News Article | January 5, 2016
Over the past year, the Department of Energy has been putting an increased focus on technology to integrate renewable energy into everyday grid operations. This work has included opening loan guarantees to distributed renewables, grants to support field tests of distributed energy integration, and future funding plans to support the development of grid modernization technologies. Now the DOE’s blue-sky research agency, ARPA-E, is getting into the action -- or, as befits its mission, ahead of the action. Last month, ARPA-E announced $33 million in grants for its Network Optimized Distributed Energy Systems (NODES) program, meant to help 12 university, corporate and DOE laboratory projects that are trying to turn grid-edge assets into networked “virtual storage” systems. These projects are meant to “enable real-time coordination between distributed generation, such as rooftop and community solar assets, and bulk power generation, while proactively shaping electric load.” That could allow utilities to manage greater than 50 percent renewable penetration on the grid, “by developing transformational grid control methods that optimize use of flexible load and distributed energy resources.” This is not a unique concept. Distributed energy resource management software, or DERMS, platforms are being developed to tackle this challenge in one way or another, with grid giants like Siemens and Toshiba and startups such as Spirae, Enbala, Integral Analytics and Smarter Grid Solutions providing different pieces of the puzzle. Beyond that, there’s work being done by consortia such as Duke Energy’s Coalition of the Willing and Pacific Northwest National Laboratory's transactive energy pilot project to allow lots of distributed energy assets to communicate and act in concert to solve local and system-wide grid challenges. Some of the projects funded by ARPA-E’s NODES program would help support these kinds of ongoing distributed energy resource (DER) integration efforts, while others would go several steps beyond what today’s utility grid control platforms and DERs are built to handle. Here’s a short description of each project and its aims.
News Article | January 6, 2016
Over the past year, the Department of Energy has been putting an increased focus on technology to integrate renewable energy into everyday grid operations. This work has included opening loan guarantees to distributed renewables, grants to support field tests of distributed energy integration, and future funding plans to support the development of grid modernization technologies. Now the DOE’s blue-sky research agency, ARPA-E, is getting into the action — or, as befits its mission, ahead of the action. Last month, ARPA-E announced $33 million in grants for its Network Optimized Distributed Energy Systems (NODES) program, meant to help 12 university, corporate and DOE laboratory projects that are trying to turn grid-edge assets into networked “virtual storage” systems. These projects are meant to “enable real-time coordination between distributed generation, such as rooftop and community solar assets, and bulk power generation, while proactively shaping electric load.” That could allow utilities to manage greater than 50 percent renewable penetration on the grid, “by developing transformational grid control methods that optimize use of flexible load and distributed energy resources.” This is not a unique concept. Distributed energy resource management software, or DERMS, platforms are being developed to tackle this challenge in one way or another, with grid giants like Siemens and Toshiba and startups such as Spirae, Enbala, Integral Analytics and Smarter Grid Solutions providing different pieces of the puzzle. Beyond that, there’s work being done by consortia such as Duke Energy’s Coalition of the Willing and Pacific Northwest National Laboratory’s transactive energy pilot project to allow lots of distributed energy assets to communicate and act in concert to solve local and system-wide grid challenges. Some of the projects funded by ARPA-E’s NODES program would help support these kinds of ongoing distributed energy resource (DER) integration efforts, while others would go several steps beyond what today’s utility grid control platforms and DERs are built to handle. Here’s a short description of each project and its aims. Greentech Media (GTM) produces industry-leading news, research, and conferences in the business-to-business greentech market. Our coverage areas include solar, smart grid, energy efficiency, wind, and other non-incumbent energy markets. For more information, visit: greentechmedia.com , follow us on twitter: @greentechmedia, or like us on Facebook: facebook.com/greentechmedia.
