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From 2011 to 2012, retirement eligibility rates for utility executives jumped 50 percent. Although the increase is significant, it is not even the most critical change management task most utilities are facing.
A new report from PwC, Power and Utilities Changing Workforce, outlines the layers of risk many utilities face. Not only are many workers retiring, but benefit costs are also very high, and the first-year turnover of new employees has gone up and is expected to rise even more.
“As a result, traditional 'word-of-mouth,' on-the-job training of utility workers is not sustainable,” the report states.
The report goes on to note that many older employees have stayed on during the recession or remained as contractors, which has “has helped perpetuate the conservative, consensus-driven culture that has challenged innovation in the industry.”
PwC explicitly questions whether older workers will really want to change tack 30 years into a career, while also calling on those workers to literally take notes documenting their intellectual capital instead of assuming they will just pass it along verbally to the next generation.
The issue is that younger workers learn differently and are expecting a different workplace than some staid utilities may provide. Some are adapting quickly; others are not. “While some organizations have been experimenting with new digital technologies and e-learning approaches to attract and retain younger people,” the report states, “most still lack appropriate training skills and procedures.”
Forward-thinking utility workers, often those closer to retirement, are beginning to question whether they and their peers should choose retirement in order to open up the utility industry to a new way of doing business.
But it’s not as simple as fresh blood. Even a utility with grand plans to reinvent its service can be hampered by regulation. Although new workers may be thrilled with more automated, high-tech processes, there is a large amount of intellectual capital that could be left behind as an entire generation of workers retires.
PwC does not paint a rosy picture of the challenges, but it also goes on to identify three core areas where utilities can improve and pave the way for a smoother transition to a new way of doing business.
Why is it so difficult to win a residential solar customer in the U.S.?
Why does it cost 49 cents per watt to acquire a customer in the U.S. while it costs less than 7 cents per watt in Germany?
That works out to about $3,000 for the typical 6-kilowatt residential rooftop, according to Nicole Litvak, GTM Solar Analyst. (The 7 cents figure is from an LBNL study on soft costs; the 49 cent figure is from the GTM Research report on customer acquisition in solar. Note that 49 cents per watt is not far from the cost of the PV module itself.)
Customer acquisition costs can account for up to 10 percent of overall residential solar costs. They also offer more near-term potential for cost reduction than any other component of solar system costs. A panel of experts at this week's sold-out U.S. SMI conference took a look at the increasingly sophisticated world of marketing solar to consumers and the volatile customer acquisition sector.
Bill Schuh, VP of Sales & Marketing at Sunrun, said, "The awareness level in most markets in the U.S. is low, and even if it's not low, a significant amount of confusion reigns about what the real costs of solar are -- and what's involved with not only purchasing solar, but then benefiting from solar energy over the life of a system."
Chris Stern, VP of Business Development at Pure Energies, said that customer acquisition costs are so high in the U.S. because "we have to find that perfect customer that has a great roof, has good credit, that's in the right utility territory, and has a high electric bill. [...] Whereas in Germany, they just need to have a roof and own the house to qualify." He said that Ontario, Canada has one-fifth the acquisition costs of the U.S.
Stern spoke of the critical mass reached in Germany because of the high penetration rates and the level of awareness instilled in the German public's consciousness.
Michael Mullen, VP of Sales at Roof Diagnostics Solar, said, "It's all about education. In Germany, they are well educated about solar. We are not educated here." He said that the public feels that solar is still too expensive.
"I think that's the key to growing this industry -- educating people." He added, "Once we get to the point of saturation [when] people understand they can go solar with no money out of pocket [and] that there are so many different ways to go solar, then you'll start seeing a lot more customers and [start] acquiring them" more quickly.
David Field, CEO of OneRoof Energy, suggested that acquisition costs actually exceed 49 cents per watt when overhead and sales management are factored in. Field said that the market is in its infancy. "The first lease was written in 2008," he observed, adding, "It's still very early-stage" and "we are still learning how to scale."
He emphasized that "people buy from people they know and brands they trust," which is one of the reasons OneRoof looks to realtors and accountants, professionals with a financial relationship to the customer, as potential solar salespeople instead of making retail partnerships.
Field suggested that most homeowners want a system, but they are "confused" by the financing and vendor choices. Field also noted that "most homeowners don't ask what type of panels go on the rooftop."
"People just want to save money" and work with "someone they trust," he added.
Shayle Kann, Vice President of Research at GTM, recently said, “We expect customer acquisition to be the next big area for innovation in residential solar and a primary determinant of whether any given installer will remain successful.”
Kann is right. Solar integrators and financiers are experimenting with door-to-door sales, phone sales, online sales, social networks, retail channels such as Best Buy or car dealers, and partnering with companies such as Nest. The list goes on.
Sunrun VP Schuh suggested that "we as an industry have not evolved to the types of selling and marketing that you'd find in much more mainstream categories." He noted that getting solar in Germany is more "an ordering process" than a process involving selection and selling. He also envisioned the process developing to be more fun and emotional.
What do you think? How can the solar industry better appeal to the customer's heart -- and wallet? How does the solar industry educate the public and make the decision-making process easy and rewarding? How does the solar industry make this into an emotional sale?
Here's the full video from the U.S. SMI session:
Chart from LBNL
Virtual auditing is like the night-vision goggle of energy efficiency, providing instantaneous clarity while others struggle in the dark.
Night vision may not be as good as seeing in the daytime, but it offers the ability to look at what was previously invisible. The same goes for virtual audits. They may not be as detailed as an on-site energy audit, but they can offer a glimpse of a building's energy profile before ever stepping foot inside.
That makes the tool a good fit for the military, which has roughly 300,000 buildings and a multi-billion tab for energy each year.
Retroficiency, the Boston-based virtual auditing firm, is set to deploy its software at 640 military buildings around the world -- providing the Army and Navy with an assessment of how their facilities are performing. Retroficiency will work with the energy services provider Sain Engineering Associates to provide the audits over the next year.
The partnership is a chance for Retroficiency to get deeper into the federal sector, where efficiency and renewables procurement are taking off under a mandate from the Obama administration.
"There's a huge opportunity in the government sector where there are very large portfolios of buildings and a very diverse set of data," said Retroficiency CEO and co-founder Bennett Fisher in an interview. "When you put those dynamics into play it will create a huge pipeline of efficiency projects."
Long before President Obama started issuing aggressive targets for energy performance in federal buildings, the military was taking the lead on procuring renewables, advanced biofuels and developing net-zero energy goals for its facilities.
As a result, virtual audits have become more important within the military and its related agencies. In 2012, Boston-based FirstFuel started working with the Department of Defense to implement zero-touch audits as part of an energy test bed initiative. And Charleston, S.C.-based SPARC also used its auditing software to uncover $3.5 million in energy savings at the Veterans Administration building in Washington.
Retroficiency's military deployment -- along with its recent outreach to small businesses and increasing number of utility partnerships -- could bring the company's energy monitoring reach to over 1 billion square feet globally through the end of the year. It will also give the company a new channel in the government sector, where half a million buildings await assessment.
"Solidifying this deal will really help us broaden our footprint and move deeper into the federal sector," said Fisher.
Virtual audits have become one of the fastest-growing sectors in intelligent efficiency. By using meter data, public monthly consumption data and other mapping tools, a range of startups have created software platforms to quickly target energy savings opportunities in buildings. That's uncovering trends across wide portfolios of buildings that were once unobservable.
In a recent analysis of 500 buildings in its portfolio, Retroficiency showed that the top 20 percent of buildings had savings potential of more than 40 percent, while the lower 20 percent could only reap a 3 percent savings.
In a similar analysis of its portfolio, FirstFuel showed that half of efficiency opportunities in commercial buildings could be realized through simple operational improvements, rather than more expensive retrofits.
While these companies admit that their tools shouldn't replace an on-site audit, they can dramatically improve how energy service companies target efficiency improvements.
And considering that operational efficiency is a key strategy of any military, the virtual audit should fit right in.
With residential solar financing companies leading the charge in rooftop solar installations around the country and utility companies starting to invest big money in that business, it’s worth asking a seemingly simple question. Why haven’t retail utilities, which sell power directly to customers in deregulated markets, cut out the middleman and started selling rooftop solar leases and PPAs themselves?
The answer is pretty complicated, but can be boiled down to two main reasons for and against the idea. On the “for” side, retail utilities would love to add low-cost rooftop solar to their array of competitive offers to acquire and retain customers. That could also give them a way to hedge their bulk power purchases, by giving customers a generation resource that’s producing the most power around the same time that grid demand and pricing peaks.
