By Tuesday morning, more than eight million people were left without power after Hurricane Sandy churned water onto roads, tunnels and into homes and businesses across the East. Substations exploded in New York City. Atlantic City was inundated. Trees went down across Delaware, Pennsylvania and Connecticut.
In New Jersey, the hardest-hit state, about two-thirds of utility customers were without power as of 9 a.m. on Tuesday. With a storm of this magnitude, power outages are unavoidable. Trees will always go down. In New York City, which has the bulk of its system underground, floodwaters put significant portions of ConEd’s grid at risk.
The question for companies and utilities pushing the envelope of technological innovation is how much investment in smart grid can help at a time like this.
As Greentech Media reported on Monday, state-of-the-art outage management systems and self-healing feeders can mitigate damage and limit the spread of power loss to some degree, depending on the damage. But Consolidated Edison, which serves New York City, called the extent of damage “unprecedented.”
Another solution is for utilities to use sophisticated analytics to look forward, rather than just using historical data to inform storm response, especially with the increasing frequency of unprecedented storms.
Far before Sandy was a low-pressure system in the ocean, IBM started thinking of all the data being generated from increasingly sophisticated grid components, such as smart meters and sensors on the grid, and how that data can be maximized for operations.
To study and commercialize applications, IBM just launched a Smarter Energy Research Institute, which will be a collaborative model between different utilities to use data for analytics that are both “predictive and prescriptive,” said Allan Schurr, vice president of Strategy & Development for Energy & Utilities at IBM.
He noted that utilities that are already pushing the envelope are looking at even more advanced techniques. The Institute, referred to as SERI, will bring together IBM Research experts in mathematical sciences, computer science and high-performance computing with engineers from member utilities. The three founding members are Hydro-Quebec (Canada), Alliander (Netherlands) and DTE Energy (U.S.). IBM started by asking utilities which type of predictions they are looking for and came up with five distinct categories.
The first category is outage planning, which includes planned and unplanned work. In the case of maintenance, for example, algorithms can find patterns of heat-based overloading in transformers to help utilities make decisions about when to replace them.
When it comes to outages, predictive analytics can inform crews about where to be staged, or better model how underground or overhead lines respond to environmental factors. For utilities that are investigating distribution automation projects, Schurr said that analytics can help identify how much and where to make the investment.
IBM wouldn’t speculate on how such analytics could have impacted the utilities reeling from Sandy, but analytics that could be used to model weather situations in conjunction with historical data are needed. “We have a 100-year storm every two years now,” New York Governor Andrew Cuomo said after the storm.
At SERI, analytics will also be tested in asset management optimizations. “We’re using more sensory information to target condition-based maintenance more accurately,” said Schurr.
For utilities working with the SERI, findings will be shared, and there are production systems so that members can move the technology from pilot to implementation. The process of collaboration might not completely negate the need for a pilot to test analytics with legacy systems, but “the close collaboration at SERI will take some of the unknowns that accompany a technology that may be proposed and make it more familiar from the beginning,” said Schurr.
The Institute will also have projects in a few additional areas, including integration of renewables and distributed energy, wide-area situational awareness and analytics that will look at demand-side management to better match demand response with localized needs.
Many of these analytics, when commercialized, could be cloud-based, although some, like real-time situational awareness, would likely require server investments.
IBM is hardly the first to see the growing need for sophisticated analytics to crunch the data coming off of smart grid investments. Southern California Edison has a laundry list of partners, including Boeing, General Electric and Space-Time Insight, for a project that will test the interplay of smart grid systems with everything from distributed generation to electric vehicles.
Meter data management companies are also looking beyond simple meter applications into far more sophisticated analytics that can inform operations, customer relations and business processes.
IBM expects to add more utilities to the Institute later this year and into 2013. “The time was right for us to find clients that wanted to push on those envelopes together,” said Schurr. But it is still early days, and while the investment might not pay off in 2013 or even 2014, IBM hopes the focus on data analytics will pay off as sophisticated utilities become the norm instead of the exception. “We see this as a very long-term opportunity.”
Because of the continued haggling over net energy metering (NEM), PV solar’s most fundamental incentive, GTM Research brought together an advocate and a utility representative to debate the policy at its U.S. Solar Market Insight Conference.
Pacific Gas and Electric (PG&E) (NYSE:PCG) wants its RPS-required renewables portfolio and rooftop residential to grow, according to PG&E Director David Rubin. But “as the industry moves from a relatively nascent one to one that is mature, it is appropriate to take a careful look at incentives available for customers who install rooftop solar systems.”
PG&E’s decoupled regulatory environment, Rubin explained, leaves earnings unaffected by increased solar. But “a combination of NEM, where a customer can spin their meter backwards at the full volumetric rate, combined with our residential rates, which at this point bear no real resemblance to costs, creates a potential problem for our non-participating customers. I am not here to condemn NEM.”