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 | December 11, 2015
Shayle Kann and the GTM Research analyst team give GTM Squared members insight into our internal discussion and debate on the latest business developments across solar, grid, and energy storage markets in this monthly column. Shayle Kann Senior Vice President, Research: Grid Edge team, as you know, the California Public Utilities Commission (CPUC) has been under the gun to come up with a plan for merging the distribution resources plan (DRP) and the integration of distributed energy resources (IDER) into a cohesive whole. They recently held the first official joint workshop to hash out how it’s going to proceed, along with a straw proposal that helps clarify the timeline for certain key decisions over the next 12 months. There's required reading on the subject by Jeff St. John for GTM Squared that we published just last week. After reviewing the workshop proceedings and Jeff’s article, what did you learn about the plan? And do you think the CPUC is moving in the right direction to systemically remake energy procurement in California? Steve Propper Director, Grid Edge: To begin with, I think this is one of the first major attempts at combining large-scale integrated resource planning (the DRP proceeding) with utility/third-party and customer-owned assets (the IDER proceeding) into one regulatory conversation. For years, there have been a multitude of proceedings tackling each part of this separately -- there were solar and distributed generation (DG) proceedings, advanced metering infrastructure (AMI) and smart grid infrastructure proceedings, requests for cost recovery on various new technologies pilots, etc. There was also the infamous Integrated Demand-Side Management (IDSM) proceeding that languished out there and dates back more than five years, without tangible results at effectively merging overall distributed asset portfolio management at the regulatory level. So it's encouraging to see the CPUC take some more aggressive action and think more holistically about distribution planning and behind-the-meter resources (which, happily, includes demand response and other "non-generation" technologies). It's starting to sound a bit like New York REV, which isn't entirely surprising given recent talk from Albany on a New York-California distributed energy resource (DER) partnership. And, on the whole, the framework proposed by the CPUC makes logical sense from a business planning perspective. Shayle Kann Senior Vice President, Research: Steve Propper, you say it's encouraging, but will it be effective? First, I think the timeline for 2016 -- while ideal as a grid-edge technology enthusiast -- is quite aggressive. The January workshop to begin integrating in IDER aspects is what I see as one of the biggest challenges. Full agreement on how to measure benefits, assign compensation and get the methodology squared away for the locational net benefits analysis (LNBA) of the future pilots is key to effectively testing the pilot pipeline planned for the rest of the year (some of which don't have technology or vendor selection complete yet). I'm not totally skeptical, but have doubts on the timing given the amount of moving parts and the likely continued disconnect with how much data utilities are willing to share. Additionally, I think the goals of having advanced workshops by mid-2016 that detail pilot results and begin to integrate other proceedings like interconnection, storage and electric vehicles (EV) is a bit lofty without an unprecedented level of open dialogue and investor-owned utility-regulatory engagement. I'd be curious to get Ben Kellison's take on this. Ben Kellison Director, Grid Research: I would say this is a major step forward for the CPUC. The integrated nature of the conversation around integrated capacity analysis (ICA) and LNBA, if done right, could be a major leap forward in effective valuation and procurement of resources based on their value to the network. This would effectively address the value of solar, help determine optimal resource levels, and guide financial resources to more effective locations on the grid, all in one proceeding. This is a major shift for the CPUC; it has traditionally siloed all of these efforts into individual proceedings, sacrificing integration for faster implementation. This is a major advantage from an efficiency of capital perspective, but it creates a huge risk in the efficiency of negotiation. Workshops over the next year will have to make some major breakthroughs to set up the DRP pilots for success in the coming five years. The proceeding also hinges on several major technological and data management efforts to remake planning and simulation processes to incorporate DERs. Initial signs of the complexity involved with this process were shown in July with the release of the DRP plans that detailed the three IOUs' methodology to create an ICA. I am interested to see what compromises will have to be made to the vision of the proceeding in order to achieve value and meet milestones. For instance, will Southern California Edison be limited in its ability to determine the value of a particular resource on a single feeder because of its choice to utilize representational circuits? Will limitations like this force the CPUC to temper expectations to focus on the saturation and value of a resource deployment at the substation level in