked's EPIC 2016 competition aims to discover and promote new market entrants who can help homes, industry and big business use less energy, at lower cost and with a lower carbon footprint. Advances in predictive analytics, real-time optimization, edge computing, fintech and battery storage are creating new demand-side flexibility and compelling opportunities to modernize the way the world produces, buys and consumes energy. Winners in the five EPIC categories -- homes, buildings, mobility, systems and finance -- were selected by an international jury assessing their impact on productivity, global transferability and innovation. Partners of the EPIC initiative include the Climate Group's EP100 initiative, the Global Alliance for Energy Productivity and the Alliance to Save Energy. Using Flexibility Management to Increase Energy Productivity AutoGrid was recognized for its suite of flexibility management applications, AutoGrid Flex™, which enable utilities and energy service providers to use the Energy Internet to predict, optimize and control any networked distributed energy resource (DER) -- including Combined Heat and Power (CHP) units, demand response (DR) programs, distributed solar, industrial lighting systems, battery storage systems and smart thermostats -- in real time and at scale. By enabling them to maximize the energy productivity of these DERs, utilities and energy service providers can better balance supply and demand on an increasingly complex, multi-directional and renewable energy powered grid. For example, with AutoGrid Flex, utilities and energy service providers can use DERs to account for the intermittency of renewable generation, allowing them to cost-effectively add more renewables into their energy system without impacting grid stability. In addition, AutoGrid Flex's advanced analytics and machine learning technologies deliver reliable, accurate, dispatch-grade demand response, making these programs more efficient while improving system reliability. "The distributed energy world will require us to not just generate more power from renewable resources, but also use the Energy Internet to maximize the productivity of every energy asset we have if we want energy to be clean, cheap and reliable," said Dr. Amit Narayan, CEO of AutoGrid. "This recognition further validates our conviction that flexibility management is essential if utilities and energy service providers are to be successful in building renewable-friendly, flexible energy networks that maximize the productivity of any type of DER." About EPIC EPIC -- the Energy Productivity Innovation Challenge -- is a global initiative devised and delivered by Energy Unlocked with funding from ClimateWorks. Entries were invited from global technology companies and innovators between June and September 2016. A jury of clean energy pioneers and experts including -- ClimateWorks Foundation, Rocky Mountain Institute, International Energy Agency, World Green Buildings Council, Bloomberg New Energy Finance and the B Team -- announced 21 regional finalists on October 13, 2016 at the IEA's Innovation in Energy Efficiency event. Partners of the EPIC initiative include the Climate Group's EP100 initiative, the Global Alliance for Energy Productivity, and the Alliance to Save Energy. Global media partners include: GreenBusiness Media and Bloomberg New Energy Finance. Please visit EPIC.energyunlocked.org for more information. About AutoGrid Systems AutoGrid builds software applications that enable a smarter Energy Internet. The company's suite of Energy Internet applications allows utilities, electricity retailers, renewable energy project developers and energy service providers to deliver cheap, clean and reliable energy by managing networked distributed energy resources (DERs) in real time and at scale. AutoGrid applications are all built on the AutoGrid Energy Internet Platform (EIP), with patented Predictive Controls™ technology that leverages petabytes of smart meter, sensor and third-party data, along with powerful data science and high-performance computing algorithms, to monitor, predict, optimize and control the operations of millions of assets connected across global energy networks. The world's leading energy companies, including E.ON, Bonneville Power Administration, Florida Power & Light, Southern California Edison, Eneco, Portland General Electric, CPS Energy, New Hampshire Electric Cooperative, NextEra Energy and CLEAResult, are using AutoGrid's software to improve their operations, integrate renewables and drive deeper engagement with their customers. AutoGrid has been recognized with several prestigious industry awards including Greentech Media's Grid Edge Award 2016, Bloomberg New Energy Pioneer 2016, World Economic Forum Technology Pioneer 2015, Red Herring Top 100 North America 2015, Cleantech Global 100 for 2015 and 2014, and Industrial Innovation Company of the Year 2014 by the Cleantech Group.
