- About Us
- News & Events
- Career Center
- Our Blog
Ken Munson, CEO of Stockton, Calif.-based startup Sunverge Energy, doesn’t want you to think of his company’s product as a “battery in a box,” backing up a roof full of solar panels -- even if that’s one very accurate way to describe what it packages up into a closet-sized, UL-certified form.
Instead, he’d like you to consider the Solar Integration System as an energy manager for the modern, solar-PV-equipped home -- and, importantly, one that utilities see as an asset, not a threat.
“We’re very utility-centric,” Munson said in a March interview. “We believe that, inherently, a utility focus, utility ownership, even utility rate-basing [of] our devices as an asset, is where the industry is moving.” That’s a view that doesn't align with the 'customer-owned solar+storage=utility existential threat’ views we’ve seen expressed lately. It’s also a departure from the way that competitors like SolarCity or Stem have targeted building owners as their storage customers.
But with 2 megawatts of its systems deployed from Sacramento, Calif. to Auckland, New Zealand, Sunverge is on its way to getting a pretty broad set of test utilities for its behind-the-meter storage platform. In fact, Sunverge ranks third behind SolarCity and Stem in terms of total megawatts of advanced battery projects planned in California, according to the state’s Self-Generation Incentive Program records. With California regulators moving to break a year-long impasse between utilities and customers over how to connect battery-backed solar systems to the grid, those projects could accelerate in the months to come.
Now Sunverge is turning to the next phase of its plans: networking those distributed solar-storage systems into a virtual power plant that is able to store, shift and balance electricity at grid scale. “Stuffing lithium-ion or flow or any kind of battery in a box and putting it in as a simple backup device is not that exciting,” Munson said. “But putting a cloud layer with real-time energy services on top, and being able to aggregate and control a fleet of devices on the grid in near-real time -- that’s something special.”Building a Solar Battery for Multiple Uses
Munson and Sunverge co-founder Dean Sanders worked in the grid business together, at Sacramento-based grid switchgear manufacturer Inertia Engineering, before founding their startup in 2009. “We think we understand the distribution grid pretty well” as a result, Munson said, and that informed the way they approached the solar-storage concept.
“The more we got into it, the more we realized there was a potential for a confluence to occur in the market, with the level of penetration that solar was taking on, and the operation issues we were hearing about regarding distributed PV on the grid,” he said. (Greentech Media has been covering the challenges of distributed PV on grid operations.)
Backed by their own funds and an undisclosed amount of venture capital investment, Sunverge assembles batteries from undisclosed partners (though Munson described them as top-tier suppliers), as well as inverters from Schneider Electric, into what is otherwise its own system. That includes its own local IT hardware and power electronics controls, as well as its cloud-based software platform, which keep real-time tabs on its solar generation and battery capacity at each networked Solar Integration System, and allows each unit to balance that combination to meet different needs, he said.
That doesn’t exclude helping the customer, he noted. “On some grids, UPS [uninterruptible power supply] is of paramount importance. In California, demand charge mitigation, peak shaving, and time-of-use shifting in certain applications is important.” These are the kinds of applications being targeted by companies like Stem, Green Charge Networks and Coda Energy in the United States, Sonnenbatterie in Germany, and Panasonic in Japan. Likewise, “We can get into the whole-home automation component, where our system, via our Open API architecture, can aggregate plug-load devices or discrete devices,” he said.
At the same time, “we can aggregate resources on a circuit or a feeder, and start solving operational issues for the utility,” he added. That’s the kind of work underway at utility pilot projects around the world, but it has yet to be rolled out at mass scale -- though companies like Intelligent Generation and Solar Grid Storage are exploring it in the context of larger, commercial-scale solar-battery deployments.How Solar Plus Batteries Blurs the Lines Between Utilities and Customers
Sacramento Municipal Utility District (SMUD) is tapping Sunverge’s systems for a 34-home “net-zero-energy” development, which means each home is expected to generate more energy than it takes from the grid over the course of a year. That’s not exactly a welcome prospect for utilities that make money by selling electricity to homeowners, unless the units can simultaneously serve a purpose for the utility.
Patrick McCoy, SMUD’s solar program planner, told us in an October interview that the utility is looking at several potential uses for Sunverge’s systems, including the potential to shift solar energy from midday to late afternoon, when it’s in highest demand on the grid. SMUD is also involved in state- and federal-funded pilot projects that are modeling the ebb and flow of solar power on distribution circuits, as well as linking up advanced inverters to utility communications networks.
In New Zealand, Sunverge is partnering with Vector, an Auckland-based provider of both energy and telecommunications services -- a hybrid type of utility that’s rare in the United States. This structure allows it to offer no-money-down solar-battery deals to its customers.
Vector CEO Simon Mackenzie said in a November interview that the company sees its role as a solar-storage provider in several ways. From the traditional utility perspective, “it allows us to manage the utilization and peaks on our network, to focus on how we better manage demand, and mitigate the risk longer-term,” he said.
From the perspective of making its customers happy, Sunverge’s platform supports iPhone and Android applications that allow customers to track how much solar’s being generated, how much battery storage is available, and how much the combination has saved the customer, he added.
Jon Fortune, director of regulatory and energy services for Sunverge, said at a February storage conference in Santa Clara, Calif. that the company has about 150 units, representing 600 kilowatts of aggregated capacity, installed with Vector so far. “All the communication happens in the cloud,” he said. “You can access all the units, full command and control -- we have a set of APIs that can integrate with any utility.”
Munson noted that Sunverge is working with standards groups like the SunSpec Alliance for advanced inverter communication and controls in order to future-proof its product for integration with a number of utility or grid market interfaces. It’s also a partner in the Energy Innovation Hub at Philadelphia’s Navy Yard redevelopment project, where it and a number of smart grid companies are working on distributed energy and net-zero energy concepts.
Whichever angle Sunverge’s customers end up pursuing, there’s little doubt that the combination of rooftop PV and ever-cheaper lithium-ion batteries is going to cause significant disruption in utility business models and customer relationships. “You’ve got a utility industry that has a fairly significant investment in sunken costs,” Munson said. “You’ve got a growing industry heavily invested in rooftop solar. And you’ve got to meet both of those parties' needs.”
Schneider Electric appointed Laurent Vernerey as president and CEO of its North America operations. Vernerey has been with Schneider for 28 years and worked his way up from plant manager to lead the company’s $8 billion North American line of business. Schneider has more than 150,000 employees and had sales of $31 billion in 2013.
KACO New Energy, a PV inverter manufacturer, named Jurgen Krehnke, previously president and GM of SMA America, as its new CEO for the Americas. Krehnke is currently a board member with the Solar Electric Power Association. KACO is hiring in its San Antonio, Texas offices to support the 400-megawatt OCI/PS project.
Vivint Solar, one of the largest U.S. residential solar providers, named Dwain Kinghorn as its Chief Strategy and Innovations Officer. Kinghorn joins Vivint Solar from SageCreek Partners. Prior to that, Kinghorn was CTO at Altiris.
OneRoof Energy, a solar services provider, named Valerie Iwinski as SVP of Operations. Most recently, she served as VP and GM at Express Scripts. Prior to that, Iwinski managed multiple business functions at American Express, including merchant and fraud services and customer call centers. OneRoof recently completed a transaction that resulted in the firm being listed as a public company on the Toronto Exchange.
Eric Hafter and Todd Lindstrom announced the founding of Enable Energy, "a technology, product development and business strategy consulting firm" that will seek to accelerate the deployment of solar PV and thermal technologies, energy-efficient lighting and energy storage. The company plans to announce a new commercial flat-roof racking system later this spring.
Greensmith has named Andrew Tang, formerly of AutoGrid, as SVP of Business Development at the energy storage management firm.
Dr. Mohan Narayanan, formerly the VP of technology at Hanwha SolarOne, is now Head of Strategic Marketing and Global Customer Quality Service at JA Solar.
Hanwha SolarOne, a manufacturer of solar modules, announced that its Chairman and CEO Ki-Joon Hong has retired from the firm. No reason was provided for the departure. A replacement is expected to be named by the end of April, according to a release.
Andalay Solar named Steven Chan as CEO and President. Chan has held positions at NRG Energy, GCL-Poly Energy Holdings and Suntech Power. He served as the Vice President of NRG Energy, overseeing residential solar for the company's NRG Residential Solar Solutions business.
Comverge, a supplier of demand response software for residential and C&I customers, named Gregory Dukat as Chairman, President and CEO. Dukat was most recently Chairman and CEO of Campus Management, a provider of software to higher education institutions. Dukat's appointment follows Blake Young's resignation as President and CEO. Comverge was acquired in 2012 by H.I.G. Capital.
Shayle Kann, SVP of Research at GTM, presented on solar's disruption of the wholesale energy market in Germany and the U.S. at the kickoff of the GTM Solar Summit in Phoenix, Arizona. It's an important presentation, and you can view it here.
But the next section of his presentation really connects the dots between the growth in solar and DG and the looming existential threat to utilities.How to disrupt a retail energy market
Step one for disruption is to install a lot of solar.
The following slide shows the phenomenal growth in residential and commercial solar, along with the 1.9 gigawatts of distributed solar installed in 2013.
But here's the kicker: that 1.9 gigawatts of solar, which is producing 2.7 million megawatt-hours, accounts for only 0.04 percent of national electricity demand. Why would utilities be impacted or worried by that small sliver of solar?