the short term and push out timelines for more detailed analysis? Omar Saadeh Senior Analyst, Grid Edge: Interestingly, DRP and IDER aren’t the only CPUC initiatives planned for full implementation by 2018. Two other CPUC initiatives are also scheduled for full implementation in two years: demand response direct participation and the demand response auction mechanism (DRAM). And coincidentally, both initiatives have also been featured in a past Jeff St. John thriller. On one hand, the commission’s direct participation initiative will require IOU demand response (DR) programs to be integrated as resources in the CAISO wholesale energy market. On the other, the CPUC’s demand response auction mechanism (DRAM) plans to create a competitive solicitation process for DR providers -- in this case, the IOUs -- to get paid today for future energy reductions. It’s essentially an open bidding DR capacity auction, very similar to PJM's structure. While all this is undoubtedly very progressive, there are still many questions on the table which may ultimately push back some of these deadlines. Andrew Mulherkar Analyst, Grid Research: I'm not sure that "progressive" fully captures the nature of the CPUC's work here. It appears to me that this effort is critical element of a tectonic shift in how California's electric utilities plan for, procure, and pay for energy resources. The CPUC is looking to transform traditional, centralized resource procurement into a next-generation procurement process that leverages the extraordinary growth of distributed solar PV, controllable loads, energy storage, electric vehicles and energy efficiency. The integration of the two proceedings will ideally give utilities both a way to value and plan for distributed energy resources (through the DRP) and to actually procure the resources (through the IDER). Now, as eager as I am to see a comprehensive approach here, the scope of the approach is daunting. As Steve Propper points out, the precursor to IDER languished -- and that's despite a relatively siloed and limited scope. One exciting idea to emerge from the IDER proceeding is incentives that reflect locational benefits. Once fully developed, it's not inconceivable that consumers could receive solar PV incentives just based on the characteristics of their local distribution feeder. Then we can look back and smile at the days when demand-side management (DSM) meant mailing compact fluorescent lamps (CFLs) to any and every customer. Steve Propper Director, Grid Edge: CFLs! I recall a few Saturdays educating customers about lighting with retail partners like Sears, Lowe's and Best Buy. I agree with previous comments, but as I was thinking about this last night, I can't seem to shake the importance of the CPUC getting the data-sharing and third-party access components "squared" away early on in these workshops next year beyond the A and B pilots, which look pretty straightforward. I might suggest they make sure to have some experts from the wireless, banking and/or consumer internet worlds playing an active role in these workshops to push some more aggressive thinking in how this can get accomplished. I understand the utilities' trepidation over security and customer data, but I also think you will see third parties and ultimately customers become more active in participating if it's clear what the benefits are related to DER procurement and ongoing distribution-level management. Also, as the end-user equation within this joint proceeding gets worked out, I'd hope there is also a realistic conversation about the notion of perceived privacy vs actual privacy over sharing more granular data points such as usage data and behind-the-meter DER asset performance. Think about all the apps that are collecting and sharing customer data today...a far cry from 10 years ago without that much ruckus around privacy. Omar Saadeh Senior Analyst, Grid Edge: Taking a look at vendor prospects, I think potential opportunities will go beyond incumbent vendors -- those with circuit-level modeling or control systems already deployed at the IOUs -- to companies offering utility distribution management support and third party DER fleet management. Think Enbala, Blue Pillar, Smarter Grid Solutions, Spirae, 1Energy Systems, etc. Moreover, it’s not surprising that DER providers like SolarCity, Sunverge and Enphase have been developing grid software that extends beyond asset management. Not to be overly bold, but I’d expect SolarCity’s GridLogic technology to eventually scale beyond just microgrids. With regards to DR -- it’s really interesting to see how the vendor community is reacting. As utilities become less dependent on third-party program implementation and with continued uncertainty in wholesale demand response markets, companies are clearly taking notice, some even shifting business models. For example, EnerNOC is diversifying away from market-based DR, which it deems to be higher-risk, and into enterprise and utility software-as-a-service -- a move pursued by Enbala not too long ago. On a bright note, similar to PG&E’s recent DERMS RFP, I’d expect project scopes to be left somewhat open-ended, providing vendors with opportunities to showcase platform strengths and -- very importantly -- expand capabilities while under utility support. Click here to learn more about the latest grid edge research from GTM Research. You can read bios for the analyst team here.