It is the underlying rate design, he explained. Rates “are steeply tiered. At the margin, our customers are paying $0.30 to $0.34 per kilowatt-hour.”
A typical PG&E solar customer, consuming 1,000 kilowatt-hours per month, has an average rate of $0.23 per kilowatt-hour. By PG&E’s calculation, its avoided cost, he said, is about $0.07 per kilowatt-hour.
The California Public Utility Commission (CPUC) market price referent, he added, is around $0.10 per kilowatt-hour. “Somewhere between those two numbers is the correct reflection of how much we avoid when a customer installs solar,” he said. “The difference between that and $0.23 ends up being shouldered by our other customers.”
“You need to look at the costs and benefits of net metering,” responded Keyes, Fox and Weidman Partner Jason Keyes, whose law firm represents the Interstate Renewables Council (IREC), a nonprofit advocate for fair utility pricing.
Costs and benefits vary from utility to utility, he said, and from market to market. “In the residential market, the average is $0.23 per kilowatt-hour and often in the $0.30 range,” he explained. “But two-thirds of the market for net metering is the non-residential sector.” Because that market pays demand charges as well as energy charges, he said, its solar use is a benefit to utilities.
“We agree with how the CPUC has handled the costs and benefits of net metering,” he said. “You don’t want to look at net metering generation going to onsite power. You just want to look at the excess.”
And, he said, any subsidy imposed on ratepayers due to the tiered rate structure is “not a cost of net metering -- that’s a cost of that tier system.”
The biggest cost of NEM, Keyes agreed, is the rate. But “the $0.23 is a revenue reduction. The utility isn’t actually paying me $0.23 per kilowatt-hour when I generate electricity. It gives me a kilowatt-hour in the middle of the night.” He rejected the idea of administrative costs because advanced meters should eliminate them, but he accepted there are interconnection costs.
“On the benefit side, the biggest thing is capacity,” he said. Solar adds to a utility’s generating capacity, saving it the costs of purchased peak demand sources.
“I agree our commercial industrial rates are pretty well-designed rates. That is not where we have an issue,” Rubin replied. But “there is strong rationale to design residential and small commercial rates where the revenue and costs match each other much better.”
Rubin said a CPUC study required including both power consumed onsite and exported power. Keyes said that was only because it was legislatively mandated and the CPUC has publicly stated it will focus on exported power.
“I do agree residential will tend more toward a subsidy than commercial,” Keyes acknowledged. But “an E3 study said the rate impact of NEM is fairly modest.” And since tiered rates have flattened since that study, he said, “any subsidy the upcoming E3 study finds should be even more modest. And I would expect it, like the first one, to again find a net benefit on the commercial side.”
Debate moderator and GTM Research Vice President Shayle Kann asked Rubin if a rate structure fix could make NEM acceptable.
“One of the most straightforward things,” Rubin answered, “would be to flatten the rates.” A fixed charge similar to that imposed by the Sacramento Municipal Utility District of perhaps $25 to $30 per month could be an alternative. Or utilities could add demand charges for residential customers.
“There is a commission proceeding on the California IOUs’ residential rates,” Rubin said. If the rate issue is not resolved, NEM customers might be stripped of their exemption “from charges that other types of distributed generation customers pay because they don’t have the same exceptions NEM customers have.”
Social policy underscores the question of “what you would be willing to pay for your neighbor to reduce their bill,” Rubin said. Upward pressure on PG&E rates from the state’s RPS will likely add 10 percent by 2020. “To the extent that NEM adds additional upward pressure, which we believe it does, the question is whether that is an acceptable cross subsidy within our customer base.”
“The current structure of net metering works pretty well,” Keyes said. “For most utilities, there is a benefit.” Eventually, he added, "utility peak demand will shift to later hours and the benefit of net metering won’t be there. But that point is a long way off.”
The California Public Utilities Commission (CPUC) voted unanimously on October 25 to approve revised power purchase agreements (PPAs) between BrightSource Energy (BSE) and Southern California Edison (SCE) (NYSE:EIX) for electricity generated by one 250-megawatt unit of BSE’s proposed 500-megawatt Rio Mesa solar power tower project and one 250-megawatt unit of its proposed Sonoran West tower project. The CPUC also rejected three proposed BSE-SCE PPAs.
The rate designated by the renegotiated PPAs for purchase of the power is confidential. "Edison negotiated hard on behalf of their customers," BSE Government Affairs VP Joe Desmond said, “and got a significant increase in value and decrease in cost.”
The CPUC-approved PPAs lock in an estimated annual generation of 573 gigawatt-hours from each facility “for a term of twenty years with the option for SCE to extend the term to 25 years.” According to BSE, design specifications call for Rio Mesa to produce at least 573 gigawatt-hours per year and for Sonoran West, with storage, to produce at least 733 gigawatt-hours per year.