But they’re certainly not going to do it if it ends up losing them money -- and just how to draw the line between making and losing money on a rooftop solar deal can be pretty hard for retail electricity providers, or REPs. That may be why we haven’t heard a lot out of REPs like Constellation Energy that have launched their own residential rooftop solar business lines, and why we’ve seen a much more go-slow approach from others, like NRG Energy, that are only starting to emerge.
Beyond the challenge of building a new business from scratch to compete with upstart, yet growing, contenders like SolarCity, Sunrun, Sungevity, Vivint and many others, REPs have a much different set of economic calculations to contend with. First, every solar-generated electron a customer consumes equals an electron they don’t buy from the REP, making the way they configure that long-time payback from each customer a critical calculation.
Second, while REPs don't directly bear the burden of covering the fixed costs of maintaining the grid that keeps solar-equipped customers supplied with power when the sun doesn’t shine, they do indirectly pay those costs through agreements with the “wires” utilities that serve that purpose. Without some way to prove that their solar customers are reducing that power “traffic,” at the right times, they’ve got no way to reduce those costs.
That’s where smart meters can end up playing a critical role, according to research firm DNV KEMA Energy & Sustainability (now part of DNV GL). In simple terms, old-fashioned meters that are read every month have no way to record the hourly contribution of rooftop solar power to that reduction in power pulled through the grid. But smart meters, which record power consumption on an hourly or fifteen-minute basis, can -- and that provides a record that can be turned around to make a money-losing solar installation into a profitable one.
These points are laid out in a November presentation, using data from New Jersey, Connecticut and Massachusetts, three states that combine competitive energy markets, lucrative solar incentives and net metering programs, and a significant portion of smart-metered customers.
“The smart meters are key to this, because the real-time information is crucial,” Soner Kanlier, vice president at DNV KEMA Retail Energy Markets, told me in a November interview. Here are two charts, based on data from New Jersey utility PSE&G that illustrate that point. The first shows that costs actually increase for a retailer serving a solar-equipped customer with a monthly meter:
The second, representing a solar-equipped customer with an interval (smart) meter, shows the opposite, with extra costs transformed into cost savings:
To be sure, the presence of an interval meter isn’t the only barrier standing between REPs and the customer-sited solar game. “The main challenge for these retailers has been the tax credits, the third-party financing, and the market itself,” Kanlier said.
That could be why we’ve seen most REPs dive first into the business of selling green power to customers via contracts that buy power from wind, solar and other renewable resources. These green power purchasing programs are popular among customers interested in going green -- and that, in turn, has made what was a fairly rare offering into more or less a “pretty standard product” amongst the country’s REPs, eroding their value as competitive differentiators, Kanlier said.
These offers also come with a higher price for customers, which represent the pass-through costs of obtaining more expensive renewable energy, he said. Customer-sited solar, in contrast, can reduce the customer’s utility bills, while also providing them the satisfaction of going green.
Retailers may decide that partnering with established third-party solar providers is safer than creating their own offering. That’s what Direct Energy, a subsidiary of U.K.-based Centrica that operates in fourteen deregulated state markets, did with SolarCity in October, creating a $124 million fund to finance commercial and industrial rooftop solar.
But it’s pretty clear that other REPs are laying the groundwork for a wholesale assault on the business model of SolarCity et al. NRG CEO David Crane has been pledging a move into distributed energy, with promises of solar panels matched with natural-gas-fired home generation systems, now in development, to fill in the gaps that solar can’t.
This is an active, volatile market segment and one worth watching as REPs jockey for position in retail solar, helped by the 46 million smart meters currently in place.
New community and crowdsourced financing models for solar will expand the availability of cheap capital -- if regulatory risk can be cleared.
No more than 25 percent of U.S. rooftops are suitable for standard solar, GTM Senior Editor Stephen Lacey noted in introducing the Democratizing Solar panel at the GTM Solar Market Insight conference. A huge pool of renters and low-income customers could be brought into the solar market through emerging smaller-investor models.
First-mover Solar Mosaic’s business model is a relatively simple two-step process, explained CIO Greg Rosen. First, raise money and loan it to a Special Purpose Entity (SPE) created to build a solar project, and then offer shares to individual investors. His company has secured investments of over $5.6 million and returned an average of 4.5 percent to 6.5 percent to its accredited and non-accredited investors.
Indicative of the burdensome regulatory complexities, Rosen added, is that Solar Mosaic must use the term "crowdsourced" and avoid using the term "crowd-funded" to remain in compliance with federal and state securities law dictates.
Clean Energy Collective (CEC) also creates an SPE front fund, explained President Paul Spencer. Its utility-centric business model is funded by what regulatory dictates require it to call "customers." CEC begins with a power purchase agreement from a utility and ends with the customers owning and getting electricity bill credit for individual panels. It presently has 29 projects worth $70 million in six states.
“The community solar space offers huge opportunities for securities lawyers,” joked Village Power Finance CEO Ty Jagerson. Jagerson’s company works with nonprofit organizations that want solar but cannot monetize tax credits. It creates an SPE for investors in rooftop systems for the nonprofits and then builds and manages those systems.
Community-based and shared solar business models fit the DOE SunShot goal of cutting solar costs and increasing the scale of deployment. The aim is to make solar subsidy-free by 2020, according to DOE Fellow Anna Brockway. DOE’s recent workshop on the new models turned up three key needs: reducing regulatory uncertainty, improving utility collaboration, and educating regulators, utilities, and the general public
Rosen said California regulators have given Solar Mosaic the green light because his company has gone to great lengths to make its solar investments “look and smell like any other loan for solar," adding, “This is an early stage for community solar."
CEC uniquely works with utilities, Spencer said, and doesn’t use net metering. It is trying to buck the current trend “and keep utilities and solar from drowning each other.”
“I don’t challenge utilities; I’m too scarred,” Jagerson said. “We try to get as far away from them as we can, but solar does need to work with utilities.”
“We have found that the more utilities learn about the community solar model, the more they are interested,” Brockway said. They will play “a crucial role [when] they accept it and figure out how to deal with it.”
CEC is in 141 conversations with utilities across 39 states, Spencer said. Each one is different. “Some say ‘Yes’ and some say ‘Leave now.’ And some of those call back a year later.”
“There is a danger in painting utilities into a corner,” Rosen said. “The solar industry needs to listen to their needs and try to align the arrows of the different models.”
Community-funded projects may not be as low-risk as investment-grade projects, Rosen pointed out, but the multiple sources of funding reduces risk because “you can find a new customer for one that defaults.”
Another key to minimizing risk, the three developers agreed, is having the right consultants and third-party underwriters. “If everything is buttoned up,” Jagerson said, “standardizing could lead to downstream securitization.”
Using truSolar’s method of standardizing non-residential solar projects, Rosen said, can also reduce investors’ perception of risk.
“A key part of our SPE structure is setting aside a trust fund for project O&M,” Spencer said, “to ensure the community will be taken care of and not lose their investment, no matter what happens to CEC.”
Asked what policy changes would move community solar ahead, Jagerson called for a carbon tax or “anything to move to a national commitment to support renewable energy.”
Spencer called for a different type of subsidy, contending that the tax credit is “woefully deficient” and allows “monetizing to dissipate to other parties.”
DOE has generally supported crowdfunding, Rosen said, but it needs to help figure out how SPEs can identify the good players in the space. “We don’t want to throw out the baby with the bath water,” he said, “but we’ve got to protect the individual investors despite a few bad actors.”
Watch "Democratizing Solar: Crowdfunding and Community Solar" from the U.S. Solar Market Insight Conference 2013:
This week, GTM Research and SEIA published the Q3 2013 U.S. Solar Market Insight report. The infographic below details some key milestones that the U.S. solar market will hit by the end of 2013.
Embed this on your site! Copy and paste the code below onto your HTML to use this image.<a href="http://www.greentechmedia.com/articles/read/Infographic-State-of-US-Solar-2013" target="_blank">
Who knows how economical it might be, but the Japanese electronics and industrial giant Hitachi is moving toward marketing an energy storage system that could be a companion piece to renewable power generation -- another sign of the growing interest in such products.
The company said a system called CrystEna (that’s “crystal” and “energy” shortened and squished together; maybe it sounds better in Japanese) will use lithium-ion battery technology in a 1-megawatt container-like package. At that size, this isn’t for home storage -- nor is it the sort of storage that SolarCity has begun promoting for large business solar systems to cut peak demand.
Instead, this looks like a utility-scale application, the kind of thing that would be used in a fashion similar to the 4-megawatt sodium-sulfur battery system from NGK Insulators that the Northern California utility Pacific Gas & Electric is testing in San Jose.