News Article | February 24, 2017
In a highly competitive residential solar market, Route 66 Ventures has committed $130 million to Sunlight Financial, a provider of loans for residential solar systems. Route 66 Ventures makes credit and equity investments in the financial services sector. Solar installers and sales firms access Sunlight through an online platform, through which homeowners can apply for credit and sign loan documents. Mitsubishi’s American power subsidiary, Diamond Generating (historically focused on gas and traditional power plants) has acquired a near-majority interest in Boston's Nexamp, a solar and renewable project developer, according to Boston Business Journal. The deal will allow Nexamp to bring its commercial-scale energy project development and community solar to Maryland, Georgia and New Jersey. View, the Milpitas, Calif.-based tintable-window startup, raised $100 million in VC funding led by TIAA Investments, an affiliate of $882 billion Nuveen. View holds a valuation of $1.1 billion, according to PitchBook. View has raised more than $600 million since its inception as Soladigm seven years ago from investors including Corning, Madrone Capital Partners, Khosla Ventures, GE, Reinet Investments, NanoDimension, DBL Investors, Navitas Capital, Sigma Partners and The Westly Group. View claims over 300 installations in North America, with another 150 in progress. View’s main competitor, SageGlass, is owned by Saint-Gobain. Kinestral Technologies also recently raised $65 million in a Round C funding for its tintable glass. Enbala raised at least $12 million in Series B financing led by ABB Technology Ventures, the Swiss grid giant's venture arm. ABB just picked Enbala’s technology to build out its distributed energy resource management system (that's DERMS) -- a hot commodity among forward-looking utilities, particularly those in regions with lots of customer-sited rooftop PV. Enbala has raised about $42 million from investors including GE Ventures, Chrysalix and Obvious Ventures. Enbala's competition on the DERMS front includes grid giants developing their own platforms, and startups like Advanced Microgrid Solutions, Blue Pillar, AutoGrid, Opus One, Power Analytics, Spirae, Smarter Grid Solutions, and the recently acquired Viridity Energy. GreenSync raised $11.5 million in a Series B round led by Australian government-owned Clean Energy Finance Corporation and Southern Cross Venture Partners. The firm has shifted from peak demand management services to a software platform that controls and optimizes energy resources and battery storage. GreenSync appears to be a direct competitor to Enbala, AutoGrid, etc. The firm is taking part in a T&D deferral trial project and a "project in Australia that looks a lot like a REV demo." NRStor, a Toronto-based energy storage project developer, won an $11 million equity financing commitment from the Labourers’ Pension Fund of Central and Eastern Canada. NRStor has won contracts with Ontario’s Independent Electricity System Operator for utility-scale energy storage projects and is working with Hydrostor and Temporal Power. NRStor built Canada’s first commercial grid-connected flywheel facility, and is developing Canada’s first commercial compressed air energy storage facility. Its majority investor is Lake Bridge Capital. MineSense, a provider of data analytics for the mining industry, closed a $14.5 million round led by Aurus Ventures along with Caterpillar's VC-investment arm, Chrysalix, Cycle Capital Management, Prelude Ventures and Export Development Canada. MineSense's sensors and data analytics software can impact "both the mines' productivity and environmental footprint," said Victor Aguilera of Aurus Ventures. SparkFund, a Washington, D.C.-based financial technology startup, closed a $7 million Series B led by Energy Impact Partners along with existing investor Vision Ridge Partners and others. SparkFund looks to offer an "efficiency-as-a-service" subscription model to provide businesses with efficiency measures for a single monthly payment and no upfront cost. Why is long-in-the-tooth grid startup Tendril raising another $5 million in venture funding? QD Solar, a Toronto solar startup, won $2.5 million in a Series A financing led by Dutch VC firm DSM Venturing along with MaRS Innovation and Saudi Arabia’s KAUST Innovation Fund. QD Solar’s quantum dot-based solar cells use "nano-engineered, low-cost materials that can absorb the otherwise wasted infrared light" with the potential to boost overall power generation by 20 percent, according to the firm. ConnectDER, an early-stage firm developing a meter collar that lets residential solar connect to the grid cheaply and rapidly, has closed a $1.1 million Series A round through a collaboration between Investors’ Circle and PRIME Coalition. PRIME Coalition is a 501(c)(3) public charity that allows philanthropists to place charitable capital into market-based solutions to climate change. WattGlass, an Arkansas-based startup, won Series A funding from DSM Venturing for its anti-reflective and anti-soiling coating with applications in solar and other markets. First Solar acquired Enki Technology for its anti-reflection coatings late last year after receiving funding from Applied Materials, RockPort and the DOE's SunShot program. Pollinate Energy won support from Tata Trusts, an Indian philanthropic organization, for its "last mile distribution of social impact products" like solar lights and water filters in India's slums. Enphase has "refinanced and extended its term loan facility with certain funds managed by Tennenbaum Capital Partners (TCP) from $25 million to $50 million. In connection with the TCP refinancing, Enphase says it will consolidate its lender relationships by repaying amounts currently drawn under its existing line of credit facility with Wells Fargo Capital Finance and close that facility. Ascent Solar has shipped limited volumes of its portable CIGS thin-film solar charging devices, but Hong Kong Boone Group Limited still invested $20 million in its purchase of Ascent's newly designated Series K Convertible Preferred Stock. GTM Research analysts Andrew Mulherkar, Paulina Tarrant, Elta Kolo and Brett Simon contributed to this article.