The revised PPA for Rio Mesa provides for BSE’s planned deployment of its second-generation technology. It will have a 250-foot-taller tower than in the first-generation, 372-megawatt Ivanpah plant now under construction, allowing for a more concentrated arrangement of heliostats that will reduce the land required to two-thirds of that needed for a comparable photovoltaic (PV) or power tower project.
The revised Sonoran West PPA provides for incorporation of the newer technology, as well as the first deployment of BSE’s steam-heated molten salts storage system. Stored generating capacity will give Sonoran West more production capacity and the flexibility to serve the grid in ways that help balance transmission system supply and demand and make electricity delivery more reliable, functions more typically associated with traditional power plants.
The CPUC-approved PPA calls for Sonoran West to have “a few hours” of generating capacity “when the thermal storage system has been charged and the sun is not shining.”
Perhaps most importantly, Rio Mesa and Sonoran West won PPAs despite not having Department of Energy loan guarantees. They will be the first U.S. concentrating solar power (CSP) projects built with only marketplace investment, state incentives, and the federal investment tax credit (ITC).
According to BSE, the contracts represent billions of dollars in direct investment and more than 2,000 construction jobs for California’s economically stressed Inland Empire region.
Of the rejected PPAs, Hunter explained, BSE planned in 2009 for seven contracts but, with the addition of storage capability in November 2011, one of the PPAs became extraneous, and Ivanpah’s PPA with SCE was previously finalized, along with two Pacific Gas and Electric (PG&E) (NYSE:PCG) PPAs. That left five pending at the CPUC.
“One of the two units at Rio Mesa was approved and one was denied. And the one unit at Sonoran West was approved,” Hunter said. “Two others at the planned Siberia site were denied.”
The CPUC’s concern was the ability to facilitate projects that move California toward its 33 percent renewables by 2020 goal, Desmond explained. This is “a workable plan that could be done, taking into account the need for deliverability, and including transmission and constructability, in time for qualifying for the ITC.”
The other three PPAs were unlikely to be fulfilled by the end of 2016, when the ITC will drop from 30 percent to 10 percent. “For a variety of reasons,” Desmond said, “but it comes down to transmission.”
BSE will continue working through the planning and permitting processes for the other sites. “We are talking to other utilities,” Desmond said. “Over time, people drop out of certain transmission queues. That changes which projects may be advanced.”
The first twenty-two megawatts of the 250-megawatt California Valley Solar Ranch (CVSR) project, owned by NRG Energy, Inc. (NYSE: NRG), created approximately 350 jobs since construction started in September 2011 and is expected to add $315 million to the San Luis Obispo County economy over its two-year construction period.
CVSR, which will be one of the biggest PV solar plants in the world, has a 25-year PPA with PG&E. The full 250 megawatts are expected to be on-line by December 2013. Engineering, procurement and construction (EPC) for the SunPower designed project is being handled by Bechtel.
A 13.78-megawatt PV system at Naval Air Weapons Station China Lake, the U.S. Navy’s biggest solar installation, will generate over 30 percent of the facility’s annual energy load and cut its power costs an estimated $13 million over twenty years. It will use “SunPower's high-efficiency, Buy American-compliant solar panels,” SunPower reported, and SunPower’s modular solar power block that incorporates its tracker, cabling, inverter and operating system.
The facility’s MetLife (NYSE:MET) affiliate-owned, Navy-hosted and SunPower-designed, -built and -maintained system is backed by the first no-upfront-cost 20-year PPA through the Defense Department’s long-term energy procurement authority (US Code Section 2922A). It will allow the Navy to get electricity at up to 30 percent below present rates.
The 25-megawatt McHenry Solar Project, built for K Road under a Modesto Irrigation District contract, brought an estimated 100 construction jobs to the economically stressed Stanislaus County region.
Bankrupt battery maker A123 has a lot of demands on its time nowadays. While U.S. giant Johnson Controls and Chinese giant Wanxiang compete over the Department of Energy-backed lithium-ion battery company’s existing business assets, one of its key customers, Fisker Automotive, wants the whole process slowed down.
Those are some updates from the ongoing legal battle over the Waltham, Mass.-based company’s remains in U.S. federal court in Wilmington, Del., where the struggling company filed for bankruptcy protection two weeks ago. The key struggle appears to be between Johnson Controls and its $125 million offer for A123’s automotive battery business (and DOE-grant-funded factory in Michigan), and Wanxiang, whose $465 million bailout offer in August still remains on the table as far as the Chinese automotive equipment manufacturer is concerned.
The latest on that front appears to put Wanxiang in the lead. According to news reports, A123 has asked the court for permission to tap a $50 million loan from Wanxiang, supplanting a competing offer from JCI to provide its own debtor-in-possession loan. Wanxiang’s 12 percent offer beat JCI’s 15 percent offer, the Wall Street Journal reported. JCI had previously won court approval to provide $15.5 million of a planned $72.5 million in in debtor-in-possession financing as well, but according to The Washington Post, the Milwaukee, Wisc.-based industrial controls giant backed out to avoid a legal fight.