But while Hitachi was announcing CrystEna, it was a bit unclear about exactly when and how it might come to market:
In the beginning of 2014, Hitachi plans to begin a demonstration test of this energy storage system in North America. Plans call for Hitachi to reflect the results of this testing in a commercial product after verifying the commercial viability and performance of the system in the electricity trading market, or the so-called ancillary market connected with maintaining the electricity supply-demand balance. Furthermore, Hitachi will examine whether to promote the system, to be named “CrystEna” (Crystal+Energy), as one of its solution businesses for expanding the transmission & distribution business in the global market.
While storing massive amounts of energy isn’t anywhere near economically feasible yet, utilities are looking for solutions that can help ensure grid stability as variable wind and solar become bigger players, and perhaps to help take a bite out of peak load. This is especially true in California, where state law requires 33 percent of electricity come from renewable sources by 2020 -- and where regulators recently ordered Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric to “procure energy storage resources” totaling 1,325 megawatts by 2020 and have it installed by the end of 2024.
Modern grids rely on many different resources to stabilize the electricity they carry. But in simple terms, let’s separate them into two main types: those that have “inertia” and those that don’t.
Spinning resources like turbines and generators have inertia, meaning that they slow down and speed up in ways that directly interact with and improve the stability of the electrical system. Solar and wind power inverters lack inertia, and while they can be programmed or controlled to perform certain grid-balancing tasks, they just don’t provide the same stability as spinning metal, magnets and wire.
This can be a significant problem for microgrids -- self-contained systems of power generation, distribution and end loads. Microgrids tend to rely on diesel generators or small-scale turbines as their spinning resources, but would like to add more renewables to their systems.
But the more they add, the more they rely on the uncertain ups and downs of wind and sun-generated power, all coming from inverters that lack the inertial stability that comes from spinning generators. This can quickly add up to system-wide instability that can force generators to ramp up and down wildly, push grid protection gear into states it’s not meant to handle, or force the wind and solar to shut off altogether.
Swiss grid giant ABB believes it has an answer to this challenge in PowerStore, a grid stabilizing generator that combines the inertial properties of a flywheel, the power management functions of advanced inverters, and the software to make it all work together. Think of it as an entire grid’s worth of generators, power electronics and control systems, shrunk to the size of a cargo container, that can push the practical penetration of renewable power from around 15 percent to 20 percent, to as high as 100 percent.
That sounds like a bold claim, but according to Brad Luyster, vice president and general manager of ABB’s microgrid business, that’s exactly what many of the systems using PowerStore are handling today. Of course, it’s rare to see sun and wind power completely supply a microgrid’s power needs, so those systems fluctuate between 100 percent and as low as 40 percent renewable energy through the course of a day, or a year.
Through it all, “PowerStore is the voltage and frequency supplier,” he said, keeping supporting diesel generators from “hunting” up and down, or grid protection gear from tripping on and off, in a vain attempt to balance out fluctuations.
The flywheel at the heart of the system is “a spinning mass that requires very little maintenance, and a high duty cycle,” with the ability to react within 5 milliseconds, far faster than diesel generators can be fired up or down.
The inverters, in turn, can inject or absorb real or reactive power in ways that help match the characteristics of inverter-supplied renewable energy. Orchestrating it all is ABB’s renewable microgrid controller (RMC) software, which monitors and manages both renewable and fossil fuel-fired generators.
ABB has installed PowerStore devices in a dozen microgrids across the world today, Luyster said. Those account for a collective 3 megawatts of power management, and another 2.1 megawatts are under commissioning, according to a March presentation (PDF).
The earliest deployments are in Australia, where Powercorp, the developer of the PowerStore technology, used them to integrate wind power into diesel generator-powered remote grids. ABB started working with the technology in 2006, and bought Powercorp in 2011 for an undisclosed sum. Other off-grid systems in Alaska and the Antarctic, and several island grids, including one in the Azores, round out the mix.From Island Grids to Embedded Microgrids
Diesel-dependent remote or island grids remain the most economically attractive setting for microgrids, since they’re reliant on expensive imported fuel, which makes the payback on investing in renewables come more quickly. At an installed cost of about $1.5 million to $2 million, the PowerStore device comes in at about 10 percent of the cost of the microgrids they’re enabling, which generally fall into the range of 5 to 10 megawatts of capacity, he said.
But PowerStore can also play a valuable role in grid-connected microgrid systems, he said. ABB has one project with Canadian utility Hydro Quebec that’s using the device to balance about 6 megawatts of wind on a 45-megawatt grid, he said.
Beyond that, ABB is looking into about 10 different grid-connected, or “embedded,” microgrid projects across the United States, he said. These are focused on providing the on-site power reliability to allow independent generation and load to keep running when the grid goes down.
Take the example of a data center, which already has emergency backup generators and uninterruptible power supply (UPS) systems, but also wants to keep other resources, like combined heat-and-power (CHP) systems or rooftop solar panels, running during an outage. Today, that’s not really possible without the guidance of the grid’s frequency and voltage for those systems to run against, he said.
But with PowerStore in place, “We energize the grid,” allowing those systems to keep running. That could allow a data center to skip the step of setting up an entire, parallel emergency backup system, as well as the switching systems to move from grid power to off-grid power, and replace it with a single standalone system -- and that, in turn, could save lots of money, and allow inverter-based renewables to keep pumping power to that system through emergencies.
“We’re just in the midst of doing this with a couple of customers,” he said. Those include several projects in Connecticut, a state that’s pushing microgrid development in the wake of Hurricane Sandy to keep key community assets powered after major storms.
It’s also working on a proof-of-concept project with giant U.S. utility Duke Energy, centered on a mixed-use residential and commercial development surrounding a newly built community college campus, he said. The idea there is to show Duke how providing critical power and integrating local renewable energy could help the utility by reducing the costs of serving that community with the array of grid resources that PowerStore could provide instead.
The United States has nearly 1,500 megawatts of generation operating in microgrids, according to the Rocky Mountain Institute. But almost all of those projects aren’t set up to be an integrated utility resource -- although projects like San Diego Gas & Electric's Borrego Springs microgrid serve as noteworthy exceptions to that rule. There’s quite a debate over whether microgrids represents an existential threat to utility business models, as yet another step in detaching customers from the grid power that utilities sell.
But for the vast majority of customers, the utility grid is still absolutely necessary to keep stable and plentiful power flowing. At the same time, the rise of distributed renewable generation, on-site energy storage systems, sophisticated building energy management systems and other grid-edge technologies are putting utilities under stress to keep serving that role. Microgrids could play a valuable part in smoothing the transition to a decentralized, yet still secure grid.
Consumers are quickly warming to LED bulbs thanks to falling prices and much-improved performance over the past few years. But when it comes to the quality of light they give off, most LEDs are only as good as compact fluorescent lamps (CFLs).
The Department of Energy recently published a deep dive on consumer LED bulbs in a “snapshot” report on solid-state lighting spotted by All LED Lighting. The report found the technology behind A-type LED lamps, which come in the familiar bulb shape, has improved dramatically over the past five years. But the authors voiced some concern that consumers may be turned off to LEDs over quality, as many were with CFLs.
In the technology department, LEDs have been on a tear. The efficacy of LED bulbs in the DOE’s Lighting Facts database has nearly doubled in four years. Of the new LED bulbs that came out in the third quarter this year, the median efficacy was 78 lumens, a measure of light output, per watt, compared to 40 lumens per watt for the same period in 2009.
More important to broad consumer acceptance, though, is brightness and bulbs that produce light in all directions -- two areas that have historically been challenging for LED technology. Now, though, there are a number of products that produce as much light as traditional 75-watt or 100-watt bulbs. And while LEDs are best suited for giving off light in one direction, manufacturers have designed bulbs that mimic the omni-directional light of conventional bulbs.
The cost of LED bulbs, which can be more than $10 for a 60-watt equivalent, has also been a barrier to consumer adoption. But the introduction of many new products -- the DOE counts over 300 LED A lamps -- has led to widespread price competition.
In a separate study, the DOE found that the price LED lights overall has fallen by more than 85 percent in the last five years.
But when it comes to color accuracy, as measured by the color rendering index (CRI), LEDs so far are nothing special.
The DOE’s snapshot notes that nearly all the LED bulbs in its database have a CRI in the 80s, with the majority between 80 and 85. “This matches the typical level for fluorescent lighting, and is just above the minimum threshold for Energy Star qualification,” the report says. Only four A lamps have a CRI of 90 or higher. That level would meet Voluntary California Quality LED Lamp Specification, which was put in place to avoid the situation that occurred when CFLs were first introduced. Some manufacturers introduced cheaper, low-quality CFLs, which gave consumers a bad first impression that’s proven difficult to shake.