Kann next turned his attention to the top solar states -- perhaps the situation looks different there.
The U.S. market is still very concentrated, with the top seven states accounting for 88 percent of the market. But, with the exception of Hawaii, which remains an outlier in almost every case, even the top solar states, including California, satisfy very little of their overall load with PV.
Kann switches gears here. He suggests that we stop looking at total electrical generation.
He notes that utilities have historically made their money from load growth. But load growth has fallen steadily since 1950, and going forward, the EIA sees 1 percent load growth for the next 30 years. Except for Hawaii.
That 1 percent average applies to the top solar states as well. Except for Hawaii.
Through this lens, distributed solar's impact on 2013 load growth is already being felt. California, New Jersey and Massachusetts all saw their load growth cut in half by distributed solar.
Looking forward to 2016, Kann makes what he calls "conservative" growth estimates for distributed solar.
And based on those conservative forecasts, 2016 demand growth looks even more stark for utilities. He said, "You could see negative demand growth in California and almost [the same situation] in New Jersey."
"If you are a utility, this is potentially disruptive and very meaningful," he added.
Kann asked, "If you worked for a Hawaiian utility, wouldn't you be terrified?"
The last slide shows California retail electricity sales that have been and will soon be lost to solar.
"At its most destructive, you could call this the 'utility death spiral,'" particularly for an industry accustomed to recovering fixed costs through rates over 30 years.
In the face of a utility disruption of unknown consequence, Kann suggested that the solar industry needs to foster this disruption by building a sustainable business, saying, "We want to have a solar market in 30 years."
Instead of focusing solely on near-term buildup, Kann said, "We need to maintain a long-term view."
Confronted with the possibility of increasing numbers of wealthier people opting for solar or even potentially disconnecting from the grid, Kann added, "We need to maintain a strong eye toward equitable growth."
"The last thing we want to do is create an energy divide."
Watch Kann explain retail energy market disruption:
Three years after the Department of Energy issued its last loan guarantee to a renewable energy project, the program is officially back in action.
Ending a long hiatus, the DOE indicated in February that it would finally use the remaining $1.5 billion allocated by Congress for loans to clean energy project developers. Today, the department is announcing the first public step in that process: a solicitation for developers of battery storage, microgrids, efficiency and waste-to-energy projects that will "catalyze" the market.
"We are looking at how we get the same type of impact in other technologies like we did in solar," said Peter Davidson, the executive director of DOE's loan programs office, in an interview at Greentech Media's Solar Summit.
The total support could rise to $4 billion as DOE uses $2 billion in other available funds, plus hundreds of thousands of dollars in credit subsidies.
The projects will fall under the 1703 loan guarantee program, the original loan backstop vehicle set up under the 2005 Energy Policy Act and funded by the stimulus package in 2009. That is separate from DOE's sister loan program, 1705, which offered $16 billion in support to clean energy companies, 80 percent of them solar. Although the 1705 program has a 97 percent success rate, it's still best known for having backed failed solar companies Abound and Solyndra.
So far, 1703 has been used to support two large-scale nuclear plants. After a multi-year analysis of where remaining funds should be spent, Davidson's team is now looking to support projects on the opposite end of the spectrum that can help integrate nimble, distributed clean energy technologies on the grid.
"We're really interested in grid connectivity and integration," said Davidson.
A lot has changed since the department initially ramped up its loan guarantee offerings in 2009.
Starting in 2011, a handful of high-profile companies supported by the 1705 program and the Advanced Technology Vehicles Manufacturing program went bust, creating a political nightmare for the energy department. That caused a two-year frenzy among Republicans, who railed on the DOE for supposedly helping fund "losers" -- even though many of them had voted for the original program and asked for money themselves.
In March 2013, Ernest Moniz took the helm at the DOE. Davidson was brought on to manage the DOE's loan portfolio a couple of months later. Shortly after, his team announced $8 billion in funding for loan guarantees to support advanced fossil fuel projects through the 1703 program. (Interestingly, the same protests about the government "picking winners and losers" were not heard when DOE threw its support behind fossil fuels.)
The biggest change, said Davidson, has been outside of Washington. When DOE first considered recipients in 2009 and 2010, a boom in utility-scale solar was underway due to the rise in state-level renewable energy targets. Eyeing the opportunity, the department supported record-size solar PV, concentrating solar power and wind power plants that could get utility contracts for power.
In 2014, however, the needs in the energy market are different. Utilities aren't just looking to build big projects anymore. Rather, they're getting more interested in procuring the technologies that will help integrate those projects on the grid. Instead of renewable energy standards, storage procurement targets, demand-side management programs and "grid resiliency" initiatives are starting to drive the market.
That means grid-scale and distributed storage, advanced inverters and power conversion technologies, and microgrid projects are top of mind for DOE, said Davidson.
"New and exciting things are happening on the utility side," said Davidson. "We want to be involved in storage, hybrid fossil and renewable plants, microgrids -- anything that will have a catalytic role."
In other words, the grid edge.
The new solicitation is about much more than just grid balancing and distributed energy integration. DOE said it is willing to consider waste-to-energy technologies, biofuels, and unique approaches to energy efficiency. But figuring out better ways to enable distributed generation is a central focus.
The energy department will be taking public comments for the next 30 days, and the final solicitation will be in June.
To learn more about technologies enabling and transforming power generation and delivery at the grid edge, join Greentech Media at Grid Edge Live in San Diego on June 24-25.
Pulse Energy is similar to Opower in that it provides energy reports to utility customers based on analytics and behavioral psychology. Unlike Opower, it does not come from the residential market, but has always been squarely focused on the commercial sector. Its platform has tailored products for larger commercial clients, as well as small and medium-sized businesses.
The privately funded energy intelligence company has been around since 2007, but has mostly flown under the radar. Its North American clients include BC Hydro and Pacific Gas & Electric, as well as an unnamed client in Australia. (Pulse would not disclose its total number of utility clients.)
Pulse also develops dashboards for commercial clients, as well as a remote auditing product similar to those offered by Retroficiency, FirstFuel and WegoWise. But the firm has found momentum with its behavioral analytics product among utility customers.
“Our partnership with Pulse Energy will allow customers to see in real time where they are using the most energy and how they can increase their efficiency to save...money,” Stephen Beynon, managing director of British Gas Business, said in a statement. “Working with the Pulse Platform, we are able to identify the specific actions suited for each customer to help them to improve their energy productivity with minimal effort.”
The Pulse platform for large commercial clients is geared more toward the energy manager in the facility. It also comes with an interface for high-level insights that can be used for applications such as presentations in the C-suite or to show students in a school district how their energy efficiency projects are paying off.
BC Hydro offers Pulse analytics to its larger clients as part of its Continuous Optimization Program, which covers buildings of more than 50,000 square feet in size. The Canadian utility has a mandated demand-side efficiency target of 5,100 gigawatt-hours for 2014, according to Pulse Energy.
The software is also designed to notify building managers of the best approaches to plan, optimize and verify energy efficiency savings. “We don’t just train users on how to use the software; we train users on how to carry out energy management,” said Steve Jones, VP of product management at Pulse Energy.
For small commercial customers like the ones Pulse Energy works with through Pacific Gas & Electric, the approach is different. Those customers also receive reports on their energy use, but the interfaces are simpler and the messaging is tailored for their specific business. Pulse Energy supports more than 100 different verticals, differentiating between businesses such as dry cleaners and laundromats.
The competition for Pulse Energy is everywhere: remote auditing software companies, residential companies like Opower that want a slice of the small commercial pie, direct-to-business competitors like Noesis or EnerNOC, and big data analytics firms like C3.
Although the competition is stiff for Pulse Energy, utilities are increasingly looking for low-cost ways to engage commercial customers on efficiency. Pulse has products that touch the different areas where utilities are interested, from behavioral reports to deeper building analytics.
Pacific Gas & Electric is using Pulse Energy to specifically target small and medium-sized businesses. Because British Gas operates in a competitive environment, offering added value to small businesses is critical to attracting new customers.
British Gas is also one of the retailers on the forefront of installing mandated smart meters in the U.K., and some commercial customers will be looking for energy retailers who offer another layer of energy services that leverage smart meter data. “Having a mandated savings target is very powerful,” said Jones, “but so is customer need.”
California regulators have just issued a rebuke to utilities, and a thumbs-up to customers and companies that want to connect hundreds of now-stalled battery-backed solar PV projects across the state.
On Tuesday, the California Public Utilities Commission issued a proposed decision that would exempt most storage-solar projects from extra utility fees and interconnection studies (PDF). Instead, it would require utilities to treat them as regular old net-metered solar systems, as long as they meet certain requirements.
For the past twelve months or so, California’s big three investor-owned utilities -- Southern California Edison, Pacific Gas & Electric and San Diego Gas & Electric -- have been demanding these systems undergo extensive reviews that come with between $1,400 and $3,700 in extra fees. Utilities have said they need to do this for safety reasons, as well as to make sure that batteries don’t store grid power, then feed it back under the guise of green, net-metered power.
Solar and storage system installers say these unnecessary fees and studies have brought new battery-solar projects to a screeching halt, and slowed to a crawl grid interconnections for those that have been approved. SolarCity, for example, says that of the more than 500 customers that have signed up for its solar battery systems, only twelve have been connected to the grid.