Agency: European Commission | Branch: H2020 | Program: RIA | Phase: FoF-08-2015 | Award Amount: 7.01M | Year: 2015
OPTIMISED aims to develop novel methods and tools for deployment of highly optimised and reactive planning systems that incorporate extensive factory modelling and simulation based on empirical data captured using smart embedded sensors and pro-active human-machine interfaces. The impact of energy management on factory planning and optimisation will be specifically assessed and demonstrated to reduce energy waste and address peak demand so that operations that require or use less energy, can allow this excess energy to be re-routed to local communities. The OPTIMISED environment will use semantically enriched process modelling, big-data generation, capture and perform analytics to effectively support planning specialists, manufacturing engineers, team leaders and shopfloor operatives throughout the systems lifecycle. These next generation manufacturing systems supported by data rich manufacturing execution systems with OPTIMISED technology will support a dramatic improvement in system performance, improved operational efficiency and equipment utilisation, real-time equipment and station performance monitoring, adaptation and resource optimisation. The OPTIMISED vision will be achieved by developing systems which are able to: 1. Monitor system performance through an integrated sensor network, automatically detecting bottlenecks, faults and performance drop-off 2. Continuously evolve to respond to disruptive events, supply chain disruptions and non-quality issues through factory simulation modelling 3. Improve understanding and monitoring of energy demand curve and energy usage per industrial process and globally improve efficiency of production line through reduced energy waste 4. Understand potential benefits, added value and impacts of participating in Demand Side Response (DSR) processes and becoming an active player in the changing energy industry, instead of remaining a conventional passive element that simply acquires a service from energy providers
News Article | February 15, 2017
It’s the first day of the big DistribuTech conference in San Diego. Grid giants and startups are unveiling their latest products aimed at connecting utilities with the grid edge. Let’s start with Enbala, the Vancouver, Canada-based startup that has deployed its software platform to turn industrial energy loads like pumps and refrigerators into megawatts' worth of fast-responding grid assets. On Tuesday, it announced its biggest partner yet: Swiss grid giant ABB, which has tapped Enbala’s Symphony software platform as part of a new, jointly developed distributed energy resource management system (DERMS). The term "DERMS" applies to software that can integrate the needs of utility grid operators with the capabilities of flexible demand-side energy resources at the edges of the grid. DERMS platforms come in all shapes and sizes, from grid giants like Siemens and General Electric, to startups like Advanced Microgrid Solutions, Blue Pillar, AutoGrid, Opus One, Power Analytics, Spirae, Smarter Grid Solutions, and the recently acquired Viridity Energy. But for the most part, they’ve typically been organized in two different ways -- top-down extensions of utility or grid operator controls out to customer endpoints, or bottom-up aggregations of customer loads into grid energy markets. Enbala and ABB’s combo DERMS platform intends to erase this distinction, Enbala CEO Bud Vos said. On the utility side, ABB brings a well-known set of tools, like its advanced distribution management software (ADMS) with its “single network model” and “unified geospatial control center operator environment." These are tools used by utility operators to monitor and respond to changes on their distribution grids. “Our platform is an extension of the ADMS platform, and tightly integrated with that ADMS framework,” Vos said. ”It provides cohesiveness, from an operational standpoint and from a data standpoint.” Enbala, in turn, brings a software platform that can tap into hundreds of individual loads per customer, collect and analyze their data, and then start to subtly shift their energy-use patterns in effective and profitable ways. Sometimes that means moving big water-pumping schedules to times of the day when electricity isn’t in high demand. Other times it involves turning thousands of water heaters and refrigerators on and off in response to 4-second signals to help balance grid frequencies. So far, Enbala has been aggregating responsive energy loads on behalf of its customers in frequency regulation markets run by mid-Atlantic grid operator PJM and Ontario's Independent Electricity System Operator. As one of several partners in the PowerShift Atlantic project, it has also used its software platform, managed by employees at its network operations center, to help control customer loads to firm wind power for Canadian utility NB Power. In the past year or so, Enbala has been getting more into the distribution grid side of things. At last year’s DistribuTech, the company was demonstrating pilot projects in Hawaii using rooftop PV solar inverters, and a project in Southern California modeling big industrial and commercial loads’ potential to help balance grid disruptions. “We think we’re going to see hundreds of thousands, if not millions, of connected energy deices coming to market,” Vos said. “You’ve got to be able to optimize millions of assets in seconds, or even sub-second timescales, and with accuracy, to know that power is moving to the right places at the