A123 CEO David Vieau said in an earlier statement that the company had scrapped its Wanxiang deal “as a result of unanticipated and significant challenges to its completion,” though he didn’t specify the challenges involved. But it’s clear that the idea of a Chinese company taking over taxpayer-backed U.S. technology won’t sit well with a Congress already investigating the company’s outstanding loan agreement with the DOE. Wanxiang’s structured deal with A123 did involve it retaining access to the $249 million Department of Energy stimulus loan that’s helped build A123’s factory in Livonia, Mich., as well as ownership of A123’s intellectual property.
What’s A123 worth? Measurements vary. The company had $459.8 million in assets and $376 million in debt as of Aug. 31, according to bankruptcy filings. Certainly its Monday afternoon market capitalization of $23.1 million, compared to post-IPO highs of more than $2 billion, is a sad reminder of the destruction of a lot of investor capital. But its ongoing automotive battery business could offer competitive products to whomever buys it. The same goes for its grid storage business -- 24 percent of its total revenues come from grid partner AES, according to bankruptcy filings.
As for how that business is divided up, that’s up to the courts and its competing parties with an interest in the business. That includes also-struggling Fisker Automotive, which accounts for more than a quarter of A123’s revenues. On Friday, Fisker’s lawyers asked the court to delay the A123 sale process for another 30 days, though the company didn’t specify what it hoped to do with the extra time.
Here’s our ongoing coverage of the A123 bankruptcy and its financial and political fallout:
We’ve already seen the inevitable comparison to bankrupt solar company Solyndra, which took a $535 million loan guarantee from the Department of Energy only to go under last year. DOE-backed flywheel energy storage maker Beacon Power and thin-film solar startup Abound Solar have since declared bankruptcy as well, making A123 the fourth to get DOE cash, then go under.
A123’s fate is likely to be much different than Solyndra’s, which has seen its plant dismantled and its technology stranded. Obviously it has many suitors for its technology. Still, that won’t extinguish the political firestorm to come on A123’s crash and burn, of course. Congressional inquiries into A123’s remaining share of its DOE loan, as well as its relationship to struggling plug-in hybrid automaker (and key A123 customer) Fisker Automotive, have been underway for months.
Let’s start with the main stage. Mitt Romney’s campaign issued a statement on Tuesday calling the bankruptcy “yet another failure for the president's disastrous strategy of gambling away billions of taxpayer dollars on a strategy of government-led growth that simply does not work.” President Obama’s campaign fired back that Romney, as Massachusetts governor, had presided over state loans to companies that later defaulted on their debts.
On a less personal, but still political, note, a Department of Energy spokesman wrote in a blog post that Republican members of Congress had signed on as A123 supporters -- not surprisingly, both from Michigan, where A123’s plant was built with federal and state support.
DOE’s blog also stated that 100-mile-range batteries have dropped in price from about $33,000 before it started investing billions of stimulus dollars into the sector, to about $17,000 today. That’s on track to drop to $10,000 by 2015, DOE predicts. Of course, that’s based on a rosy projection for the advanced battery market, which DOE says is set to grow from $5 billion in 2010 to nearly $50 billion in 2020.
In large part, that’s tied to equally optimistic, official Obama administration goals to put 1 million plug-in vehicles on U.S. roads by 2015 -- a growth rate that is hard to imagine, given the fact that only 50,000 EVs have been sold so far this year.
Cost, Quality Struggles: Will GM Stick With A123?
Beyond the core problem of a slow-to-develop market, A123 may have faced struggles to compete on cost against its rivals, according to an analyst who spoke to Wired. Asian companies dominate the advanced battery market today -- South Korea’s LG Chem makes the batteries for GM’s Chevy Volt, Japan’s Panasonic makes Tesla Motors’ batteries, and the Nissan Leaf’s batteries come from a Nissan-NEC joint venture.
To be sure, A123 has a long list of EV customers, including General Motors, BMW, SAIC Motor Corp., Tata Motors and Smith Electric Vehicles. But Fisker was its main customer, with about 26 percent of A123’s revenue, according to bankruptcy filings -- and Fisker has been having its own problems as it strives to meet terms of its own $529 million DOE loan. Fisker was also the company that received A123 batteries that were subject to a mass recall this spring, a disaster that triggered A123’s spiral into bankruptcy.
It’s hard to predict how the proposed acquisition by Johnson Controls will affect those ongoing relationships. GM, which has tapped A123 to build batteries for its Spark EV, issued an official "no comment" on its Chevy Volt website on Tuesday as to whether it would continue using the bankrupt company’s batteries if the Johnson Controls deal goes through.