Tuesday’s proposed decision makes it clear that CPUC agrees with SolarCity and its customers, not the utilities. “We disagree with IOUs’ conclusions and would have preferred that the IOUs had taken a more proactive and collaborative approach to avoid creating barriers,” it states. In an October assigned commissioners ruling, CPUC President Michael Peevey noted that more than 10 megawatts of solar-storage projects have been put on hold in the state because of the utilities' stance.
Indeed, storage and solar advocates have been anticipating a ruling that supports a more streamlined, no-cost solution. This proposed decision doesn’t give them everything they want, but it would certainly remove the main obstacles.
“I think it’s going to streamline it quite a bit. There were customers who weren’t able to pay these interconnection fees who we can now move forward,” Peter Rive, SolarCity co-founder and CTO, said in a Tuesday interview. UDPATE: Bloomberg reported Wednesday that SolarCity has resumed submitting applications for projects in light of the proposed decision.
SolarCity has been installing batteries from Tesla Motors in homes since 2010 as part of the California Solar Initiative program. In December it announced it was entering the commercial building market as well, competing with companies such as Stem, Green Charge Networks and Coda Energy to provide low-cost battery systems to mitigate demand charges.
But SolarCity CEO Lyndon Rive and his cousin, Tesla CEO Elon Musk, complained during a February CPUC workshop that the utilities’ blockade has pushed the average wait time for interconnections to eight months. Last month, SolarCity announced it would stop filing applications with these utilities until the impasse was broken -- a stance that could be re-examined if CPUC commissioners approve this proposed decision at their next meeting.
Peter Rive noted in Tuesday's interview that opening the grid to solar-storage systems should also give utilities, grid operators, individual customers and aggregators like SolarCity a chance to optimize their interactions with the grid at large.
“The idea of solar plus storage being something that removes a customer from the grid is counterproductive to us seeing those benefits,” he said. “I think a lot of utilities don't know which way to go. They see these benefits, but they say, 'How do I aggregate these customers, when it adds up to tens of megawatts, not just hundreds of kilowatts?' […] We can aggregate customers in large numbers and use them like a virtual power plant.”
CPUC’s proposed decision lays out certain limits for systems that are exempt from all fees, interconnection studies and distribution system upgrade cost triggers. First, the energy storage component would have to be smaller than the net metering-eligible generator it’s attached to -- usually solar panels, but potentially wind or other qualifying resources – when the system is larger than 10 kilowatts. For systems under that scale, no sizing limits are proposed.
That size threshold also applies for two different ways to meter the output of solar-storage systems. Under Tuesday’s proposal, systems larger than 10 kilowatts will require a separate meter for measuring the interplay of battery-charging and solar generation, although the CPUC does take SolarCity’s suggestion to cap that extra meter’s cost to no more than $500.
For systems less than 10 kilowatts in size, the proposal takes up a system suggested by solar-storage startup Sunverge, to use the local data acquisition system to measure energy drawn into the storage unit, then use that to “de-rate” the annual net metering credit for on-site generation. In other words, it calls for trusting the solar-storage system to measure its own give-and-take status against the grid.
Also, “Because storage systems continually consume some power to maintain system services, these systems should not be penalized for de minimis consumption. Therefore, customers shall receive 100% of annual NEM credits where the annual de-rate factor is 95% or higher,” the proposed decision states. That’s important to avoid degrading the value of net metering, which makes up a significant payback stream for rooftop solar in California.
“We’re very encouraged by the proposed decision having no application fees, and having the costs of the meters capped,” Rive said. Given that SolarCity already monitors each individual installation at the meter and at the inverter, “I don’t think a meter is necessary at all -- but we’re moving things forward,” he said.
Other companies, such as Sunverge and Outback Power, have also been filing briefs in support of the CPUC’s proposal to exempt simple solar-battery projects from high fees and complicated studies. California is already pushing forward with rules for integrating 1.3 gigawatts of energy storage into the state’s grid by 2020, and calls for customer-sited storage to make up a significant portion of that total.
Besides the storage mandate, California is also undergoing a rewriting of its net metering policies, which could open up possibilities for storage-backed solar systems to interact with grid needs in new ways. Rive noted that SolarCity has just launched a Grid Engineering Solutions department that is working on ways to share its aggregated solar-storage capabilities with utilities or grid operators like California ISO.
Long known for its boom-or-bust tendencies, the U.S. wind energy industry outdid itself in 2013. Capacity additions fell off a cliff, dropping more than 90 percent from 2012 and hitting their lowest level in a decade -- but by the end of the year, new projects were under construction at a record-breaking clip.
What comes next? As the American Wind Energy Association’s just-released 2013 annual market report makes clear, the industry is once again looking for “policy stability” -- which is to say, an extension of the production tax credit and its companion, the investment tax credit.
“The lows...tell as sobering a story as the highs tell a celebratory message,” AWEA CEO Tom Kiernan says in the report, which was provided to media on the condition it not be redistributed. “They convey a crystal-clear message: The PTC and ITC must be extended, and wind energy policy must be made stable.”
AWEA calls the PTC, valued at 2.3 cents per kilowatt-hour, “wind’s primary policy driver,” and the industry’s installation ups and downs track with its fickle fate.
Up: The looming expiration of the tax credit drove massive installations in 2012, a record 13,131 megawatts.
Down: That same circumstance left wind’s project pipeline empty entering 2013, explaining why just 1,087 megawatts of new capacity went on-line during the year.
Up: The one-year extension that Congress passed at the beginning of 2013 made the PTC available to projects merely under construction by the end of year (instead of in service), leading to a surge in new activity late in the year, which ended “with more than 12,000 megawatts across 100 wind projects in the process of getting built,” according to the report.
In an interview, AWEA senior policy analyst Emily Williams said the industry would love to work with Congress on a long-term policy solution. But with comprehensive tax reform appearing unlikely anytime soon, the immediate goal is to seek implementation of a retroactive two-year PTC extension, which was endorsed early this month by the Senate Finance Committee.
That, along with the declining cost of wind -- down 43 percent between 2008 and 2012, the industry says -- would likely ensure a robust next several years for wind energy.
As it is, Williams said the projects that qualified for the PTC in 2013 should lead to growth in installations this year and then again in 2015, “similar to what we saw in 2011,” when 6,820 megawatts came on-line.
The U.S. entered 2014 with 61,110 megawatts of wind energy, second to China’s 91,424 megawatts and ahead of Germany’s 34,250 megawatts. About 90 percent of the U.S. capacity was added in the past nine years, and AWEA notes in the new report that wind energy’s contribution to U.S. electrical generation rose from 0.3 percent in 2003 to 4.1 percent in 2013, according to U.S. Energy Information Administration data.
In the report, AWEA argues that all that wind energy is trimming carbon emissions by 95.6 million tons annually, equal to 4.4 percent of U.S. power sector emissions, “while avoiding the consumption of over 36 billion gallons of water each year.”
Distributed Sun’s just-launched prototype version of beEdison is an online tool designed to make it faster and easier for investors to find worthy solar projects and for developers to find interested investors.
The beEdison software allows project sellers to enter survey data covering some 600 points about proposed projects. The predictive and directive scoring, which incorporates a recommendation engine, helps developers learn the language of finance. Investors can study the resulting beEdison diligence report to focus on projects that suit their aims and to identify the information still needed to make investment decisions.
The beEdison diligence and risk tool was developed from Distributed Sun’s study of 700-plus project development deals totaling nearly $7 billion in value, as well as the DuPont-and Distributed Sun-driven truSolar industry-wide project risk assessment database.
With beEdison, the company is separating the software, data, and intellectual property on which its diligence and project underwriting services are based from its project development and owner-operator activities. It is funded with $2 million from Distributed Sun and unidentified new investors.
The goal is to get into a transaction services marketplace that Distributed Sun estimates will be worth over $600 million for U.S. non-residential solar by 2018.
“In every deal we do, we pay for all the deals we didn’t do or dropped,” explained Distributed Sun CEO Chase Weir. “We also pay the hidden costs for all the deals our counterparties didn’t do. We could have known which projects were not worth doing sooner if we were asking the right questions in the right way at the right time.”
Based on Distributed Sun’s in-house assessment of a 100-megawatt sample of projects, 70 percent of proposed transactions have “one or more fatal flaws that cost money to find and/or fix,” Weir said.
An NREL assessment of soft costs shows there are 63 cents per watt in transaction costs and margins burdened by sunk costs, Weir said. But if all the deal parties used beEdison, that could be cut by 7 cents per watt. “That would cut $115 million from projects to be placed in service in 2014. It could cut $200 million from all currently proposed projects in the development pipeline.”
BeEdison is being designed to provide the best possible online project due diligence. It is a “TurboTax” of project stress for developers and project originators, Weir said, and it automates the screening and stress-testing of deal elements for investors.
Because the software incorporates the industry-wide truSolar effort to accumulate data on project risk, the industry itself is the final voice of whether there is risk, Weir said.
Six users are participating in the prototype testing, including two developers, two investors, and two institutions that put money into solar but aren’t ready to change their diligence process. All are participating without cost under end-user license agreements.