LED makers can develop bulbs with a higher CRI, making them closer to incandescent lamps, but that means sacrifices to power efficiency. Manufacturer Cree, for example, makes the high-CRI TW series, which costs nearly twice as much as their average-CRI counterparts. For a 60-watt equivalent, the efficiency drops from 84 lumens per watt to 59 lumens per watt.
Is having a high CRI a requirement? In general, these lights are used by photographers or in places, such as stores outlets, restaurants, or museums, where there’s a premium on accurate colors. And based on reviews of LED bulbs, consumers appear more attuned to the instant brightness of LEDs compared to CFLs and the color -- a cooler white versus the yellow of incandescent bulbs.
The California voluntary standard will give the industry more data on how consumers weigh the tradeoffs between efficiency, brightness, and quality. But as consumers get more sophisticated about lighting, they may place a higher priority on quality. “CFLs are often criticized for their color quality, which many adopters found unsatisfactory,” the DOE report notes. “Increasing the color quality of LED A lamps may be detrimental to the cost and efficacy of products, but it may also ensure consumer satisfaction.”
Three energy experts weighed-in on The Utility Death Spiral at Tuesday morning's first panel at a sold-out GTM Research event in San Diego, California. The "utility death spiral" describes an increase in distributed generation and storage that threatens the volumetric energy sales model of the traditional regulated utility.
GTM Vice President of Research Shayle Kann moderated the panel and asked big questions about the role of the regulator and the future of the utility business model.Jon Wellinghoff, former FERC chair and now a Partner at law firm Stoel Rives
Wellinghoff said, "We are in the transition to distributed resources. But we are seeing a transformation -- we are moving out of the traditional monopoly system. We're seeing wholesale markets grow." He added that the expansion of new retail and wholesale markets "will reveal the value of distributed resources." He suggested that "the role of the regulator is to oversee the transparency of the market, to see that it operates in a fair and open fashion." He added, "We will transition to a market-based system, moving from [one that is] rate-based and monopolistic" to an "open and competitive system."
In moderator Shayle Kann's "perfect world," Wellinghoff saw a situation where services and products were "unbundled" and competition occurred "where it can happen." He envisioned the distribution system being left a monopoly with fixed charges distributed across all customers.
Wellinghoff pointed out, "Ultimately, the impact on bottom-line revenues and net profits [is] still small -- even in Hawaii." He said, "There is still a need to recognize fixed charges in a distribution system somehow... [but] you should have a fixed charge for everyone," adding, "A fixed charge for solar is nonsensical."
The former FERC commissioner added that energy storage along with new battery chemistries could prove even more disruptive to the traditional utility.Craig Cornelius, Senior Vice President, Business Development, NRG Solar
Cornelius spoke of NRG Solar as being both "kind of a utility" and "kind of not a utility." He admitted to being a load-serving entity.
"As a company, we think of ourselves as a business that needs to generate its returns more creatively," adding, "We've never had the protections of a local monopoly incumbent."
He suggested that NRG was "about new markets and new market segments." He said, "We have an EV-charging company plus ways of looking at solar and storage -- different than most regulated monopolists in the sector." To that end, he noted that NRG was exploring unconventional natural gas generation, fuel cells, energy storage systems and energy efficiency.
The Dominion VP said that distributed generation was a threat to the utility business as well as an opportunity. He noted that Dominion is one of only a few utilities that has successfully implemented a fixed charge for solar customers of a certain size.
"It came about as a legislative compromise," said the VP.
Shuford spoke about what really worries utilities. He said that "you're lucky...if you can project a 2 percent load growth" as a regulated utility. He added that if through increased penetration of PV, energy efficiency or demand response "you cut into that 2 percent," then "utilities will spring into action."
The Dominion VP reminded the audience that utilities "make money when they build things," adding, "If we are not building things, people will invest in other businesses."
He suggested that "long before we get into a death spiral, we will look at DG as an impact on load growth." He said that the impact on earnings can manifest in many ways. "We can try to get rate design changed so that it's fixed and not volumetric," adding, "Putting more in the fixed category makes us less subject to volatility."
He suggested that utilities getting into the solar sales and installation business is not what consumers want. He said that solar and DG customers want to be free of the utility. He noted that solar power and desire to minimize exposure to the utility is one of the few issues that can unite solar advocates and the Tea Party.
We've written extensively on the changing role of the utility and the new type of energy consumer on the grid edge. Calling this shift a "death spiral" is fear-mongering and "a myth" according to Forbes. The panelists at the U.S. SMI conference suggested that "regulators will step in to make sure it doesn't happen."
Nevertheless, something transformative is occurring in the electrical utility industry -- and utilities will have to lead or adapt to the new normal of high-penetration distributed generation.
Watch the first part of "Fireside Chat: Tomorrow's Utility in a Distributed World" at the U.S. Solar Market Insight Conference 2013 (and watch the second part here):
The numbers suggest DOE loan guarantees played a significant role in U.S. solar’s enormous emerging success -- but a new report claims that cronyism and lobbying plagued the program.
The Reason Foundation, a half-century-old libertarian think tank, claims the DOE Loan Program Office (LPO) concentrated loan guarantees in “highly risky enterprises” and failed “to mitigate risk through diversification,” according to Stimulating Green Electric Dreams: Lobbying, Cronyism and Section 1705 Loan Guarantees, a policy brief from the group.
LPO chose “mostly ‘junk’ grade investments” in “financially unsound” companies that had “close ties to those in charge of approving the loan guarantees,” the brief asserts. Because the LPO “allocated funds broadly in proportion to applicants’ lobbying expenditures” and some recipients “were able to use political connections,” the report adds, “it diverted money away from more sustainable projects.”
The 930 megawatts of PV built in the U.S. in Q3 2013 made the quarter the industry’s second biggest ever, 20 percent higher than this year’s Q2 and 35 percent more than Q3 2012, according to the just-released GTM Research/Solar Energy Industries Q3 2013 U.S. Solar Market Insight report. Utility solar was more than half of the new PV capacity. The first wave of new U.S. concentrating solar power projects came on-line, as well.
“A big part of that was the early, active, and crucial support to the first five U.S. utility-scale solar PV projects,” explained Department of Energy Loan Program Office Executive Director Peter Davidson. “They had offtake agreements, equity investors, eager developers, and they were fully permitted. But they couldn’t attract senior bank financing until the LPO provided loan guarantees.”
The LPO also invested in CSP projects like Abengoa’s Solana and SolarReserve’s Crescent Dunes because, Davidson added, these projects' storage capability “creates what we call ‘nighttime solar’ that extends the production of the facility into the shoulder and night demand periods.”
The LPO’s goal is “to take untested technologies that our financial and technology experts feel would make the world a better place and demonstrate them so that when we step away, the private sector steps in.”
Approximately 10 percent of the 10 gigawatts of U.S. solar energy now on-line came from LPO-backed projects. But after 2011, when stimulus funding ended, ten new utility-scale PV projects went into development without LPO backing that are now either built or in construction, Davidson said. “The PV solar industry has now been incubated and is completely financed from the private sector. That is a real success.”
“Our portfolio is 97 percent money good with very strong credits. We’ve had issues. We’re not hiding anything. But it is less than 3 percent of the program,” Davidson responded.
“The credit quality of the LPO loan portfolio has increased every year since 2009 when the first loans were made and it continues to get stronger,” he said. “We primarily funded innovative generating technologies and the loans were made before the projects were built. Now twelve are grid-connected and three more will be in the next few months. From a credit perspective, that makes the portfolio much stronger.”
But the Reason Foundation's brief claims that according to a 2012 U.S. House Oversight Committee report, there was “a pattern of poor management and unconstrained lending” that ended in “a high risk, speculative and undiversified loan portfolio.”
“Having worked in the private sector for much of my career,” Davidson said, “the process the LPO goes through and the deep due diligence we do is more rigorous than the private sector and the approvals process is just as rigorous.”
“The Republican report,” House Democrats responded to the Oversight Committee conclusions, “is a political document, not an accurate portrayal of the facts.” The Oversight Committee’s report, they said, cherry-picked facts, omitted evidence and made “unsubstantiated insinuations.”
“And after all that Congressional oversight,” Davidson noted, “no charges were made, nothing was proved, and the Allison report showed there was no basis for the allegations.”
NRG Energy, which spent $10,724,000 on lobbying between 2007 and 2012 and got $5.2 billion in loan guarantees, according to the Reason Foundation report, exemplifies the “stark” and “excessive concentration of investment” in a few companies and especially in those that made big lobbying investments.
“NRG developed some of the largest solar power projects in the United States with the help of the DOE loan guarantee program and, in the process, created thousands of construction jobs and many permanent jobs,” NRG responded. “We believe [our projects] represent good investments in a sustainable and clean energy future.”