Price vs. Value for Domestic Green Technology Support
In the meantime, the company as a whole has lost a collective $1 billion over the course of its publicly-traded life, retaining $459.8 million in assets and $376 million in debt as of Aug. 31, according to bankruptcy filings. The company has seen its market value fall from a high of $2.3 billion shortly after its 2010 IPO to an estimated $8.2 million as of Wednesday afternoon, representing the destruction of a whole lot of capital.
At the same time, EV supporters were quick to point out that A123’s assets and intellectual property represent ongoing value for whichever company picks them up. “Government can help facilitate innovation, but the natural business cycle remains -- some failures in any emerging industry are inevitable," Jay Friedland, legislative director for nonprofit advocacy group Plug-In America, said in a Tuesday statement.
In that sense, A123’s bankruptcy is simply a fire-sale opportunity for consolidation into a growing industry, whether under domestic or foreign ownership. Johnson Controls got its own $299 million DOE advanced manufacturing grant in 2009 to build domestic manufacturing capacity for hybrid and electric vehicle batteries, and will be keeping jobs and intellectual property in the country if it takes over A123’s automotive business.
That means that federal investment into A123 -- and Johnson Controls, for that matter -- will be achieving its goals of creating jobs and fostering domestic technology innovation, the Information Technology and Innovation Foundation, a nonprofit founded and chaired by former Republican lawmakers, noted in a Tuesday statement.
“Through critical public investments in battery innovation by ARPA-E and DOE investments in next-generation battery manufacturing, the U.S. battery industry has made significant technological progress in a few short years,” the group noted. “And as shown by Johnson Controls purchase of A123’s manufacturing plants and technologies, it’s helped spur very promising technologies that U.S. industries will continue to use and build on.”
Whether or not U.S. manufacturing plants can compete on costs with Asian rivals is another question. Both A123 and rival lithium-ion battery maker Boston-Power have turned to building batteries in China with partners, both for low production costs and to serve China’s future market for electric vehicles.
Meanwhile, the fate of A123’s significant grid-scale battery business -- some 24 percent of its revenues came from grid storage partner AES, according to bankruptcy filings -- and other parts of the company remains unclear. Indeed, other bidders may emerge to challenge Johnson Controls for A123’s automotive battery business, which includes plants in Livonia and Romulus, Mich., a factory in China and its stake in a joint venture with Shanghai Automotive.
In the excitement over the news that all new U.S. electricity generation for September 2012 came from wind and solar, as reported in Federal Energy Regulatory Commission statistics, the bigger picture went less noticed.
The cumulative installed electricity generating capacity of wind is now up to 4.43 percent of the U.S. portfolio and, adding solar’s rapidly growing 0.29 percent piece, the two biggest potential renewables resources are at almost 5 percent (4.72 percent) of U.S. capacity.
Moreover, by adding in hydropower (8.51 percent), biomass (1.25 percent), geothermal (0.31 percent) and waste heat (0.07 percent), renewables now constitute almost 15 percent (14.86 percent) of U.S. electricity generating capacity.
Gone are the days when advocates for the traditional generation industries could dismiss renewables as playing an insignificant role, particularly since they constitute the bulk of new capacity coming on-line.
Two additional notes, one good and one not so good.
First the bad news: Wind is virtually dead for 2013. Uncertainty surrounding the renewal of its production tax credit has already put companies on hiatus, shuttered facilities and caused 10,000 announced layoffs. It will take twelve to twenty-four months to get the industry geared up and producing again even if, as insiders report, Congress will reinstitute the PTC after the upcoming election.
On the other hand, a slew of utility-scale solar power plants are expected to start bringing megawatts on-line next year. The NRG Energy (NYSE:NRG) and MidAmerican Holdings (NYSE:BRK.A) Agua Caliente project, the Exelon (NYSE:EXC) Antelope Valley Solar Ranch One project, the BrightSource Energy Ivanpah project, the SolarReserve Crescent Dunes project, and the Abengoa (MCE:ABG) Solana project all may help, along with others, take up the slack created by the congressionally mandated wind industry recession.
It does not take a crystal ball to see that what happens in 2014 depends on what happens November 6.
On November 6, Californians will cast their votes in a closely watched election. While most of the spotlight will focus on who wins the White House, the future of America’s clean energy future will, to a great extent, be determined by the fate of two ballot initiatives in California, Propositions 30 and 39.
The stakes could not be higher. Today, as a consequence of forward-thinking policies put in place in recent years, California has emerged as the incubator of the nation’s solar industry. Landmark legislation, such as the renewable portfolio standard which requires that 33 percent of the state’s energy come from renewable energy sources by 2020, has helped California lead the nation in clean energy job creation, innovation and investment at a time when our state has needed it most. The California Solar Initiative has helped create almost 200,000 rooftop solar energy systems on schools, homes and businesses around the state and reduce the installed cost of solar energy systems by 50 percent over the past five years. And California’s climate law, AB 32, is now getting under way, helping reduce pollution throughout the state.