The long-term revenue plan is based on the "freemium" business strategy. The open platform will be cost-free until the parties hit certain value points. “We are focused on the art and science of adoption,” Weir explained. The parties will pay “when the deal gets real and user benefit is plain. But we get out of the way and let the deal get done. We are less interested in processing lots of potential deals than in getting deals over the goal line," Weir said.
Unlike the Mercatus online digital deal room just endorsed by SolarCity, beEdison aims to be “the next-generation risk and diligence practice,” Weir said. He hopes to create an open, industry-driven scoring platform that is a training system for developers, and that increases deal transparency and lowers risk and cost for developers.
As indicated by recent SunShot awardees, the industry is hungry for financial technologies that cut the soft costs of deal-making, Weir said. Mercatus and truSolar, as well as Richard Matsui’s kWh Analytics, are “educating the marketplace that we need better tools to evaluate project risk.”
A Power User version of beEdison will come this summer. Weir expects it to have a dozen users. An Enterprise version is scheduled for release this fall.
With new money coming in and the solar market reaching a higher level of maturity, Weir said, “people who want high-volume asset financing or selling will need financial technologies to help them more efficiently decide if a project is worth doing.”
If you work in the solar industry and are having some difficulty reaching your colleagues, it's probably because a good portion of them are here in Phoenix at GTM's Solar Summit, taking in the sun as well as the deep flow of information at this event.
Shayle Kann, GTM's SVP of Research, kicked off this industry summit with a new, insightful take on solar's impact on energy markets.How to disrupt a wholesale energy market
According to Kann, "solar is not a disruptive technology." He suggested that what makes solar disruptive to the market is how it is financed, structured and priced.
And wholesale disruption is "a reality today in Germany."
Europe has installed 85 gigawatts of solar, 40 gigawatts in Germany alone. And relative to the size of the total German market, 40 gigawatts is a lot of solar, said Kann.
Most of this solar is on the utility side of the meter, feeding into the wholesale side. And as a result, wholesale prices have fallen a lot more than expected.
If you are an operator of a fossil fuel plant that does have some marginal operating costs, "then this is no good for you," Kann said.
Gross margins are now negative in many natural gas plants in Germany, most of which are owned by big European utilities. In fact, in 2013 alone, Europe mothballed 20 gigawatts of natural gas plants and wrote down $23 billion in generating assets, "a financial pain they have never felt before."
Kann showed the tumbling share prices of the big EU utilities such as EDF, GDZ Suez, ENEL, E.ON and RWE, which has openly stated that it needs to change its business model in order to compete.
If you're talking about the changing shape of energy, CAISO's Duck Chart must be displayed. It's the law.
Kann flashed the Duck Chart, created by California's independent system operator, to show net load on a theoretical spring day with no air conditioning load and a lot of sun.
It illustrates that in the years ahead, as more wind and solar is added to the system, the duck's belly sags and fast-ramping capabilities become critically important. The CAISO solution is to do things as they always have: add more fast-ramping natural gas.
Kann suggests that it is "better to flatten the duck" with demand-response pricing signals plus energy storage.
Kann noted that wind power is a contributor to this curve and that utilities have over-invested in natural gas assets.
He acknowledged that Germany's grid situation is not the same as that in the U.S., which simply doesn't have as many renewable resources on-line relative to load.
But the amount of solar on the grid in California is starting to impact the generation profile.
In March, wholesale spot prices went negative for about an hour due to higher generation from PV and wind.
Forget theoretical ducks, Kann said: the actual CAISO load shape for March 18, 2014 is "already looking pretty duckish."
According to Kann, "This is a good kind of wholesale disruption."
Watch Kann explain what makes solar disruptive:
And join us at our next event in June in San Diego, Grid Edge Live.
If more than 30,000 commercial buildings in New York City adjusted their thermostats just one degree upward in summer and one degree lower in winter, the savings would add up to $145 million dollars annually.
That finding is just one of the insights gleaned from Retroficiency’s new Building Genome project, which leverages publicly available data to take a high-level look at what is possible over very large portfolios -- including the entire building stock of New York City, which was the first target for the project.
“Even with just publicly available data, there’s a level of insight we believe you can get to,” said Mike Kaplan, vice president of marketing at Retroficiency.
When it comes to energy efficiency, scale and speed are the factors on everyone’s mind. Even though there are various firms offering software-based approaches to identify savings and retrofit opportunities, scale continues to be a problem. The Building Genome project, which will soon be expanded to other cities, is meant to provide policymakers, utilities and large ESCOs with a snapshot of what is possible using the startup’s analytics.
Retroficiency started with tax assessor and consumption data, Energy Star scores and energy-use intensity scores that are publicly available thanks to New York City’s energy benchmarking disclosure rules. The genome takes specific “markers” such as lighting, HVAC and envelope characteristics of buildings.
For New York, the analysis included oil boilers, which must phase out dirty No. 6 heating oil by next year.
The data is then aligned and processed using Retroficiency’s energy modeling software that includes information from past audits of similar buildings and weather data to model energy savings under different scenarios.
The project is not meant to inform one-off undertakings, but rather to “show opportunities on a mass scale,” said Bennett Fisher, CEO and co-founder of Retroficiency. Although the software-driven approach is gaining traction, “it’s still cutting-edge and disruptive for policymakers and utilities,” he said.
The project is both a thought experiment and a sales tool. Retroficiency is taking suggestions about which cities to tackle next, although cities that already have public disclosure rules are obvious choices. Bennett said the company is planning on mapping several more cities this year.
Once the mapping is done, clients can examine specific scenarios, such as where to target window retrofits. Retroficiency found that in New York City, the top 35 ZIP codes by savings potential could save triple the energy when compared to the ZIP codes with the lowest savings potential.
Most of the ZIP codes with the highest savings potential stemming from window retrofits are located in Manhattan, where glass-sided skyscrapers abound. The information is just a starting point, and the next step would be for customers to then add in their own data to yield more specific insights.
“You start by including every building in the portfolio and then dealing with the pain points for different situations,” said Fisher.
Earlier this year, Retroficiency partnered with a company that focuses on multifamily energy efficiency programs and recently announced it is working with Consolidated Edison in New York City. Utilities are a particular focus for Retroficiency and competitors like FirstFuel, because utilities are looking for low-cost ways to identify efficiency opportunities and verify savings now that some of the lowest-hanging fruit for retrofits has already been plucked.
Xtreme Power, the well-funded grid battery startup whose ambitions flamed out in bankruptcy this January, has a new owner. On Tuesday, the Lyle, Texas-based startup’s assets were acquired by Younicos, a Berlin-based grid battery and energy management startup.
Terms of the deal weren’t disclosed, but Xtreme creditor and “stalking horse” bankruptcy bidder Horizon Technology Finance announced Monday that it received $9.9 million in cash for its share of the bankrupt company. Horizon had previously committed to outbid any offers under $10 million, which appears to indicate that larger bids hadn’t emerged.
That’s bad news for Xtreme’s investors, of course. Since its 2004 founding, Xtreme has raised about $55.7 million from investors including SAIL Capital Partners, Bessemer Venture Partners, The Dow Chemical Company, Fluor Corp., BP Alternative Energy, Dominion Resources, POSCO ICT, Skylake & Co. and Spring Ventures. But Xtreme had only $34,000 in cash and $10 million in debt when it filed for Chapter 11 bankruptcy protection in the U.S. Bankruptcy Court for the Western District of Texas.
But it’s a good deal for Younicos. The startup, founded in 2006 by executives at German solar manufacturer Solon, has about 10 megawatts of projects in the ground or being built, and is developing about 10 megawatts more across Europe.
It's small compared to Xtreme, which has 60 megawatts of grid-scale battery storage up and running in twelve projects around the world. Xtreme CEO Alan Gotcher stated in January that the startup’s pipeline of business was in excess of $100 million, with letters of intent for another $65 million on top of that.
But whether Xtreme’s current roster will equate to future business is less clear, on several fronts. The first is the future of Xtreme’s “PowerCell” advanced lead-acid battery chemistry itself. Xtreme put its factory up for sale in April 2013, but hadn’t found a buyer as of its January bankruptcy.
Xtreme hasn’t disclosed prices or costs for its battery technology, so it’s hard to say how competitive it was against established grid-scale battery manufacturers like Panasonic, Mitsubishi, LG Chem, Samsung, and Saft. It does have significant projects in the ground, including the U.S.’s largest, a 36-megawatt, 24-megawatt-hour system sited at Duke Energy’s Notrees, Texas wind farm.
But Xtreme has also seen confidence in its product drop since a 2012 fire that destroyed its 15-megawatt energy storage facility in Hawaii. Its most recent projects use lithium-ion batteries from the aforementioned OEMs, not its own chemistry. The track record of companies competing against these giants on mass manufacturing batteries isn’t good, as highlighted by the bankruptcies of A123 Systems, Ener1, Exide and International Battery.
That appears to leave Xtreme’s battery management system (BMS) -- the hardware, software and services to keep grid-scale battery units running smoothly and optimizing their money-making capabilities -- as its primary asset. BMS platforms are valuable, and a host of startups are focusing on them as a software-based, startup-friendly way to get into energy storage.
But real-world expertise is also worth a lot. Consider A123 Energy Storage, the grid-scale portion of bankrupt U.S. lithium-ion battery manufacturer A123 Systems, which was sold by Chinese owner Wanxiang to Japan’s NEC last month.