“Government loan officers do not have incentives to ensure that the investments they make on the public’s behalf generate a return,” the Reason Foundation report charges. “There is a far better way to allocate funds. It could establish prizes that it would only award to technologies that meet specific criteria.”
“We don’t go out and select winners and losers. Everything we do is part of a competition,” Davidson said. “We put out a solicitation and people respond. There is a brutal competition among the applicants to make it through our gauntlet of due diligence.”
In just a few years, Americans will likely produce the majority of the power they consume at their home or office, primarily through distributed solar arrays on their roof or over their driveways or parking lots. If they come up short, they can tap the battery in their electric car or an energy-converting appliance in their basement. What these options illustrate is that consumers will only turn to the grid as a last resort.
It’s a reality that the utility companies have ignored for too long. Like the phone and transportation monopolies before them, they believed the sun would never set on their position as keepers of the all-powerful grid. But the grid, which is the backbone of their business model, is in jeopardy due to the rise of distributed generation.
First, let’s accept the fact that the sale of system power has entered a period of inexorable decline. The correlation to GDP growth is broken. Societal trends, including stagnant population growth levels, consumption crowdsourcing, and a greater commitment to sustainable lifestyles, will accelerate the pace of demand destruction in the energy industry.
Another factor is automated at-home conservation, which will help smooth out the daily load curve. As power sources such as solar and wind take over the system, they will match electricity usage both when it is being produced and where it is being produced.
The net effect is that the massive excess capacity that our grid system currently carries -- generation and transmission -- to meet high peak demand will become unnecessary. The need to build more power plant and transmission lines will be eliminated, as well.
Over the next decade, three trends will pave the way for consumers to leave the rate-based power industry behind:
At first, the utility companies tried an ill-conceived attempt to win politically. As we saw in Arizona last month, the utilities’ political strategy involves net metering constraints and absurd interconnection charges that they try to co-opt for their economic benefit.
This is not to say there is no role for utilities down the line. But that prize will go to those that evolve with the times, and NRG certainly hopes to be one of the leaders serving this new future.
Solar will soon become dirt-cheap, but nothing is going to change its fundamental intermittency. The solution lies in compromise. Utilities should compensate solar customers fairly by buying back the excess supply that coincides with peak use, instead of trying to offer average power supply costs. Solar customers should expect to pay for grid use at night or on cloudy days.
In the long term, off-grid solar needs a reliability partner and the solution is the natural gas distribution system that could be used to connect a home "appliance" to convert natural gas into electricity for the home. Currently, 34 million American homes are served by electricity and natural gas distribution systems, and it makes no sense for homeowners to pay for both when one would suffice.
NRG is developing a gas conversion machine with Segway inventor Dean Kamen. This machine, known as the Beacon 10, operates like a refrigerator compressor running backwards. Heat from natural gas goes in and out comes 10 kilowatts of electricity to supplement solar on the roof or from a freestanding structure like NRG’s Solar Canopy. The Beacon 10 also emits heat as a byproduct, which can supplement hot water heaters and home heating systems.
Clearly, the future of our industry is completely up for grabs. We don’t know which companies will helm the future of the electricity industry. However, the only thing I am sure of is that our sector can no longer defend the status quo.
Put simply, we can’t act like utility companies anymore.
David Crane has been the President and Chief Executive Officer of NRG Energy since December 2003. Under his leadership, NRG has become a Fortune 500 company with enough generating capacity to power nearly 40 million homes, benefiting about 2.2 million retail customers.
FirstFuel has raised $8.5 million in a Series B round aimed at expanding its remote building analytics to new markets -- and, if the round’s lead investor is any indication, that could include Europe.
That’s because giant European utility E.ON is leading the investment round, joining existing investors Battery Ventures, Rockport Capital and Nth Power. The funding round brings total investment in the Lexington, Mass.-based startup to $21 million, and is aimed at fueling growth and development of its Remote Building Analytics software-as-a-service platform.
FirstFuel has several large U.S. utilities using its technology, including Pacific Gas & Electric, and has also landed several government partners, including the federal General Services Administration, Washington, D.C.'s Department of General Services, and the Department of Defense’s Environmental Security Technology Certification Program (ESTCP).
Now it has a strategic investor to offer it entree into projects in Europe, where regulations are set to push efficiency on a broad scale. In a Tuesday statement, Urban Keussen, senior vice president for technology and innovation at E.ON, said the utility is planning to “work with FirstFuel as both an investor and a partner for the future,” though the release didn't provide any more details.
FirstFuel's technology relies on analyzing energy meter data collected from utilities, along with weather data, building location information and characteristics, and other site-specific information, and then applying what CEO Swapnil Shah calls its “inverse modeling” approach. It’s one of a number of “virtual energy audit” software providers promising a much cheaper way to discover and prioritize energy waste in buildings, or across entire real estate portfolios (others include Noesis Energy, Retroficiency, Sparc, and Energy Results).
As of November, FirstFuel had analyzed over 700 million square feet of commercial building space, which can help customers take low or no-cost actions to reduce simple energy waste (e.g., leaving lights and HVAC systems on overnight, incorrectly setting operating parameters), as well as prioritize which buildings offer the best return on investment for more involved efficiency retrofits.
It’s all part of the growing world of intelligent energy efficiency, which stretches from early-stage companies like SCIenergy, Lucid, WegoWise, Agilis, Switch Automation and BuildingIQ, to energy services giants like Honeywell, Johnson Controls, Siemens, Trane and Schneider Electric. Demand response companies like EnerNOC, building energy management and analytics companies like Ecova, EnergyCAP and eSight Energy, and IT systems integrators like Wipro are also moving into building efficiency.
All are targeting the massive opportunity in buildings, which can waste up to a third or more of their total energy use. All face the challenge of making efficiency investment competitive with alternative opportunities for capital spending by building owners, coming up with ways to manage the split incentives that bedevil efficiency projects, and of course, scaling up their solutions to meet the needs of customers at the portfolio level.
Utilities, in turn, have an incentive to better understand their customer energy profiles to optimize their efficiency spending, increase customer satisfaction, and perhaps incorporate real-time, adaptive building energy controls into serving their grid needs. Customer-facing systems are particularly important for utilities in deregulated markets, which must fight to land and retain customers with a whole set of offerings that go beyond simple sales of electricity and natural gas -- including efficiency services.
The U.S. solar industry has come a long way in a very short timeframe. After decades of slow but steady growth, the last 2.5 years have brought an explosion of new installations in America -- with two-thirds of all total distributed solar installed since just 2011. By 2015, installations will likely double.
At only half of a percent of U.S. electricity capacity, it would be hard for anyone to call solar a “mainstream” contributor to the broader energy mix. However, there are a number of other factors to consider when looking at the impact of the technology.
Shayle Kann, GTM’s vice president of research, outlined four of those indicators at this morning’s Solar Market Insight conference. (The data can also be found in GTM Research's newest report on the U.S. market, released today.) When considering this broader range of factors, Kann concluded that the industry is “pretty close” to becoming a mainstream energy source.
Here’s Kann’s mainstream solar checklist.
1. Primary source of new electricity capacity: check
In 2012, solar was the fourth-largest source of new capacity in the U.S. This year, it is the second largest, according to the Federal Energy Regulatory Agency.
"This year will be the first year that there will probably be more solar in the U.S. than in Germany," said Kann. "The U.S. market was slower [than Germany] and still has a long way to go, but is strong and consistently growing overall."
According to GTM Research, there was 23 times more utility-scale solar installed in the third quarter of 2013 compared to the third quarter of 2012. And although the residential solar market started from a very small base, it has grown 230 percent over the last 15 quarters.
"That's remarkably consistent growth," said Kann. "That's the beginning of the hockey stick -- we're very bullish on residential solar."
2. Cost-competitive without fickle incentives: half check
There's no doubt that the solar industry is still dependent on state-level incentive programs, many of which foster boom-bust cycles. More than 80 percent of solar installations are concentrated in five states, not because the fundamentals there are necessarily the best, but because "those are the states that have the right incentives in place," said Kann.
"As long as that's the case, it's going to be hard to check that off the list," he said.
However, there are signs that the market is shifting. In the third quarter of 2013, more than half of all residential solar installations in California were deployed without any assistance from the state's solar initiative. That number has continually grown every quarter.
"California is a great example of watching this happen. I do think it's the beginning of a monumental shift in solar in the U.S.," said Kann.
3. Solar taken seriously by the electricity industry: check
This year marked a noticeable change in the way utilities, regulators and analysts are talking about the impact of distributed generation on the grid. This spring, the Edison Electric Institute issued a report warning that utilities could face serious financial losses as more customers invest in solar and efficiency. The report sparked a more serious look at the "utility death spiral" that is already underway in Germany.