But all this momentum could be in jeopardy without the passage of Propositions 30 and 39.
Proposition 39 fixes a corporate tax loophole that encourages corporations to locate employees outside California. By basing corporate taxes on California sales instead of California payroll, Proposition 39 will generate an extra $1.1 billion/year in revenues to California to pay for critical services including education. For the first five years, 50 percent of these new revenues would be dedicated to energy efficiency and clean energy projects on public buildings, helping to put solar panels on schools and creating up to 30,000 new jobs while helping schools lower their energy bills and reinvest that money in the classroom. Endorsed by business organizations like the Silicon Valley Leadership Group, San Francisco Chamber of Commerce and the Los Angeles Business Council, this initiative strengthens our local economy by fixing a loophole that unfairly benefits companies out of state, and uses the resources to invest in California’s future.
Proposition 30 was put on the ballot by Governor Brown to address California’s pressing deficits with a temporary 1/4-cent sales tax increase and personal income tax increase for the Californians earning over $250,000 per year. The majority of the funds generated under this measure would be devoted toward saving public education, the foundation for the future of innovation in California.
If it were to fail, the consequences for the growth of solar and other California renewable energy industries would be severe. There is simply no way California can compete internationally as a clean energy innovator if we let our public education system wither on the vine. Skyrocketing tuition and declining resources will make it harder for California to attract the best and the brightest students who will be the innovators of tomorrow. But if we succeed in passing Proposition 30, it creates a stable platform for new growth, and offers California a better chance to compete with countries like China, that have been investing billions in their renewable energy industry.
The choice facing Californians is clear.
We can continue to lead the nation forward toward a clean energy future or we can cede that leadership to other countries. Fortunately for us, the choice is ours to make on November 6. Vote yes on Propositions 30 and 39.
David Hochschild has worked in the solar energy field in California for 12 years. He is co-founder of the solar advocacy organization Vote Solar (www.votesolar.org) and currently serves as Vice President at Solaria (www.solaria.com), a California-based solar panel manufacturer.
At Connecticut Light & Power, most of the preparations for Hurricane Sandy have involved tree-trimming, lining up extra work crews and sandbagging critical substations that lie in the flood zone. The utility is aiming to have a far different outcome than one year ago, when an October snowstorm left 800,000 Connecticut residents without electricity. CL&P is hardly alone in its Hurricane Sandy planning.
Jersey Central Power and Light told reporters on Friday that outages from Hurricane Sandy could last more than a week. One computer model estimated more than 10 million people across the Eastern Seaboard will lose power as the category 1 hurricane slams into the coast close to a full moon. However, that model is built from looking at outages from previous hurricanes, so increasing smart grid technologies could help to dull the magnitude of that prediction.
Utilities from Virginia to Massachusetts are already reporting power outages, with more than 30,000 without power by one report. Connecticut Light & Power had about 7,700 customers without power Monday morning. Long Island Power Authority had more than 20,000 people in the dark midday Monday.
For utilities that have made smart grid investments, especially in distribution automation or smart meters, the technology could help identify outages more quickly or minimize the spread. But in the case of Hurricane Sandy, utilities are mostly highlighting more old-fashioned (but still critical) preparations, such as preparing crews, rather than toting high-tech systems that will improve restoration efforts or cut down on outages all together.
Earlier this month, EPB Chattanooga calculated it had saved $1.4 million during a single storm due to its investment in self-healing feeders. Pacific Gas & Electric is investing $360 million to add technology on its distribution grid circuits, which is expected to cut outages by 77 percent. Neither utility are in the path of Sandy.
After Hurricane Irene, Long Island Power Authority accelerated implementation of its new outage management system, which will put a real-time functionality on all of LIPA’s 980 feeders by the end of this year. Like New Jersey utilities, LIPA’s website warns that restoration could take seven to ten days. But if the new OMS is widely implemented, it could reduce restoration time. Atlantic City Electricity is also in the middle of a $37 million distribution automation project that could help isolate outages. For any utility that is investing millions of dollars, telling the story of success after big storms will grow increasingly critical.
But examples of smart grid investments changing the outcome of storms could still be few and far between. For some utilities, even minor investments, such as improved mobile apps to report and track outages, can make a difference in customer relations. Many utilities have found that Twitter and Facebook are powerful tools during outages.
At Vermont Electric Cooperative, just overhauling the utility's call center with updated technology and improving web offerings drastically cut down on angry customers. Dominion has its mobile outage app featured prominently on its homepage.
But just as this summer did not see prominent examples of end-to-end smart grid deployments coming to the rescue, Hurricane Sandy is likely to be the same. There may be individual examples of successes, but it is unlikely that the storm will be a turning point for an industry.