Younicos doesn’t make its own batteries, but has put its software to use controlling sodium-sulfur batteries for projects in Berlin and on the island of Graciosa in the Azores, and lithium-ion batteries in England. It also has investors from the battery world, including Samsung for lithium-ion batteries, and Germany’s Gildemeister, maker of a vanadium-redox flow battery called the CellCube that provides multiple hours of storage for wind or solar power shifting.
GTM Research solar experts Adam James and Scott Moskowitz delve into global solar demand every day in excruciating detail.
We'll be checking in with them periodically to see what's on their solar-obsessed minds and reading lists. Our previous Global Solar Note covered the trouble brewing in India's Solar Mission Program and the U.K.'s huge first quarter.
Here are four recent stories that have caught the attention of the analysts.EU drops solar Chinese solar module volume cap and price floor
The European Union's 2014 volume cap on Chinese PV modules dropped from 7 gigawatts to 5.8 gigawatts, and the price floor was lowered from €0.56 per watt to €0.53 per watt. Despite some gains in the U.K., the EU is seeing weak demand and lower average module prices. GTM Research's James notes that China's Trina and Yingli have both revised their shipment forecasts down. Yingli, the world's largest solar-panel maker, "expects first-quarter shipments to have slumped by at least 30 percent from the previous three months," according to Bloomberg.
The bottom line is that demand is soft in the EU. The GTM Research analysts cautioned that Germany was on pace to hit a relatively modest 2 gigawatts in 2014, a low point in recent demand.
James believes that the move by the EU to dial-in the price floor and volume cap is an effort to stoke regional demand.
For more on PV pricing trends see the PV pulse.Germany, the U.K. and the difficult transition from a subsidy-laden market
While the European Commission is pushing for market-based policies as incentives decline, "Germany isn't taking heed," according to the analysts. Instead, the country is passing a restrictive self-consumption tax that is being challenged in court.
The U.K. took a different approach, introducing a market-based contracts-for-difference scheme that will begin later this year with a contract price of £120 per megawatt-hour -- almost double the current FIT levels. This is essentially a "government-procured synthetic PPA," that should spur demand.
For more on trends in global demand, see GTM's strategic consulting services.China's distributed solar market heating up
China will continue to be the world's largest solar market in 2014, with demand driven by massive utility-scale build-out. But China also has sizable distributed generation targets in place, which have been greeted with skepticism in some quarters.
The bottom line according to the analysts is, "We will see a DG market in China with new players that may not have had a share in a utility-dominated market."
Clenergy recently announced a JV for 150 megawatts in Fujian (2014 DG target of 300 megawatts); Jun Yang Solar raised $25 million for projects in Jiangsu (2014 DG target of 1 gigawatt) and Zhejiang (2014 DG target of 1 gigawatt); and Hanwha SolarOne is looking to develop 100 megawatts in eastern China.
Although ambitious 8-gigawatt DG targets will not be met, the analysts expect the China DG segment to attract a lot of interest and to witness the emergence of new and up-and-coming vendors.Turkey solar recipe
After some false starts, the PV market in Turkey "is finally getting started," according to the GTM analysts. CSUN has signed a supply agreement for a 15-megawatt system, and Sungrow has supplied 2 megawatts of photovoltaic systems spread out over four projects, which the analysts describe as "the first concrete signs of movement in this emerging market."
James notes that Turkey's feed-in tariff was "massively oversubscribed" and applications had to be sorted out -- but the market is real and finally starting to gain traction.
Right now, industry accounts for around one-third of the world’s energy use -- more than any other end-use sector of the economy.
Additionally, industrial energy demand is projected to increase by as much as 44 percent over the next twenty years, particularly in emerging and developing countries. This, of course, means there will be an unprecedented increase in the greenhouse gas emissions that are associated with climate change.
To avert this course, we will need to cut our annual global energy use by a quarter by 2020. It will take a major shift toward energy efficiency and smarter resource use to ensure industry plays its part by becoming more efficient and productive.
The good news is that we already have much of the know-how in place to stimulate this level of change. Here are the eight exemplary initiatives I believe can fundamentally alter the way industry uses energy and, ultimately, how our global economy functions.
1. Policies and programs
Governments play a vital role in driving industry to adopt energy-saving and low-carbon practices. Most countries now have some kind of energy efficiency policy in place, and efforts are also ramping up in many developing countries that have large, energy-intensive industry sectors.
China is one of the countries leading in the policy arena with the industrial energy-efficiency initiatives in its Twelfth Five-Year Plan, which targets the country’s approximately 15,000 enterprises that consume more than 10,000 tons of coal equivalent (tce) per year.
This program builds on the successful “Top-1,000 Program,” which focused on the country’s top 1,000 energy-consuming enterprises. As a result of this initiative, China cut its energy intensity (energy use per unit GDP) by almost 20 percent between 2006 and 2010 -- primarily through energy efficiency upgrades and by closing obsolete facilities. It is now aiming to cut energy intensity by a further 16 percent by 2015.
In India, the Perform Achieve Trade (PAT) energy efficiency trading scheme has been developed to reduce industrial energy consumption through market-based mechanisms. Conceived in 2008, it is expected to contribute to savings of 6.6 million tons of oil equivalent in its first phase (2012-2015). This is comparable to the amount produced by 40 new coal-fired power plants over their lifetime.
Back in the United States, the Executive Order issued in 2012 will help meet the national goal of deploying 40 gigawatts of new, cost-effective industrial combined heat and power (CHP) by the end of 2020. CHP involves recovering the heat normally lost in power generation and using it to provide useful thermal energy to businesses and factories. If achieved, this goal will help generate as much electricity as 80 coal-fired plants can produce over their entire lifetime.
Many U.S. states also have energy efficiency resource standards that lay the foundation for industrial energy-efficiency programs funded by the public or by electric and gas ratepayers.
Many of the well-established, ratepayer-funded industrial energy-efficiency programs in North America -- those from Bonneville Power Authority, BC Hydro, the Energy Trust of Oregon or Wisconsin’s Focus on Energy -- have delivered reliable energy savings from industry at below the average costs they face for their programs overall. To realize increased low-cost energy savings in industry, however, will require a concerted effort developed specifically for each sector.
2. Energy management systems
Having an energy management system in place is one of the single most important factors in reducing the energy use of industrial operations in enterprises. As the term suggests, an EMS equips companies with certifiable practices and procedures that help them continuously improve their energy efficiency.
The benefit to companies is that it helps reduce energy costs, increases operational efficiency and productivity, and improves risk management. One recent study by the Lawrence Berkeley National Laboratory showed that the cost of developing and implementing an EMS to world standards was, on average, paid back in less than two years through energy savings.
The increasing uptake of ISO 50001 -- an international environmental management standard focused on energy use and performance -- demonstrates that energy management is becoming part and parcel of industrial operations around the world. Since the standard was launched in 2011 by the International Standardization Organization, there has been a tremendous leap in the number of industrial sites that are ISO-certified, increasing from about 90 two years ago to about 8,000 today.
Germany alone accounts for around 3,000 ISO-certified sites, largely due to voluntary agreements between the German government and industrial firms that encourage companies to cut energy use in return for a tax rebate. Other governments have also been successful in encouraging corporate adoption of EMS: Sweden, Ireland and Denmark, among others, have had longstanding negotiated agreements with industrial companies to provide technical support and financial incentives in return for energy savings and EMS implementation.
3. Transparency and disclosure
Another trend that is gaining momentum is carbon disclosure. Companies that measure their environmental risk are better able to manage it strategically. And those that are transparent and disclose this information are providing investors and other decision-makers with access to a critical source of global data that delivers the evidence and insight required to drive action. Thousands of companies around the world, from medium-sized enterprises to large publicly quoted corporation, are realizing the benefits of this process.
In China, new rules that signal a move toward greater transparency have just come into effect. They require 15,000 enterprises, including some of the biggest state-owned companies, to publish information about their air pollution, wastewater and heavy metal discharges.
In India, the Companies Act 2013 mandates that companies spend 2 percent of their profits on CSR initiatives and to publish related reports. Estimates suggest that if all companies that fall under the jurisdiction of the Act are to fully comply with the mandate, the CSR capital generated would amount to nearly INR 20,000 crore (USD 3.2 billion).
The not-for-profit organization Carbon Disclosure Project (CDP) works with 3,000 of the world’s biggest companies to measure and disclose environmental information. Members include BMW, Daimler, Phillips Electronics, Nestle, BNY Mellon, Cisco Systems, Gas Natural SDG, Honda Motor, Nissan Motor, Volkswagen, Hewlett-Packard and Samsung.
4. Putting a price on carbon
Many major companies now consider the price of carbon as a core element of their business strategy. Carbon pricing has increasingly become a valuable tool, as it helps companies identify and implement high-impact energy efficiency projects, and improves the paybacks and IRRs of measures such as CHP, the switch to low carbon fuels, and the use of newer process technologies that use less energy. Companies now pricing carbon include Exxon, Wal-Mart, American Electric Power, Microsoft, General Electric, Walt Disney, ConAgra Foods, Wells Fargo, DuPont, Duke Energy, Google and Delta Air Lines.
While the future of carbon pricing regulation is still uncertain, at least 29 major companies around the world have incorporated a carbon price into their long-term financial plans.