"If you look at the conversations that have taken place, I think it’s clear that something fundamental has changed in the collective mindset of U.S. utilities. They are taking solar seriously, and that’s both a good and bad thing for the industry," said Kann.
The "bad" could come as more utilities worried about shifting T&D costs look to end or weaken net metering laws. That is already a contentious issue in a handful of states, and the net metering battleground is expanding.
However, the "good" impact may come as utilities start buying solar companies, make venture investments in developers and directly invest in projects. That trend is also growing.
"It seems clear to me that the utility industry is taking solar seriously in the U.S. in a way that absolutely was not true two years ago," said Kann.
4. Solar must be bankable: check
In order for solar to be mainstream, it must be treated as such by investors. The increased interest in solar on Wall Street is another positive sign.
According to GTM Research, residential solar finance grew from $1.2 billion in 2012 to $2.3 billion this year. And as new forms of securitization and yield co models pop up to help leverage retail investment in projects, new sources of capital continue to flow into the industry.
"Solar projects have to be a mainstream source of investment, and 2013 has been big year in this progression," said Kann. "We've seen some big precedent-setting events."
GTM Research projects that solar will make up about 10 percent of U.S. electricity generation by 2027 based on current growth rates. When compared to traditional forms of fossil generation, some may still not think that makes the technology "mainstream."
But when looking at the whole ecosystem of investment -- the participation of Wall Street, the attention paid by utilities and steadily improving project economics -- solar may become more influential than previously thought.
“I didn’t think solar was all that close to being there. But when I consider this checklist, we’re pretty close,” concluded Kann.
GTM Research and the Solar Energy Industries Association® (SEIA®) today released U.S. Solar Market Insight Q3 2013, the definitive analysis of solar power markets in the U.S., with strategic state-specific data for 28 U.S. states and the District of Columbia.
The U.S. installed 930 megawatts of photovoltaics (PV) in Q3, 2013, up 20 percent over Q2 2013 and 35 percent over Q3 2012. This represents the second-largest quarter in the history of the U.S. market and the largest quarter ever for residential PV installations. Even more importantly, 2013 is likely to be the first time in more than fifteen years that the U.S. installs more solar capacity than world leader Germany, according to GTM Research forecasts.
“Without a doubt, 2013 will go down as a record-shattering year for the U.S. solar industry,” said Rhone Resch, SEIA president and CEO. “We’ve now joined Germany, China and Japan as worldwide leaders when it comes to the installation of new solar capacity. This unprecedented growth is helping to create thousands of American jobs, save money for U.S. consumers, reduce pollution nationwide and lessen our dangerous dependence on often-unstable foreign energy supplies. When it comes to preparing for America’s future, clean, dependable and affordable solar energy has become 'The Little Engine That Could,' defying expectations and powering economic growth -- and frankly, we’re just scratching the surface of our industry’s enormous potential.”
The residential market continues to see the most rapid growth of any segment in the U.S. PV market. Through Q3, residential PV installations were up 49 percent year-over-year, driven largely by progressive state renewable energy initiatives. The non-residential (commercial) market has seen the most difficulty this year with installations forecasted to stay flat over last year. The utility market continues its consistently strong installation numbers and is forecasted to exceed 1 gigawatt of installations next quarter, including Abengoa’s Solana, the world’s largest parabolic trough concentrating solar power (CSP) plant. This will be the first time any individual market segment has hit that mark.
“Solar is the second-largest source of new electricity capacity in the U.S. this year, trailing only natural gas," said Shayle Kann, Vice President of Research at GTM. "As solar continues its march toward ubiquity, the market will require continued innovation, efficiency improvement and regulatory clarity. But already the groundwork has been laid for a mainstream solar future."
At the state level, California continues to lead the solar PV charge, installing 455 megawatts in Q3. North Carolina moved into the No. 3 spot in total PV installations with 23 percent growth over last quarter. Other movers and shakers on the state rankings list include Nevada (moving from 17 to 5) and Vermont (from 21 to 12).
Looking at the U.S. solar market on the whole, U.S. Solar Market Insight: Q3 2013 forecasts nearly 5 gigawatts of PV and CSP will be installed during 2013. Installations have already surpassed the 10 gigawatts cumulative benchmark, and by the end of the year more than 400,000 solar projects will be operating across the country.
Key Report Findings
About U.S. Solar Market Insight®:
U.S. Solar Market Insight® is a quarterly publication of the Solar Energy Industries Association® (SEIA)® and GTM Research. Each quarter, we survey nearly 200 installers, manufacturers, utilities, and state agencies to collect granular data on photovoltaic (PV) and concentrating solar. This data constitutes the backbone of the U.S. Solar Market Insight® report, in which we identify and analyze trends in U.S. solar demand, manufacturing, and pricing by state and market segment. We also use this analysis to look forward and forecast demand over the next five years. As the U.S. solar market expands, we hope that U.S. Solar Market Insight® will provide an invaluable decision making tool for installers, suppliers, investors, policymakers and advocates alike.
EnerNOC (Nasdaq:ENOC) has formed a joint venture with Marubeni Corporation to license its DemandSMART application in Japan.
The new company, EnerNOC Japan, KK was awarded a government-sponsored demand response program with the Tokyo Electric Power Company (TEPCO).
The agreement heightens the competition for demand response market share in Japan, even though it is still early days. Japan’s utilities have turned their attention to demand-side management as the industry continues to contend with generation limits in the wake of the March 2011 Fukushima nuclear disaster.
Earlier this year, Comverge established a research and development facility in Japan and the OpenADR Alliance has also established a toehold to make the OpenADR standard the default communications standard as demand response is built from the ground up in the country.
EnerNOC’s partner Marubeni is one of Japan’s largest trading firms, with annual revenues of more than $50 billion. It owns more than 10 gigawatts of power generation and is one of the largest independent power producers in Japan. EnerNOC Japan, KK is expected to be incorporated by January 2014.
"There is growing national attention in Japan on intelligent buildings and smart grids, and an increased focus by utilities and policymakers on the importance of demand-side management," David Brewster, president of EnerNOC, said in a statement.
The government is already pushing building energy management systems out of the lab and into building stock, according to a report from GTM Research, The Smart Grid in Asia, 2012-2016: Markets, Technologies and Strategies. The market for residential energy management alone could be worth more than $2 billion by 2015, GTM Research found, with the potential for the commercial market being far larger.
For EnerNOC, the focus will be on commercial and industrial load shedding and demand-side management. The project with TEPCO, which is sponsored by the Japanese government's New Energy Promotion Council, will be one of the first deployments of aggregator-based quick-response demand response, according to EnerNOC. The resources will provide both peaking capacity and load-balancing services to TEPCO.
The project will be EnerNOC’s first overseas project using OpenADR dispatch. OpenADR uses an automated signal that can be measured and verified in real time to dispatch demand response. Details on how many megawatts the contract will cover were not disclosed.
Earlier this year, the Japanese OpenADR Alliance hosted workshops; the group already includes many prominent Japanese companies, such as Fuji Electric, Toshiba, Hitachi and Mitsubishi. The adoption of OpenADR is not surprising, as Japan already has a highly automated and advance electrical grid.
EnerNOC is not the only demand response company working with TEPCO. Schneider Electric and Energy Pool, in which Schneider owns a majority stake, partnered with Japan’s Sojitz Corporation recently to set up a 50-megawatt industrial demand response pilot. The project between TEPCO and EnerNOC is scheduled to begin in January.
One of the big questions about scenarios for 100 percent renewable energy production is how to structure the energy market. We now know that having electricity supplied to a major economy entirely by renewable energy sources is possible, and most likely no more expensive than building new fossil-fuel generation.
What we don’t know is how to structure the energy market so it provides the right incentives. If the marginal cost of solar and wind energy is close to zero (because there is no fuel cost), then the energy price in a 100 percent wind and solar market is going to be zero -- at least in the current market structure. But who would invest?
This is one of the major questions being put to regulators and policymakers around the world, but the country most in the firing line is Germany, one of the world’s most successful industrial nations.
It’s not that Germany is about to arrive at 100 percent renewables any time soon. But the penetration of renewables (now above 25 percent) is getting to the point where the current energy market, based around the cost of fuels, is no longer functioning as it used to. And by the time the country gets to 40 percent by 2020, and close to 60 percent soon after 2030, this will be a critical issue.
Some analysts, such as Macquarie Bank, have described the energy market as already broken, and there is no doubt that fossil-fuel generators are reeling because their coal- and gas-fired plants no longer make the profits they once did. German regulators and policymakers concede that their energy markets need to be redesigned.
How they do that is going to be one of the big tests for Germany’s Energiewende, the transition from a largely centralized baseload generation system with lots of nuclear to one based around renewables. And it is going to be one of the big challenges of the new “grand coalition” between Angela Merkel’s center-right CDU and the left-of-center SPD, which has its base the coal-rich regions of northern Germany.