News Article | February 22, 2017
A new report from an anti-nuclear group gives some alternative spin to the same old dogma – shut down all nuclear plants and replace them with renewables. Lots of spin, but no evidence. This particular report, from McCullough Research, again targets their imagined nemesis Columbia Generating Station, Washington State’s own public power nuclear plant that has been operating beautifully, breaking production and safety records over and over, for the last five years. The main point of this report is its claim that Northwest power customers would save up to $500 million over ten years by permanently closing Columbia Generating Station and replacing it with wind and solar energy. The report neglects to mention that Washington State is already 80% low-carbon, mostly from hydroelectric and nuclear, so more wind is counterproductive. The report claims wind and solar prices have fallen dramatically, and rightly so, but then fails to mention they still cost more than existing power plants that have two or three times their lifespan. They also fail to tell the reader that natural gas or hydropower is necessary to backup wind and solar, at an unknown cost, something California is struggling with as their renewables approach 30%. All other legitimate reports disagree with the McCullough analysis, showing instead that this strategy of replacing Columbia Generating Station with renewables and gas would lose ratepayers about $1.6 billion over the next 20 years and put an extra 60 million metric tons of carbon dioxide into the atmosphere (IHS Cambridge Energy Research Associates, EIA, BPA) while laying off a thousand workers and three thousand more that depend on them. While global warming is not of much interest to McCullough Research or its sponsor, Physicians for Social Responsibility, it certainly is to many others. The world’s top climate scientists, including Dr. James Hansen, Dr. Tom Wigley, Dr. Ken Caldeira and Dr. Kerry Emanuel, have shown that renewables alone cannot meet any of our carbon goals and that a major expansion of nuclear power is essential to avoid dangerous anthropogenic interference with the climate system in this century. Specifically, they said shutting existing nuclear plants, like Columbia Generating Station, is foolish and dangerous. It does seem foolish to close a power plant 25 years ahead of schedule when it’s producing energy at a price of 4.2¢/kWh, 93% of the time with only 17 gCO2/kWh, based solely on the hope that gas prices will not increase for 20 years. Columbia Generating Station’s leveled cost of electricity is estimated to be between 4.7 and 5.2¢/kWh through 2043. Just look at the numbers. First, prices are not costs. Costs are what it takes to generate a kWh of electricity. Prices are what the markets can get away with charging us for it, and includes costs of generation, grid and network maintenance, metering, retail charges, market charges, capacity cost, congestion costs, and renewable energy certificate charges. These charges depend strongly on where you live. The cost to generate electricity in New York is about the same as in Washington State, but the price in the unregulated market of New York is 19¢/kWh while in the regulated market of Washington State the price is just 8¢/kWh. During the last Polar Vortex, New York State utilities were gouging customers up to 100¢/kWh, just because they could. That cannot happen in a regulated market like the Pacific Northwest. In fact, during the Western Energy Crisis of 2000-2001, the steady power from Columbia Generating Station saved Northwest power customers $1.4 billion. Therefore, to compare Columbia Generating Station with replacement by wind, we have to separate out just the costs. How you finance it, what tax breaks you give wind, what the market will bear, all have to be dealt with later, usually without the ratepayers knowledge or input. But it’s the actual costs that are key to comparing different energy sources. The all-in cost of generating a kWh of electricity at Columbia Generating Station is 4.2¢/kWh. This price includes all capital, fuel, operation and maintenance (O&M), salaries and replacement of parts and equipment. Since Columbia Generating Station produces over 9 billion kWhs/year, it will generate about 180 billion kWhs over 20 years and, using 4.2¢/kWh, it will cost $7.6 billion. The expected lifespan of this nuclear plant is at least 60 years, not 40 years as implied by McCullough. The 40 years was just the arbitrary time period chosen by the original Atomic Energy Agency as a good point to do the first thorough relicensing examination, followed by another every 20 years thereafter, for as long as the plant is in good shape. Continuous change outs, replacements and upgrades keep a plant in good shape, and Columbia