With energy prices rising in many parts of the world, energy efficiency is seen as a means to save money. Benchmarking helps firms to assess what savings they can make by looking at the efforts of others, how much they have saved, and at what cost. A few industry sectors -- notably, petroleum refiners and cement producers -- already benchmark their energy efficiency performance successfully. But for the broader industry, this is an area that needs further development.
A UNIDO analysis on benchmarking shows energy efficiency could reduce global energy use by 26 percent, with a 15 percent to 20 percent potential improvement in industrialized countries and 30 percent to 35 percent in developing countries and economies in transition. The potential savings vary sector by sector, with energy-intensive processes and sectors having the potential to save even more than average. Most light industry processes show higher improvement potentials at an individual plant-level, but do not consume nearly as much as heavy industry.
6. Supply chains
The value of using supply chains to drive change cannot be underestimated. Around 40 percent to 60 percent of a manufacturing company’s carbon footprint comes from its supply chain, but this number can be as high as 80 percent. These numbers could be significantly reduced through better cooperation on energy efficiency practices and strategies between companies and their supply chains.
The Institute for Industrial Productivity is working with CDP on a new initiative called Action Exchange, which will help this seed take root in the supply chains of some of the world’s biggest companies, including Bank of America, L’Oreal, PepsiCo, Philips, Vodafone and Wal-Mart.
Supply chains are often opaque and complex; one multinational company can have hundreds of suppliers around the world. Creating transparency and targeted information through Action Exchange will open the door to emissions reduction strategies that governments have so far struggled to tap into. If successful, the thousands of companies that disclose to CDP will be able to access information on energy efficiency opportunities and purchasing clean technology and services, as well as to share the experiences gained from the program.
Unlike the advances we’ve seen in IT in recent years, the basic processes used by industry are decades old. In fertilizer production, for example, ammonia is still converted using the Haber process, a technique that was first used on an industrial scale in 1913 in BASF's Oppau plant in Germany. Although the energy intensity of ammonia production has decreased substantially over the years, it remains the most energy-intensive and high-product-volume chemical process.
In recent research efforts conducted by companies and universities, the emphasis has been on reducing our carbon footprint by designing products with reusable parts that can be integrated into the next version of that product. This idea of a circular economy promotes the use of less precious resources and greatly reduces the embodied energy used in the making of each product, because each part or product has a much longer lifecycle.
We’re now seeing how the concept can work through the efforts of companies like Ricoh and Renault. Ricoh’s Greenline computers are leased out, then refurbished and upgraded at the end of each contract -- and then leased out again. Renault makes some of its car parts so that they can be reused in new models, literally giving them a new life. If this approach is applied on a greater scale, we would see a significant shift away from how the world produces and disposes of waste.
Financing remains one of the major challenges in accelerating industrial energy efficiency. Current investment is well below the economic potential, mostly because energy efficiency programs aren’t yet well understood by banks and financiers. Drawing on the work from the European Bank for Reconstruction and Development (EBRD), other financial institutions can take important steps to scale up their investment, while simultaneously increasing their revenues, building a positive brand, and satisfying regulators and other government agencies that they are committed to addressing climate change.
EBRD launched its Sustainable Energy Initiative (SEI) in 2006 and, by 2013, cumulative SEI investment reached $17 billion for 756 projects, of which $14.4 billion is related to energy efficiency projects. Moreover, SEI investment accounted for 28 percent of total EBRD investment in 2013, demonstrating just how bankable energy efficiency projects can be. Cumulative carbon emission reduction from these energy efficiency projects is estimated at 54 million tons per year.
The practical experience of the EBRD is that energy audits are a key instrument to drive energy-efficiency financing addressing important barriers.
The eight exemplary initiatives listed above, together with a new era of smart power and a grid powered by a much higher share of renewable and distributed energy systems, could accelerate the transition to a low-carbon economy. It is time industry moves away from its association with smokestacks and toward smart manufacturing based on productivity, sustainability and efficiency.
Jigar V. Shah is Executive Director of the Institute for Industrial Productivity, an independent nonprofit organization whose role is to accelerate the uptake of energy efficiency practices amongst industry. IIP is the only global organization solely dedicated to helping reduce industrial energy use to mitigate climate change and address other relevant environmental issues.
Minnesota’s new value of solar law appears to contain a major loophole.
The law creates a methodology for utilities to calculate a rate for customer-generated solar power, based on avoided infrastructure, pollution and other costs.
However, the value of solar rate is voluntary. Utilities have the option of paying the new rate or continuing with the existing net metering policy, which compensates customers with small arrays at the retail rate.
The issue -- whether customers or utilities should be able to make that choice -- was a bone of contention during the extensive stakeholder process to develop the policy, and remains so today.
In testimony to the Public Utilities Commission, Xcel Energy, Minnesota’s largest utility, estimated a value-of-solar rate of 14.5 cents per kilowatt-hour. Meanwhile, Xcel’s residential retail rate is 11.5 cents per kilowatt-hour.
So if the value-of-solar rate is higher than the retail rate, will utilities actually adopt it?
The answer, most likely, is yes, according to a new analysis released by the Institute for Local Self-Reliance.Kilowatt-hours vs. dollars
John Farrell, who authored the report, says the key is to look at the different ways the policies are structured.
Under Minnesota’s net metering policy, solar power is treated essentially as an efficiency resource. The kilowatt-hours customers generate are subtracted from the kilowatt-hours they consume, and the customer is billed for the remainder. If the customer produces more power than needed, the utility pays the customer at the retail rate.
Value of solar, however, treats the solar panels like a small power plant. The utility enters a 25-year contract with the customer at the value-of-solar rate, which is determined according to a methodology developed by the state Department of Commerce. The dollars earned by customers through that contract are then credited toward their utility bills.
That means, according to Farrell, that the higher value-of-solar rate is actually a better long-term deal for the utility, because the price is locked in.
Farrell says that’s also better for customers, because the contract provides certainty that will serve to decrease financing costs.
Meanwhile, “the transparency of the market price means no concerns about cross-subsidies between solar customers and non-solar customers.” In other words, ratepayers can be assured that they aren’t paying a larger portion of fixed utility costs than are solar customers.
“In theory, everyone is a winner if utilities adopt Minnesota’s market value of solar,” Farrell writes.The long-term outlook
Not everyone is convinced, however.
In a recent Huffington Post column, Anne Smart of the Alliance for Solar says utilities will eventually find ways to push the value-of-solar rate to below the retail rate, setting up “an immediate bust following the utilities’ recalculation of the tariff.”
Farrell agrees that value-of-solar rates will eventually fall below retail rates, “but that’s as likely to happen because of rapid increases in retail rates as from any changes to [value-of-solar rules].”
And if those rates rise, there’s no guarantee utilities won’t push for legislation to end net metering policies, which is already happening in several other states.
Also, the value of solar rate is pegged to avoided costs -- new power plants, fuel costs, transmission costs, and carbon emissions -- which are all tending to become more expensive over time. Meanwhile, solar panel costs have been falling significantly.
So under current trends, solar power should continue to be economical. And not tying the price to the retail rate is a better deal for ratepayers, helping build support for new solar, Farrell argues.
“As the spread between the retail rate and the actual cost of solar energy grows, ratepayers start to have very strong preferences for solar acquired under PPAs or other negotiated agreements rather than net metering, because it will be much cheaper power,” says Farrell.
Farrell says it’s too soon to determine whether the value of solar policy will work, but how utilities implement it will have a lot to do with it.
“[The] ultimate success lies in whether electric utilities can be convinced that accommodation of customer-owned power generation is in their best interest, or whether any concession of their market share is a deadly threat to their economic livelihood.”
After scooping up demand response companies in Ireland and Germany in February, EnerNOC has bagged its third company this year to bolster energy management offerings.
EnerNOC purchased EnTech USB, a global utility bill management software firm that started in the U.K. to serve the growing deregulated energy marketplace. The company has expanded worldwide to more than 100 countries and counts eight of the Fortune 50 as clients.
The software, which supports more than 200,000 utility tariffs, will be integrated into EnerNOC’s energy intelligence software to provide more detailed information on forecasting energy costs. For some potential clients, simply helping them break down utility bills is an important first step, before jumping deeper into energy efficiency projects. Utility billing information can also help potential and existing clients evaluate economic demand response opportunities.
"EnTech has impressive global reach. Its software product is the global UBM [utility bill management] solution of over 50 enterprises. Eight of the Fortune 50, including the largest companies in the world in telecommunications, consumer products, banking and auto manufacturing rely on EnTech's UBM software," Tim Healy, Chairman and CEO of EnerNOC, said in a statement.
EnerNOC has primarily been expanding overseas with its demand response offering. But EnerNOC co-founder David Brewster recently told Greentech Media that in Germany, one of its largest potential international markets, the company expects to expand into efficiency. About 20 percent of EnerNOC’s revenues came from outside North America in 2013.
Demand response still makes up the bulk of EnerNOC’s revenue, but the company has been slowly diversifying for the past few years into energy efficiency software.
“In addition to accelerating and streamlining data collection, the combination of monthly bill data with real-time energy consumption data greatly improves an organization's ability to effectively manage energy," Oliver Dawson, CEO of EnTech, said in a statement.
Some financial analysts agreed that the acquisition would strengthen EnerNOC’s ability to increase recurring revenue outside of demand response. “We believe EnTech’s utility bill management capabilities are a strong compliment to ENOC’s product suite and should improve ENOC’s cross-selling abilities,” said Baird Equity researchers. Not only will the acquisition strengthen EnerNOC's offering in a crowded energy efficiency software market, but it could also offer another entry point into international markets.