What is decided and achieved in Germany will likely have a significant impact on the pace -- and ambition -- of renewable energy schemes in other major economies.
Still, despite the clamoring of the incumbent industries to have capacity mechanisms introduced into the market, the German policymakers appear to be in no hurry to indulge them. The recent treaty between the two main parties provides for no capacity mechanism before 2018, by which time the share of German renewables may well be close to one-third of total demand.
It could be that Germany is looking for the survival of the fittest. “I would be very, very careful not to jump into capacity markets too early,” says Andreas Loeschel, who heads a government-appointed expert committee looking into the energy transition process. Loeschel is also based at the Centre for European Economic Research (ZEW), and is also professor of economics at the University of Heidelberg.
“We don’t need [capacity markets] at the moment,” he said. “We have excess capacity, but maybe it is something for the future.”
Rainer Baake, a former permanent secretary to Germany’s Minister of the Environment and now head of an energy industry think tank called Agora Energiewende, says some form of capacity market in the future is inevitable, but it is likely to be a mechanism that allows maximum flexibility and thus encourages not just baseload generators but other enabling technologies such as energy storage, demand management, smart grids, or whatever else is needed to deliver flexibility in a market with high renewables penetration, as well as the potential for large amounts of “prosumers," that is, households and businesses that can generate their own electricity.
“We need markets where different answers to the problem are able to compete with each other, and we need more flexibility in the system,” Baake said in a recent interview in Berlin.
“A few years ago, we thought we would have an energy-only market and everything would be fine. Now we are looking at what sort of market we should introduce and when the right time to introduce it will be.”
It likely won’t be a simple capacity market, where generators receive payments simply for the ability to provide output on demand, even if it is rarely used, as is the case in Western Australia. It is more likely to be a sort of “capabilities” market, a more refined version that reflects environmental and other qualities. It’s just the name “capabilities” market hasn’t caught on yet.
This transition seems to be accepted by the two biggest generation groups in Germany, RWE and E.ON, which are both now talking of a move away from centralized generation and towards distributed systems, where consumers produce a lot of their own energy and the role of utilities is to provide security of supply, added value and services to those “prosumers.” (See this interview with E.ON’s chief executive and the recent insight into RWE’s new strategy for more information.)
Of more immediate concern to the German regulators, however, is the question of how to manage the cost of this energy transition, as well as the cost of what has already occurred in the form of feed-in tariffs.
Loeschel says Germany as a whole is paying the same percentage of GDP (2.5 percent) on electricity costs as it did twenty years ago. The problem is how these costs are distributed. Because many industries are exempted from it, the retail consumer has borne the brunt of the EEG, which is the tariff assigned to fund green energy support schemes,
The irony is that as the amount of wind and solar has increased, the price of wholesale electricity, on which many energy-intensive industries' costs are based, has fallen by nearly half. Furthermore, because of the way the EEG has been structured, a reduction in the wholesale price results in an increase in the EEG tariff paid by consumers. According to Loeschel, this has allowed complaints about rising electricity bills to be exploited by those who want to slow down the progress of the Energiewende.
But as Baake points out, no party that had espoused an Energiewende slowdown as its official policy won any seats in the German parliament in the recent elections. The grand coalition has also rejected any talks of retrospective changes in tariffs. Indeed, it has actually increased and expanded the renewable energy targets out to 60 percent by 2035 -- although some people say the country could achieve more, and that this in fact represents a slowdown.
Still, these costs need to be capped. One of the driving forces behind the campaign against the Energiewende is that industry fears it will lose its recent favorable treatment and energy discounts. “The people who are complaining the most are actually better off than they were a few years ago,” said Loeschel.
Baake’s Agore Energiewende has come up with its own solution, as illustrated by the graph below.
The diagram is designed to illustrate how to get to 40 percent renewables with minimum cost. This requires a total of 240 terawatt-hours of renewable production, out of total grid demand of 600 terawatt-hours. The vertical box on the left, EEG 1.0, represents the costs of tariffs already committed. Baake says this is around 17 euro cents per kilowatt-hour. That, he adds, was the cost of Germany’s learning curve, and it is locked in until 2020, when it will start to decline as the first tariffs expire. There is no talk of retrospective cuts, so the big question is what to do in the future.
Baake proposes something called EEG 2.0. Having installed 160 terawatt-hours of renewables at an average of 17 cents per kilowatt-hour, he suggests a cap of 8.9 cents per kilowatt-hour for new renewable installations. This is nearly half the cost of EEG 1.0 and is highly significant, because from now on it means that whatever Germany invests in, be it fossil fuels or renewables, the energy costs will be the same. “We are at a turning point in the cost debate,” he says.
However, to encourage enough fossil fuel or balancing capacity to remain in the market, Baake proposes the capacity measures mentioned above. Right now, though wholesale power prices are at 3 cents to 5 cents per kilowatt-hour, many plants need higher returns to ensure positive cash flows. This could come from some form of capacity premiums.
Of course, the incumbent fossil fuel industry would like that light blue rectangle to be bigger and broader, but Baake says it is important for this part to be controlled. Many see this as the biggest threat to the development of the Energiewende.
Loeschel is happy to see a shakeout in the market. “The wholesale price has probably dropped a little too far. But this will change if we allow capacity to go out of the market. The larger companies try to bribe policymakers by telling them they are going to shut down power plants. We should now allow that.”
But, he conceded, changes are needed. His proposal is to create “mini markets” that would result in capacity being installed where it is most needed, and maybe overcome Germany’s principal problem of having a lot of generation located far away from the main areas of demand.
“I’m very confident about the future of the Energiewende,” he says. “This is a long-term project and an important one for Germany. We should not throw this whole thing out just because we have some problems in the first few years.”
Arizona's solar net metering conflict may be over until the next rate-setting process. But the state is only at the beginning stages of dealing with disruptive energy technologies.
Along with a renewed focus on how to structure solar promotion policies in 2014, Arizona regulators may take a wide-ranging look at how energy storage, home energy management, microgrids and high penetrations of distributed generation will impact how power companies deliver service to customers.
It seems Arizona may be ready to embrace the grid edge -- in concept anyway.
Last week, Arizona Corporation Commissioner Bob Burns issued a letter calling for a series of workshops over the coming year on "innovations and technological developments" in the electricity sector that will change utility business models. In his letter, Commissioner Burns implied that net metering is just the warm up act for what utilities will have to deal with in the coming years.
"The proposed scope of this docket is to review the following major innovations and technological areas that appear to have the greatest potential to impact the current energy utility model," wrote Commissioner Burns.
Here are six of the technology and service areas outlined in the letter.
1. Distributed Supply and Storage Resources Enabling Customer Self-Supply: Includes any distributed supply resources (solar technology, fuel cells, etc.); distributed storage devices (battery, flywheel, thermal storage, etc.); and customer shared generation (virtual net metering, etc.)
2. Customer Load Management Technology, Energy Efficiency, Major New Loads and Related Services: Includes customer energy information systems, demand controllers, real-time pricing controls, plug-in electric vehicles, demand response, and alternative services arrangements for customer energy management, etc.
3. Utility-Scale Solar Technology: Includes pumped storage (hydro, compressed air) battery, flywheel, etc.
4. Metering Technology and Services: Includes electronic meters, communications systems (one-way, two-way, real-time), alternative arrangements for meter reading, meter services, meter data management, etc.
5. Transmission and Distribution Automation: Includes real-time information access for situational awareness, real-time physical monitoring and manual control, automated technologies for system self-healing, etc.
6. Micro-Grids: Includes grid-tied and isolated.
Commissioner Burns played an important role in the recent compromise over net metering in Arizona. Although his proposal for a fixed monthly charge of $0.70 per kilowatt on solar systems was far lower than what Arizona Public Service wanted and a bit higher than what the solar industry wanted, it helped get an agreement passed.
Now Burns is preparing the Arizona Corporation Commission for a future that could bring many more difficult choices for regulators.
"We are excited to see that many of the topics at these workshops point to an energy future where customers are taking greater control of their energy usage and are active participants in the energy marketplace," said Annie Lappé, solar policy director at the Vote Solar Initiative, in response to the letter.
That may not excite a utility such as Arizona Public Service, which has long argued that solar is a drain on grid infrastructure. However, Lappé believes the convergence of technologies outlined by Commissioner Burns could create new opportunities to harden the grid and accommodate higher penetrations of solar.
"It is very strategic for the commission to study the ways in which resources like distributed solar could provide more benefits to the grid if coupled with storage and new customer load management technologies," said Lappé.