Generating Station is in great shape. If we were to replace Columbia Generating Station with wind, it would cost about $9.3 billion to generate the 180 billion kWhs over the next 20 years, or 5.2¢/kWh, including connecting to the grid, but not including buffering or load-following its intermittency that would be done with hydro or natural gas. Such load-following can rise to 7% of the price when wind exceeds 10% of the annual production. Wind turbines cost about $1.7 million per MW if they are built on land, and $3.5 million per MW if built offshore. Once built, they last about 20 years, operate about 30% of the time in the Pacific Northwest, and take about 1.5¢/kWh to operate and maintain. Assuming onshore turbines are built along the scenic Columbia River Gorge or in the beautiful foothills of the Cascades, a single 2 MW wind turbine, made from a thousand tons of steel and two thousand tons of cement, costing $3.4 million, operating 30% of the time (8,766 hours x 0.30 = 2,630 hours/yr) for 20 years will generate only 105 million kWhs over its economic life (52,596 hours x 2,000 kW). A little more or less depending on luck and maintenance. This 105 million kWhs will cost $5.0 million in total: $3.4 million in construction and $1.6 million in O&M over its life. To replace Columbia Generating Station’s 180 billion kWhs over 20 years will require construction of 1,714 of these 2 MW wind turbines (180 billion ÷ 105 million) at a total cost of $8.6 billion plus another $0.72 billion to connect to the grid, bringing the total life-cycle cost to $9.3 billion for 180 billion kWhs, or 5.2¢/kWh. A bit higher than Columbia Generating Station’s 4.2¢/kWh and similar to the highest end of future costs possible for the nuclear plant under its PPA. Connecting to the grid includes transformers and substations, as well as the connection to the local distribution or transmission network and costs between $170,000 and $250,000/MW, or about $720 million for these seventeen hundred 2-MW turbines. Columbia Generating Station is already connected to the grid. However, according to the Renewable Energy Foundation of London, the economic life of onshore wind turbines is between 10 and 15 years, not the 20 to 25 years used for government projections, so this estimate of costs for wind is significantly lower than reality, making Columbia Generating Station even more cost-effective compared to wind. In addition, this amount of wind is more wind energy than exists in all of Washington State right now, and that took a decade of intense building and serious subsidies to achieve. Solar is even more expensive than wind. Warren Buffet recently purchased the world's largest photovoltaic solar array in Bakersfield, California. It is a 5-square-mile 579 MW PV array that cost a little over $2.2 billion. With a capacity factor of 25% over the expected 25-year lifespan, this utility-scale PV will generate only 32 billion kWhs over its total life. PV solar O&M costs of 1.3¢/kWh adds $400 million over the life of this array. So to produce 32 billion kWhs at a total cost of $2.3 billion means a life-cycle cost of 7¢/kWh, not including connectivity. McCullough can dance around levelized costs, financing issues, tax credits and other non-costs to try to make the price of wind sound good, but the actual costs don’t show that. Columbia Generating Station doesn’t have any hidden costs as it’s already built and running and contractually locked-in to its present price until 2043, a risk reduction that has a fair value of its own. But the bigger issue here is the foolishness of building wind in an area already dominated by hydroelectric. Washington State is about 70% hydroelectric, so it took a law enacted in 2006 to outlaw hydro as a renewable just to get wind built here at all, since the renewable mandates, and the associated tax credits, would not have been invoked if hydro were considered a renewable. Which it is. Unlike along Tornado Alley from Texas to North Dakota, in the Pacific Northwest wind doesn’t really add to our generation capacity as it competes with hydropower, not fossil fuels. Bonneville Power Administration, the region’s wholesale power broker, by law has to ramp down hydropower in order to take wind onto the grid, spilling water over the dam and wasting the hydropower (see figure below on load-balancing for last week). Our dams are run-of-the-river so you can’t store the water for future power. This is especially a problem during spring runoff. It is true that wind gets a 2.3¢/kWh production tax credit which has a pre-tax value of about 3.4¢/kWh, depending on regional tax rates, plus federal tax incentives and whatever State incentives exist. But this just moves the cost from the ratepayer to the taxpayer, it doesn’t get rid of it. It does give wind a great market