EnTech has about $10 million annual revenue and offices in eight countries. The acquisition is expected to close this month.
Figuring out how often to wash solar panels is more complicated than it might seem. Washing arrays too often can be a waste of money; washing them too infrequently results in soiled modules that reduce electricity production, and thus, the value of the project.
Operators typically follow a simple, low-risk policy of washing once a year just before the summer “money maker” month. It's usually a rigid schedule that project owners don't stray from, regardless of actual soiling levels. That's according to a new white paper by David Young, the vice president of asset management at Solarrus Corporation, entitled "To Wash or Not to Wash?" Solarrus is a service company for solar projects and electric-vehicle charging stations.
In the white paper, Young attempts to take the guesswork out of cleaning by using a mathematical formula to determine the optimal washing frequency. By using the formula and adhering to a mathematically calculated wash cycle, Young believes operators can expect hundreds of thousands of dollars in extra revenue. That could mean cleaning panels every twenty to 40 days during certain periods of the year.
In order to get a handle on this complicated problem which is influenced by unpredictable factors like weather, varying levels of soiling and seasonal revenue rates, Young starts out by setting forth a number of basic assumptions:
Under these assumptions, it is easy to describe the problem as a function of the following variables:
W: The cost of washing in dollars.
M: The maximum revenue production increase just after washing in dollars per day.
r: The rate of revenue lost due to soiling in dollars per day.
T: The time between washes in days.
As a graphic, the function looks like this:
To calculate the number of days between washings and maximize production revenues, Young came up with this formula: T = √ 2W/r
To test his formula, Young used data from a 20-megawatt plant in the Central Valley of California. With one wash costing $60,000 (= W) and the daily production revenue loss due to soiling in summer being (r =) $240/day, the optimal washing frequency is twenty-two days.
The tricky part of this calculation is to determine the correct 'r' value. A constant rate of revenue loss due to soiling over long periods of time does seem unrealistic, Young concedes. System performance is instead impacted by the physical rate of soiling, the revenue rate being earned for each kilowatt-hour generated, and the irradiance each day. It might be next to impossible to account for these factors in some regions, Young concludes. However, although they vary widely throughout a year, these factors do occur in fairly predictable seasonal patterns.
To make his calculation more realistic, Young changed the 'r' values for three different seasons: March to May, June to September, and October to November. Between December and February, it usually rains often enough in California to make module washing unnecessary. With this assumption, the graphic shown above becomes this:
While this model now accounts for the seasonal patterns for the plant in Central Valley, the 'r' value for each period still needs to be calculated. According to Young, the most reliable method is to set up a control array on site that is washed frequently, often weekly in times of heavy soiling rates. Solarrus also installed an array that matched the control array but was not cleaned at all. Young then compared the rate of change in the different output rates between the control array and the matching array and translated it to revenue.
Finally, Young calculated the lost revenue for a period between June through September, taking into account that the operator of the plant budgeted only one wash at the beginning of the summer season. The formula showed that the modules should have been washed three times in a 102-day period, which, according to Young's calculations, would have netted the operator $203,624.
The following table compares the two scenarios:
Although the results reflect only one set of circumstances for one solar power plant over a period of just 102 days, Young's approach may take some of the guesswork out of the decision to wash modules of solar power plants.
The long-promised goal of embedding open, flexible computing power in all types of smart grid devices is starting to be realized in 2014.
Open platforms from Silver Spring Networks, Cisco, Itron and other grid vendors are being introduced. Multi-vendor partnerships driven by utilities like Duke Energy and Toronto Hydro are creating new ways for smart meters, solar PV and battery inverters, distribution grid gear and other equipment to interact on the grid edge.
Open computing platforms like Linux, Android and Java are at the foundations of many of these efforts. Oracle, the database giant with a significant stake in smart grid technology, just happens to own Java developer Sun Microsystems. Embedded Java -- the version designed for mobile or remote computing platforms -- is now part of billions of SIM cards and mobile handsets, millions of TV devices (including every Blu-ray player), and other networked machines from office equipment to cars.
So it makes sense that smart grid devices are next on Oracle’s Embedded Java roadmap. In fact, they’re already out there today, in test beds like San Diego Gas & Electric’s Borrego Springs microgrid project (PDF), a showcase for Oracle’s grid management software to tackle a range of grid edge challenges.
“We’ve built prototypes for Borrego Springs, and demonstrated that,” Brad Williams, vice president at Oracle Utilities, said in an interview last week. “Certainly this is a key investment area for us. The main point is that Oracle embraces these distributed architecture concepts, and supports them through our core applications.”
For Oracle, those core applications range from its customer relations, billing and meter data management software used by a hefty roster of utility customers, to its network management system. That's Oracle’s version of an advanced distribution management system (ADMS), which is the central platform at Borrego Springs.
As for the equipment that’s getting embedded with Java, “we are working with our customers to do that with meters, head-end systems, home area network devices,” said Williams. “But our intent is to take this further into substation automation, switchgear, manufacturers like S&C Electric, Schweitzer Engineering Laboratories,” he said. Oracle has had some initial discussions with them, though it hasn’t announced any official partners yet.
Of course, this work is still in the “visionary” phase, Williams noted -- as are the rest of the distributed intelligence grid projects underway around the world. It takes some convincing to get grid equipment vendors to open up their systems, and even for heavy utility trendsetters like Duke, it’s still being done as an experiment. If those experiments prove fruitful, vendors are going to have to make some important changes to their device hardware, starting from the chipsets on up.
“The way we work with the ecosystem is [we] go back to system-on-a-chip [firms] like Freescale and Qualcomm to increase their portfolio of equipment for Java,” said Simon Nicholson, senior director of product management for Oracle’s Java team. “We also work with the OEMs, the major meter manufacturers.”
Take the example of Oracle’s work in Latin America, where it’s partnering with Dutch data security company Gemalto and Brazilian metering company V2COM to embed Java in smart meters and connect them with its MDM software. Oracle, which owns smart meter data analytics company DataRaker, is working on several distributed applications to run across the strongbox-secured meters that Latin American utilities use to prevent meter tampering, he said. One obvious application is non-technical loss (i.e., theft) detection, Nicholson noted -- “There’s tremendous commercial value there.”Why the grid edge needs distributed intelligence
As with many other embedded intelligence efforts, one of the key issues Oracle hopes to solve is managing the massive amounts of data being generated by smart devices on the edge of the network, Nicholson said. “If you can start driving decision-making to the edge, or locally, you can enable faster turnarounds,” Nicholson said.
But there’s also the possibility of embedding applications in the devices themselves, he added. “Because the Java at the edge is the same as the Java at the data center, that makes integration from the back end much easier. […] They can potentially move application logic out into the neighborhood,” he said. “We’re already seeing engagements now, and deployments in some cases, where Java is enabling the intelligence platform on the edge.”
In the meantime, safety and security are critical utility concerns. “Particularly when we’re talking about grid operations, utilities cannot have these distributed processes doing things that could create safety concerns," Williams said. That makes back-office applications, like Oracle’s network management system (NMS) in Borrego Springs, the "overarching authority to the distributed intelligence."
“We are the database of record for the real-time model configuration,” he said. “If we dispatch a crew to work on that line, we’ll tag that out, lock that out, and synchronize the devices that are tagged and locked out with distributed processes.” That’s something that the most sophisticated ADMSs are only beginning to take on in field operations.
Security is another part of that local-plus-central coordination. “We want to make sure our devices have the security to authenticate [that the information] is coming from a valid application, a valid location, before it will allow that change to happen.” Open systems are obviously open to intrusion and attack by bad actors, but the history of open standards in the IT world have proven that they end up improving security in the long run -- something that’s gotten lots of attention in the smart grid space lately.
As for which applications utilities are asking for, “the big ones that we know our customers are wanting today are around meter device management, firmware updates, configuration management, those types of things,” he said. “We have the back-office applications that already support that through the proprietary meter head-ends, and we’re working to try to make these more standards based."
This kind of IT threading through whatever proprietary or partly closed, partly open systems utilities have already installed is a challenge. But it’s also critical to make sure the central-control-to-device platform being built can really do what Java allows internet-networked computers to do: open up secure, yet reliable, channels for multiple applications to coexist.
For example, if properly set up, “any of the applications can go do a meter ping, and it’s routed through the actual proper device,” Williams said -- something that’s surprisingly hard to set up using today’s convoluted set of enterprise-to-operations-to-devices IT architectures. More standardization could make smart-meter-based analytics and automation much cheaper and simpler to implement, and help boost the still low number of utilities fully engaged in managing the smart meter data they already have, according to Oracle’s surveys on the topic.
Beyond that, a world of grid edge applications opens up, including the gamut of solar sensing and forecasting, smart inverter communications and control, grid sensor and voltage regulation coordination, and switches and reclosers to keep it all contained within the proper boundaries that it’s testing out in Borrego Springs with SDG&E.
What’s built for a microgrid like that could be applied to many distributed contexts, he added. One very big East Coast utility has asked Oracle for end-to-end visibility, including Embedded Java on each endpoint, for distributed control, he said. “They’ve got to have ways to collect that data and respond to that in real time.”