However, if there are widespread outages that last for days, as there were with Hurricane Irene and the derechos, regulators and angry utility customers may start to ask what else can be done beyond aggressive tree-trimming.
If nothing else, it should lead to even more streamline customer service offerings on web and mobile platforms.
The Document Diver of the Day Award goes to Kenneth Bossong, whose close reading of the Federal Energy Regulatory Commission’s September 2012 Energy Infrastructure Update [PDF] uncovered this tasty green morsel: Every megawatt of new electrical generating capacity installed in the United States in September was either wind or solar power.
Unfortunately, this doesn’t mean that coal and other dirty fuels (like natural gas, which, while better, isn’t clean) have packed up and gone home. Apparently, they just went on vacation in September, because in the preceding eight months, 4,587 megawatts of new natural gas capacity went into service, and coal came in with 2,276 megawatts.
image via Federal Energy Regulatory Commission
Still, that solar and wind swept the month is a sign of change -- and of more to come in the future if support for renewables is maintained, particularly on the wind front.
In September, five new wind projects, totaling 300 megawatts, went into service. That brought wind’s 2012 new-capacity total to 4,055 megawatts, ahead of last year’s January-September total of 3,239 megawatts, and it brought wind’s overall installed operating generating capacity to 51.07 gigawatts, which is 4.43 percent of total generating capacity.
The problem is, one of the big reasons wind is having a banner year is that developers are rushing to get their projects up and running before Jan. 1, 2013, because if they don’t, the projects won’t be eligible for investment tax credit or production tax credit. Under current law, both will expire when that giant ball comes down and the confetti flies in Times Square.
As for solar, that 133 megawatts figure was robust, representing more than 14 percent of the year-to-date’s 936 megawatts of solar -- and remember, we’re talking here about utility-scale projects only, not the thousands of distributed systems going up on residential and business rooftops all over the country. The biggest contributor was the Agua Caliente project in Arizona, where 50 new megawatts brought the plant total to 250 megawatts. It’s the biggest PV plant in the country, and by 2014 it will be up to 290 megawatts.
Such large-scale projects in the Southwest are becoming fairly commonplace under the Obama administration, but not all the sizable solar is happening in the desert. Here are some others that came on-line in September; they aren’t nearly as big as Agua Caliente, but each is impressive in its own way, as the FERC report notes:
- Zongyi Solar America’s 20-megawatt Tinton Falls Solar in Monmouth County, New Jersey, is on-line. Tinton Falls Solar is the largest photovoltaic project in New Jersey.
- Southern Sky Renewable Energy LLC’s 5.6-megawatt Canton Landfill Solar Project in Canton County, Massachusetts is on-line. This photovoltaic project is built on the closed and capped Canton Landfill. It is the largest solar facility in New England. The electricity generated is sold to the Town of Canton under a long-term agreement.
- SunEdison’s 3.6-megawatt Phase 2 Lakeland Regional Airport Solar Project expansion in Polk County, Florida is on-line. The Lakeland Regional Airport Solar has a total capacity of 6.3 megawatts. It is the largest photovoltaic project in Florida. The electricity generated is sold under long-term contract to Lakeland Department of Electric Water Utilities.
Shayle Kann, Greentech Media's VP of Research, kicked off a standing-room-only Solar Market Insight event in the San Francisco Bay Area.
Let's cut to the chase. Solar installations in the U.S. will total 3.2 gigawatts in the U.S. in 2012. That's a healthy 71 percent growth rate. "But the next couple of years are hard to call," according to Kann.
"We have a more sober assessment on 2013," said Kann, who sees close to 4 gigawatts in 2013, but like everyone in the solar industry, is waiting to see the impact of the ITC grant sunset. The upside is that "it's hard to imagine a down year for 2013."
Kann said that the U.S. market is "a rare source of strength in an extremely difficult" global market. "We expect to see a recovery in shipments now that the import tariff has been finalized."
Kann discussed the Chinese solar panel import tariff. He noted that the final decision comes from the ITC on November 7 and that there have been instances where the entire case has been thrown out at that stage.
Residential solar is steady and growing incrementally, although that growth is "masking an enormous amount of flux in financing."
SunPower has the strongest dealer network and dominates in residential solar in the U.S.
Kann suggests that in addition to the usual third-party financing companies such as SolarCity and Sunrun, the industry should keep its eye on newcomers with a unique twist on financing such as OneRoof and Vivint.
There are 300 solar industry movers and shakers at this conference, and we'll be reporting on their viewpoints over the coming days. The twitter hashtag is #ussmi2012. Stay tuned.
Lincoln International’s Frankfurt office engineered the acquisition of German micromorph thin film manufacturer and solar developer Inventux Technologies AG by the Argentinian-Chilean Consortium Covema SACIS in August 2012. Chicago-based Chaim Lubin, a VP in Lincoln’s Renewables group, did preliminary work on the deal in early 2012.