advantage, making the owners lots of money, but does not give anything to the ratepayer. And the tax credit is set to expire in 2021, unless Congress extends it. The McCullough report makes a big deal about other nuclear plant closures in the country as support for shutting down Columbia Generating Station. Unfortunately, he misrepresents those closures. He cites Pacific Gas & Electric Company’s recent announcement to phase out its nuclear reactors at Diablo Canyon in California over the next decade, under a proposal made jointly with anti-nuclear groups. McCullough claims Pacific Gas & Electric will replaced this nuclear energy completely with gains in efficiency and renewables. But the proposal’s details do not say this at all. In fact, it calls for implementing renewables and efficiency equal to only a quarter of Diablo Canyon’s generation. Instead, experts agree, the generation will mainly be replaced by natural gas, and attempts to buy energy from out-of-state, particularly from our hydroelectric plants up here in the Pacific Northwest and, ironically, from the Columbia Generating Station itself. This has been the experience with other recent nuclear shut-downs, including San Onofre, also in California. In 2012, when the San Onofre nuclear plant closed, natural gas became the main replacement power source, contrary to claims by the renewable advocates, creating emissions of carbon dioxide equivalent to putting two million new cars on the road. The utility, SoCal Edison, does not ever expect that energy to be replaced by renewables. A similar step backward is happening in the Northeast, where closing the Vermont Yankee Nuclear Plant in 2014 meant an increase in natural gas use, leading to 5% higher carbon dioxide emissions in New England. Ironically, Vermont has ended up buying nuclear power from Massachusetts, a real stick-in-the-eye to the several thousand Vermonters put out of work by the politically-motivated closure. In the end, Columbia Generating Station’s nuclear bird-in-the-hand is worth way more than two renewables-in-the-bush. Dr. James Conca is a geochemist, an energy expert, an authority on dirty bombs, a planetary geologist and professional speaker. Follow him on Twitter @jimconca and see his book at Amazon.com
News Article | November 10, 2016
Bureau of Reclamation Commissioner Estevan López announced today the selection of Max Spiker as Senior Advisor for Hydropower and Electric Reliability Officer. Reclamation is the second largest generator of hydropower in the country; its 53 power plants annually generate an average of 40 billion kilowatt hours of electricity, enough to meet the demand of 3.5 million homes. "The availability of hydropower from Reclamation facilities is key to the stability of the electric transmission system in the Western United States and supports the development of renewable energy throughout the West," Commissioner López said. "Max’s extensive experience from all levels of power operations and management, including working collaboratively with Reclamation’s customers, stakeholders and industry, will be a great asset to Reclamation as it ensures the reliable generation of clean renewable electricity into the future." As senior advisor, Spiker will coordinate implementation of corporate partnership efforts involving Reclamation's power functions and serve as the liaison on intergovernmental initiatives associated with hydropower delivery and be responsible for Reclamation's overall compliance with Federal Energy Regulatory Commission Mandatory Bulk Electric System Reliability Standards. He will also coordinate activities in collaboration with the U.S. Army Corps of Engineers, Bonneville Power Administration, Western Area Power Administration and the Tennessee Valley Authority. Since 2013 Spiker has been the power resources manager where he worked with Reclamation offices in managing Reclamation's hydropower operation and maintenance program, reliability compliance program and renewable energy program. He joined Reclamation's Power Resources Office in 2010 as the operation and maintenance program manager where he provided policy direction and oversight. He previously held multiple positions including mechanical journeyman at Hoover Dam, facility manager at Green Mountain Dam, Estes Lake and Marys Lake power plants, facility manager of the Colorado - Big Thompson Project and power manager of the Upper Colorado Region where he managed the power program on the upper Colorado River and its tributaries, including Glen Canyon Dam, Flaming Gorge Dam and the facilities on the Gunnison River. Spiker has more than 28 years of experience with Reclamation. He graduated from Weber State University in 1988 with an Associate of Science degree in Construction Technology. He begins his new responsibilities this week.