That fits in with Greentech Media’s concept of the grid edge as a frontier for IT innovation. And it also aligns with the epochal challenge utilities are facing in integrating their millions of new active, co-generating customers into the grid.
“That’s what the utility wants -- they want to be assured they’re in control,” Williams said. “Those are some of the concerns with some of the smart grid technology – and it’s getting further than arms’ length from their control.”
To learn more about innovations in distributed intelligence on the grid, join Greentech Media at the Grid Edge Live conference this June 24-25 in San Diego, Calif.
Comverge, a supplier of demand response software for residential and C & I customers, named Gregory Dukat as Chairman, President and CEO. Dukat was most recently Chairman and CEO of Campus Management, a provider of software to higher education institutions. Dukat's appointment follows Blake Young's resignation as President and CEO. Comverge was acquired in 2012 by H.I.G. Capital.
The Electric Power Research Institute (EPRI) announced that Denis O’Brien, senior EVP at Exelon Corporation and CEO of Exelon Utilities, has been named chairman of the Board of Directors. Gil Quiniones, president and CEO of the New York Power Authority, was named vice chairman.
Dr. Chris Case was named CTO of Oxford PV, a spinout from Oxford University developing perovskite-based solar cells. The firm has raised more than $10 million in equity funding. Previously, Case served as CTO at the Linde Group.
Energy storage startup and flow battery developer Primus Power named Ravi Oswal as VP of Operations. Oswal was most recently VP of Technical Operations, as well as VP of Process Quality and Engineering, at Bloom Energy, where he was employed for nine years. Primus announced the first close of a $20 million Round C led by South Africa’s Anglo American Platinum earlier this year. Other investors include DBL Investors, I2BF Global Ventures, Chrysalix Energy Venture Capital, and KPCB. Founded in 2009, Primus has logged $35 million in total venture capital, along with significant funding over the years from DOE, ARPA-E, and the CEC.
Fortune's Dan Primack reports that KPCB partner Amol Deshpande "appears to have launched a startup called the Farmer’s Business Network," as per this SEC filing citing a $4.6 million investment. Deshpande had been active in Kleiner's "green ag" efforts but, according to Primack, he got "passed over" in the recent restructuring at the VC firm.
Arthur (Bud) Vos joined Enbala Power Networks as president and CEO. Previously, Mr. Vos served as COO at Simple Energy and as CTO of Comverge. Enbala's previous CEO, Ron Dizy, will remain with the firm as EVP and Chief Revenue Officer. Enbala provides a software platform for for grid optimization. One of its best-known projects is in PJM territory, where it has been providing frequency regulation services by aggregating quick-responding load from about twenty sites. Enbala is on GTM's Grid Edge 20 list.
Industry observers have seen many dramatic graphs about price reductions in solar recently, such as this one tracing price drops over the last 30 years and this one from Citigroup, but the following graph from investment bank Sanford Bernstein is quite stunning -- not just for its simplicity but because it draws attention to the potential impact of solar on the $5 trillion global energy market.
As shown in the chart, the cost of solar PV has come from -- quite literally -- off the charts less than a decade ago to a point where Bernstein says solar PV is now cheaper than oil and Asian LNG (liquefied natural gas). It does its calculations on an mmbtu basis (mmbtu is the standard unit of measure for liquid fuels, often referred to as 1 million British thermal units).
“For these [developing Asian economies], solar is just cheap, clean, convenient, reliable energy. And since it is a technology, it will get even cheaper over time,” Bernstein writes in a newly released report.
“Fossil fuel extraction costs will keep rising. There is a massive global market for cheap energy, and that market is oblivious to policy changes” in China, Japan, the EU or the U.S., according to the bank.
As Bernstein notes in its report, the share of solar PV in the global energy market is currently so small that “the idea that oil and gas is the 'loser' in this formulation is laughable...in 2014,” a contention confirmed by the following chart.
But that’s not likely to be the case a decade from now. Solar is already eating away at the margins of oil and gas demand. Bernstein says the adoption of solar in off-grid areas in developing markets will translate into less demand for kerosene and diesel. The adoption of solar in the Middle East means less oil demand. The adoption of solar in China and developed Asia means less LNG demand. And distributed solar in the U.S., Europe and Australia will likely serve to reduce natural gas demand.
And then Bernstein drops this bombshell: while solar has a fractional share of the market now, within one decade, solar PV (plus battery storage) may have such a share of the market that it becomes a trigger for energy price deflation, with huge consequences for the massive fossil fuel industry that relies on continued growth.
“The behavior from here seems clear: the solar industry will expand. Retaliatory steps from distribution utilities will increase the market for cost-effective battery storage. This becomes -- initially -- a secondary market for battery technologies being developed for the auto sector. A failed battery technology in the auto sector (too hot, too heavy, too rigid a form factor) might well be perfect for the home energy storage market...with an addressable end market of 2 billion backyards.
“And for some years, that will be the extent of the effect. We have previously calculated how large the solar sector would need to be in order to become a material share of incremental energy supply each year and therefore begin to displace high-cost oil and gas supply and start to depress prices.
“We estimate that the solar industry would need to be an order of magnitude larger than it is today to have this kind of impact. At the point where solar is displacing a material share of incremental oil and gas supply, global energy deflation would become inevitable: technology (with a falling cost structure) would be driving prices in the energy space. But even on an aggressive view, this could take the better part of a decade.”
But, the Bernstein analysts say, the chief risk is that they are being too conservative. The big oil and gas producers, and the investors that control the flow of capital, may not wait until energy prices do actually deflate; they will likely change their behavior well before that in anticipation that it will happen.
“If the downward sloping forward curve is ever accepted as permanent, rational behavior from energy producers will guarantee it is so. Sitting on oil and gas reserves for the benefit of generations yet to come ceases to be a rational strategy if that reserve represents a depreciating rather than an appreciating asset.”
This, Bernstein says, is the hidden flaw with the idea that solar is “too small to matter.” Ultimately, it says, what may kill the energy market for equity investors is not the fact that renewable technology and battery storage will turn into behemoths, but the realization of that future as inevitable.
When the wind blows and the sun shines in Germany, electricity prices around the country plummet. Natural gas peaker plants are not needed, as the peaks are erased and they cannot compete with renewables.
But the grid still needs a whole lot of balancing resources during times that renewables dominate. That makes demand response, still a very nascent resource in Germany, even more important.
When it comes to demand response, America has the most mature markets in the world. Within the U.S., demand response -- both for emergency load capacity and ancillary services -- is growing in every region.
The most active and largest market is PJM Interconnection, which also happens to be one of world’s largest grid transmission organizations. Germany has roughly half the peak load of PJM, but the volume of reserves procured by the four German transmission system operators are comparable to the size of the ancillary market in PJM, according to an analysis by EnerNOC.
EnerNOC bought its way into the German market earlier this year with the acquisition of Entelios, one of the European demand response leaders. EnerNOC already claims a large presence in Australia, a relatively mature DR market, and is moving aggressively into Ireland and the U.K. as well. But it is Germany that has the most immediate potential.
“In the next two years, Germany is our biggest opportunity in Europe,” said David Brewster, president and co-founder of EnerNOC. “But we’re very bullish about the opportunity for demand response in Europe as a whole.”
In 2010, very little of EnerNOC’s revenues came from outside the U.S. By 2013, about 20 percent of revenues came from abroad. While the U.S. market and the Australian market grew out of the need to shave off kilowatts when electricity demand is high, the German market is all about balancing services.
There are three levels of ancillary services in Germany, Brewster explained: primary, secondary and tertiary.
Primary is closest to the practice of frequency regulation in the U.S., which requires dispatch times of just a few seconds. EnerNOC is mostly working in the other two markets: secondary, which is similar to operating reserves and requires a five-minute response time, and tertiary, which requires a fifteen-minute response time.
The secondary and tertiary markets each need about 2,500 megawatts in each direction of positive and negative demand response, said Brewster. Germany is unique in that it needs demand response providers to drop load (positive DR) to balance the grid, as well as to increase their load when there is more renewable power than the grid can handle. In total, there are about 10 gigawatts of load needed.
The market potential is there, but it’s early days. “It’s a major evolution just [to allow] demand response to participate in all of these services,” said Brewster. Currently, demand response is participating in the markets as part of “innovation projects,” but it has not been codified in the market by the energy industry laws.
“With the newly elected German government only now becoming really active,” Brewster said, “we are working to have demand response formally included in the legislation.”
There are other barriers, as well. Commercial and industrial customers must secure permission from the electric supplier to participate in demand response, because the suppliers are responsible for balancing their supply and demand within their portfolio. Other European markets, such as Belgium, have made modifications to make DR participation easier. But it has not happened yet in Germany.
Another problem, Brewster explained, is that customers providing negative DR could exceed their contracted demand levels, triggering grid usage fees that are similar to demand charges that businesses face in many parts of the U.S. Aggregators like EnerNOC would like to see customers exempted from those fees while they’re providing grid balancing services.
Lastly, demand response will compete with natural gas power plants in the ancillary services market -- potentially eroding their profit margins even further. That may cause some resistance to increasing demand response.
Despite the challenges, EnerNOC is bullish about the market opportunity. “We view Germany as a linchpin of our European strategy,” said Brewster. “We have a great opportunity to export technology and business model around the rest of the world.”