The battle over net metering could just be the start of utility disruption in Arizona. How effectively the state deals with coming changes depends on how the commission addresses new technology trends. These workshops are a start.
What’s the value of a conservation voltage reduction (CVR) system that can collect and analyze its own power data, adapt to changing grid conditions, and deliver insight into disruptive conditions and technologies at the grid edge?
That’s the question that investors in Utilidata are aiming to answer. On Tuesday, the Providence, R.I.-based company announced a $20.5 million Series B round, along with a new customer, new plans for international expansion -- and the potential to move beyond optimizing grid voltages toward a whole new range of capabilities.
Leading the round were Silicon Valley venture firm Foundation 8 Capital and Saudi Aramco Energy Ventures, the investment arm of the Saudi national oil company. Both investors are working on partnerships that could see Utilidata’s AdaptiVolt technology deployed in Asian grid markets, as well as supporting Saudi Aramco’s oil and gas power system, CEO Scott DePasquale said in an interview this week.
DePasquale confirmed that Utilidata has also launched a new project with National Grid, as reported by the Providence Journal newspaper on Saturday. The $500,000 project is testing the company’s capabilities in Rhode Island, with an eye on possible expansion to National Grid operations in other states, Timothy F. Horan, president of National Grid Rhode Island, told the newspaper.
Utilidata also confirmed that long-time customer American Electric Power (AEP) is an investor, joining Braemar Energy Ventures in Tuesday’s round, along with a Series A round in 2012, which brings the company’s total capital raised to $25 million. AEP has piloted Utilidata’s CVR technology since 2009 as part of the utility’s stimulus-funded GridSMART project, and in late 2012 announced a research and development agreement to expand their work together.
In this week’s interview, DePasquale expanded on the nature of that work. In simple terms, the partners are building on Utilidata’s core expertise in monitoring, adjusting and optimizing distribution grid voltages, with the goal of building a set of additional applications for distribution grid management, ranging from monitoring the effects of distributed solar PV on distribution circuits, to putting the data collected by the system to use in grid analytics.A Different Approach to Fine-Tuning Grid Voltage for Efficiency
“We’re creating new data, because we have a very low-cost way of lighting the feeder up,” he said. In simple terms, Utilidata relies on networking existing voltage regulators and other voltage management devices on distribution circuits, connecting them to industrial-grade computing hubs at substations or distribution operation centers, and actively managing those systems via digital signal processing, which measures and analyzes the electricity flowing along those circuits every couple of seconds.
That’s a different approach than model-based CVR systems that rely on static representations of grid electricity flows to adjust voltages. It’s also different from automated systems that deploy preprogrammed devices that autonomously react to changes on the circuits they’re connected to, he said.
Utilidata’s approach relies on existing grid gear to do its work, as well as using robust dedicated communications networks to actively collect, analyze and react to changes across the devices it’s managing. But once it’s in place, the system should also deliver more flexible control and finer-grained orchestration of the multiple devices it’s managing, with commensurate advantages over alternative architectures.
Utilidata claims this can achieve voltage reductions 25 percent to 50 percent better than competing schemes, which can more than double the net present value of systems that strive to reduce over-voltages by between 2 percent to 5 percent across entire distribution circuits to save energy or reduce peak loads. It can also deliver a 30 percent reduction in the operation of load tap changers (electromechanical devices that automatically react to line voltage changes and which can wear out much more quickly under these new stresses) compared to other CVR schemes.
In fact, customers including the Bonneville Power Administration (BPA) and Baltimore Gas & Electric have deployed Utilidata’s technology, not to perform CVR, but solely to monitor the performance of other vendors’ CVR systems, DePasquale noted. Since 2003, Utilidata has also deployed CVR for Hydro Ottawa and Veridian in Canada, for AEP companies AEP Ohio and Indiana-Michigan Power Co. and the rural Flathead Electric Coop in the United States, and Pacific Northwest non-utility clients like lumber mills and universities, with a total of 160 distribution feeders across North America.Building on Grid Insight for Applications Beyond CVR
All of this leads to Utilidata’s new plans, said DePasquale, a former GE Capital SVP and current partner at Braemar. Prior to joining Utilidata in February 2012, DePasquale spent eight months working with AEP, where he was introduced to Utilidata’s work with the utility, as well as the potential for expanding its data collection and DSP analysis to a whole new set of grid needs.
For example, Utilidata discovered that on distribution circuits where it was deployed, “we could tell AEP when solar was hitting their grid way before they knew it,” he said. Distributed, customer-owned solar is a significant challenge for utilities, and technologies that can measure its real-time impacts and adjust the grid accordingly could play a significant role in helping to manage that challenge.
The same approach could help utilities measure and predict the impact of a whole range of distributed resources -- plug-in vehicle charging, demand response, energy storage, and the like -- on distribution grid asset maintenance and planning decisions, he said. AEP is a noted leader in IT-based asset management with its Asset Health Center project, and many other utilities are striving to collect and interpret data from legacy systems and new smart grid systems alike to optimize their operations and planning processes.
Utilidata’s fine-grained grid power data could also be applied to a wide range of data analytics purposes, he added. While he declined to go into details, he did say that the company expected to be making announcements on this front as early as next month.
“Our system is working in real time,” he said. “We’re taking signals from the circuits every so many seconds, and can see and interpret many different types of behavior. You could imagine, then, if you’re characterizing all this information on a regular basis between the substation and the home, the impacts of the fidelity at which you make these decisions impacts the grid itself.”
Lots of utilities are turning to smart meters, grid sensors, advanced inverters and other grid-edge devices for data to analyze and convert into valuable information. The difference with Utilidata’s approach, DePasquale said, is that it’s seeking to layer its data analytics potential on top of a system that already offers a clear-cut return on investment on its CVR potential. “It’s kind of a Trojan horse approach, with more to follow on the innovation side,” he added.
In some ways, Utilidata’s approach represents the reverse of another method of managing distribution grid voltages, one that’s growing in popularity. That’s the concept of using already deployed smart meters (AMI) as data collection and monitoring points for CVR. More than ten projects across the U.S. are using AMI-supported CVR systems, with Dominion Voltage Inc.’s solution playing a role in several deployments, along with distribution grid technology providers including Survalent, Efacec and Leidos, and AMI vendors including Silver Spring Networks, Sensus, Elster, Landis+Gyr and Tantalus.
AMI represents a piece of Utilidata’s approach as well -- for instance, it’s working with Silver Spring Networks on its AEP Ohio projects, a partnership that could continue to grow under the utility’s proposed $290 million expansion plan. But Utilidata has also “been able to show we can outperform folks using AMI, before we use AMI,” DePasquale said. “We can deploy voltage optimization, and get many benefits out of our enhanced ability to monitor the grid, with much-reduced risk.”
Claims like these are sure to undergo close scrutiny by utilities like AEP and National Grid, which are the first customers to look into deploying Utilidata’s new array of services beyond CVR. At the same time, new technologies, such as the power electronics systems being developed by startups like Varentec and Gridco, are laying claim to even more fine-tuned control of distribution grid voltages.
All of these startups will have to contend with established CVR offerings from grid giants such as Alstom, Siemens, Schneider Electric, General Electric, S&C Electric Co., and others. Of course, competitors like these can also end up being partners. With CVR remaining one of the more attractive options for utilities seeking to meet efficiency targets, extend the capacity of generation resources, and manage the growing instabilities on the edge of the grid, stay tuned for emerging technologies to be put to the test.
It’s inevitable: any article that mentions increases in renewable energy capacity, be it wind or solar, will be met with a smart-aleck comment that renewables don’t operate at capacity and therefore are inferior.
Of course, the fact that renewables are variable producers is taken into account when assessing their value, and, it should be noted, even fossil-fuel plants don’t operate at 100 percent capacity on an annual basis. Still, installed capacity, while important, is of limited value and in the end, it’s generation that counts (along with when the power is generated, but that’s another story).
So, courtesy of the National Renewable Energy Lab’s Renewable Energy Data Book (PDF), here are some charts that show the progress of solar and wind capacity and generation in the United States. First, wind:
Source: National Renewable Energy Lab's 2012 Renewable Energy Data Book
To put the 2012 total generation (140,089 gigawatt-hours) into perspective, that’s 3.4 percent of all the electricity generated in the United States in the year. Doesn’t sound like that much, but a decade ago, it was barely a few tenths of 1 percent.
Source: National Renewable Energy Lab's 2012 Renewable Energy Data Book
The 12,775 gigawatt-hours of solar pumped out in 2012 made up just 0.3 percent of total electrical generation in the year. But here’s the hopeful thing: it was also 74.3 percent more solar generation than in 2011. And with the price of solar becoming more competitive, there’s every reason to think that high growth rates can be sustained.