right time.” Enbala has also kicked its computing capabilities up a notch with its latest rollout, he said. “Under the covers of this release, we’ve updated our learning algorithms and optimization algorithms,” he said. It is using a software language called Erlang, originally built for the telecommunications industry, that can run millions of simultaneous transactions at a speed that allows for real-time decision making. It’s hard to define the DERMS competitive landscape, since it’s such a new field. But GTM Research predicts that the North American DERMS market will reach $110 million by 2018, as today’s pilot projects start to become operationalized at utilities in states with lots of distributed energy to handle, like Hawaii and California. And ABB isn’t the only grid giant trying to colonize the DERMS space. Take Siemens, which launched its own DERMS product at DistribuTech on Tuesday, complete with “tools that provide data and visibility across the energy system, from distribution grid planning to market forecasting.” The new DERMS platform is built on Siemens’ work on microgrids, a big focus of the company's efforts at DistribuTech conferences over the past few years. This work includes partnerships with startup Utilidata, as well as adaptations of the company’s Spectrum 7 control software into local grid applications. To date, Siemens has rolled out these capabilities in microgrid projects with universities and government partners, such as the Department of Energy-funded microgrid project with Case Western Reserve University and NASA. But it’s also linking those microgrids to utility systems, said Mike Carlson, president of Siemens Smart Grid North America, in an interview. On the data side, Siemens released an integrated application for its EnergyIP software on Tuesday, combining distributed energy management, virtual power plant capabilities and demand response on one platform. EnergyIP, built on the software of Siemens acquisition eMeter, “is architected for a true real-time, cloud-based IOT system,” Carlson said, capable of giving grid operators second-by-second control and analysis capabilities. “What we built is very modular, or scalable, or agile, components that you can bolt onto existing capabilities, and scale them based on size, or capability,” he said. The costs for standing up a microgrid range from the low six figures for simpler applications, up to the millions of dollars to enable sub-second monitoring required for certain grid applications, he said. But that’s “about half the cost of a traditional enterprise deployment,” since it has already combined all the requisite pieces of the microgrid puzzle. General Electric, which has invested in Enbala through GE Energy Ventures, has also been promising a DERMS offering, built on the work it’s been doing with Duke Energy’s Coalition of the Willing, and the Nice Grid project in southern France. GE has also been working with Enbala on a project under the Department of Energy’s ARPA-E NODES program. Vos noted that Enbala’s work with ABB is a non-exclusive partnership, freeing it to work with multiple partners. Right now the company has six projects, including two contracts for virtual power plants and two regulated utility DERMS contracts that are focused on optimization of distribution feeders. Make sure to attend Greentech Media’s Grid Edge World Forum 2017, our premier conference and exhibition focused exclusively on tomorrow’s distributed energy system. Join us to discuss and debate the latest issues impacting tomorrow’s distributed energy system, and examine the trends and innovation happening at the grid edge. Learn more here.
Agency: European Commission | Branch: H2020 | Program: SME-1 | Phase: SIE-01-2015-1 | Award Amount: 71.43K | Year: 2015
eCAP is an innovative power network planning and analysis tool for self-assessment of network capacity for DG connection. eCAP provides Distributed Generation (DG) developers with the ability to analyse the viability of conventional and ANM grid connections prior to making a connection application. DG Developers are able to choose a Point of Connection (PoC) in the network and receive an estimate of the available network capacity based on the type of generation technology and rated capacity. Currently, no such tool is available to support DG Developers who are forced to undertake complex studies using specific power systems analysis software and sophisticated techniques to determine the available capacity at a given PoC. eCAP tackles this problem using a modular software solution based on original power system modelling and analysis techniques. eCAP deals with this complex problem while delivering an intuitive and straightforward interface to the users. eCAP has an intuitive, web-based platform for DG developers to consider the feasibility of ANM-based connections and allows DSOs to vastly improve their customer service by identifying opportunities for ANM solutions to free a large portion of network capacity that otherwise would not be accessible. It has been successfully demonstrated as a proof of concept as part of the Accelerating Renewable Connections project (2012-2015) in a limited grid area with many connection requests defined by the DSO, SP Energy Networks. eCAP will enhance and support the existing SGS real time control products portfolio with a new product in planning tools. This feasibility study focuses on enhanced market analysis, the benefits and feasibility of re-platforming eCAP for being commercially fit, and identifying the requirements and design of new analytical and user interface functionality.
News Article | February 1, 2014
First published on the Cleantech Investor website, February 2014 Smarter Grid Solutions, a University of Strathclyde spin out, has secured its first US contract, with Con Edison – in collaboration with NYU Poly and the NYU Center for Urban Science and Progress. The company, which is headquartered in Glasgow in Scotland, will be involved in a project to develop technologies to increase the resiliency of the electrical grid during a variety of potential contingencies and emergencies, such as weather-related power outages, and supporting the increased connection of distributed energy resources. Part of the Electric Power Transmission and Distribution Smart Grid Program, funded by the New York State Energy Research and Development Authority (NYSERDA), the project win was announced by the Governor of the State of New York, Andrew M. Cuomo. According to Smarter Grid Solutions’ Chief Technology Officer and Co-Founder, Dr Bob Currie: “ We bring a great deal of experience in the creation and management of smart grids to New York’s developing smart grid and microgrid activities. Our Active Network Management approach has been deployed extensively in Europe, allowing power companies and utilities to create more resilient and cost effective power grids in challenging conditions. We look forward to having a technical analysis and design role in this pioneering project and contributing to the exciting work going on in New York City and the wider State of New York.” The project will investigate how distributed energy resources (DER), including microgrids, can be integrated by Con Edison to increase resilience. It will look at two target areas of the electrical distribution grid within Con Edison’s service territory. The assignment will include grid analysis and gathering stakeholder input to create recommendations on how power systems technologies - including Active Network Management - can be used to create future smart grid and smart city infrastructure through the facilitation of microgrids.
News Article | June 22, 2015
NuGen, the UK new nuclear build developer, today (22 June) announced that Robert Armour has been appointed by the board as Deputy Chairman of the company. Mr. Armour brings over 25 years' experience in the UK nuclear sector, having formerly been General Counsel and Corporate Affairs Director of British Energy Group, and, before that, Company Secretary and Legal Adviser at Scottish Nuclear. Mr Armour was a pivotal member of the British Energy team during the government-backed restructuring of the company between 2002-2005, and instrumental in the turnaround of British Energy's nuclear performance. Having been a board member of a UK nuclear licencee for over a decade and as a former member of the Civil Nuclear Police Authority, his experience will help the Board to develop the organisation of the company, and to position it with key external stakeholders, as it progresses the Moorside development. Since 2010, Mr. Armour has been Senior Counsel in the London office of Gowlings, an international legal practice, advising on nuclear and wider energy matters. He is also a non-executive director of the Nuclear Liabilities Fund, Albion Community Power plc, and chair of Smarter Grid Solutions Ltd. In 2013 Mr. Armour chaired the Expert Commission on Energy Regulation established by the Scottish Government looking at future regulatory models. Previously he was a director of Equiniti David Venus, a Board Governance consultancy, and chair of the Scottish Council for the Development of Industry (SCDI). NuGen's Board warmly welcomed Mr. Armour's appointment. NuGen chairman Shigenori Shiga said: "We welcome Robert Armour to the NuGen team. His knowledge and expertise will be of great assistance as we move forward with our Moorside project in Cumbria." Paul Rorive, member of the NuGen Board said: "We are very pleased to have Robert Armour in the NuGen team. He will be a valuable advocate for our programme given his prominence within the UK nuclear industry." NuGen is building-up its UK nuclear expertise as the company moves forward with its Moorside project, with plans to deliver 3.4GW of new nuclear at the site adjacent to the Sellafield complex. NuGen is a UK nuclear company owned by Toshiba and ENGIE (formerly GDF SUEZ). When fully operational, the planned Moorside reactors will have a combined capacity of 3.4 GW, enough to power up to six million homes. The first of the three Westinghouse AP1000 reactors is targeted to come online in 2024. NuGen's Moorside project will help support the UK Government's low carbon and energy security objectives at a time when existing power plants are retiring and low-carbon generation is required to meet national and international commitments. Construction of the new reactors will create thousands of skilled jobs over the next decade, and the project is expected to significantly boost the local, regional and national economies, with a large portion of the development and construction programmes accessible to the UK supply chain. AP1000 is a trademark of Westinghouse Electric Company LLC. All rights reserved.