“What Lincoln does, on a global basis, is advise companies on mergers and acquisitions,” Lubin explained. “We help companies buy or sell. Most of our activity is on the sell side. We advise companies, shareholders or private investors on running a global sale process.”
Covema, a construction consortium, will maintain the Inventux 35-plus-megawatt production capacity in Germany for its module supply and use its own solar engineering, procurement and construction (EPC) experience to develop solar projects in South America. “The South American market is expected to grow. Covema sees this as a play to have its own technology. Inventux was trying to grow its demand.”
Though the Inventux deal took longer, a typical acquisition is a six-month process, Lubin said. “But that is market-driven. When silicon PV was more expensive, thin film was a more attractive offering. Now that it has come down, the Inventux sale took longer.”
The price on the Inventux sale was undisclosed, as are most prices in acquisitions involving parties that are not public. “It is very rare that we are able to talk about valuation,” Lubin said. “Our clients value confidentiality.”
Referring to the current solar industry consolidation, which GTM Research has forecast could see 180 companies absorbed or bankrupt by 2015, Lubin said, “it is pure economics, especially in the panel space. There are too many companies. It is a consolidation that needs to happen.”
For years, he has told clients, “'If you are not going to be the consolidator -- the one who goes out and buys other companies -- you should consider an exit. Now we look like fortune-tellers.'”
“From the data in the market,” he said, “valuations have come down. Where we are seeing opportunity is on the development end.” The development capabilities of First Solar (Nasdaq:FSLR) and SunEdison, he agreed, are examples. “People recognize there is a real value in companies that are able to get a customer to want to buy solar and then take that project to completion. That is the model I am talking about. There are companies doing that, but they don’t think of themselves that way -- and they should.”
Lubin thinks valuations in solar may be “bottoming out” because private investors are once again showing interest. “For 2013,” he said, “the winner of the election is going to largely determine in the near term what the space is going to look like.” He would, he said, “leave it up to the public to decide, based on what each candidate has said.”
The key part of his job, Lubin said, “is the deal. The preparatory phase comes first. We spend a lot of time getting companies ready. But we’re not consultants. We’re not in the business of spending two years redeveloping a company to get it sold.”
“The larger piece of what we do,” he said, “is putting together the positioning, the story and the material we will use in the marketing.”
They also may do “a financial cleanup” and then “some type of book or presentation that articulates why the company we are selling is valuable.”
Next comes “a list of who we are going to approach,” Lubin said. “We base it on our industry knowledge, our connectivity within the industry investor universe, and the private equity universe.”
As an international bank, Lincoln takes a global approach to deals. “Solar is a great example,” Lubin said, “because few industries are as global as solar.” The Spanish solar market is really challenging right now, he said, “but there are solar companies in Spain that may like the opportunity in the U.S.” Lincoln facilitates that type of deal-making worldwide, he said. “My colleagues in Madrid are the same to me as my colleague in the next office.”
Each list of buyers is developed with the client. “Some clients want absolutely the highest price. Some are more interested in getting the right partner. And some want to get it done as fast as possible and don’t care about anything else.”
When everything is ready, Lubin said, “You go out into the market. And a lot happens. A lot of my time then is spent on the phone. There is a lot of conversation with all the different parties.” He is always, he said, “trying to connect dots. I am trying to connect the interests of one party to the interests of another party.”
Many companies don’t realize there are alternatives to an IPO, Lubin explained.
“Every company is different,” Lubin said. “I spend a lot of time talking about whether a sale makes sense. I can’t tell you how many times I’ve dealt with solar companies and said, ‘No, this is not the right time.’ It doesn’t do me any good to take a company out into the market if they’re not ready. Our success is based on getting things completed, not on just getting out there.”
When the subject of utility pilots came up in a recent conversation with Ivo Steklac, chief sales and strategy officer at Tendril, he had a clear answer.
“Piloting is no longer necessary,” he said.
That’s not to say piloting still doesn’t happen all the time in the home energy management space. Tendril recently announced that Origin Energy was now rolling out its Energize platform to its more than 4 million customers -- after a successful pilot.
For Origin Energy, the plan was always to fully roll out Energize after a pilot phase. But for utilities that don’t have an endgame, Tendril says it is increasingly uninterested in working with them. “We know what our value proposition is,” said Steklac. “We’re not as inclined to just prove it out."
Instead, he said that he can show the company's work from more than 30 other utilities and third-party verifications. “You don’t need to keep testing it out.”
Pilot fatigue, sometimes referred to as “death by pilot,” is a common topic of discussion, especially for consumer-facing programs. “The time has come to stop the pilots,” Ahmad Faruqui, principal of The Brattle Group, said earlier this year when talking about dynamic pricing. “We’ve been doing pilots and little else for 30 years.”
The frustration is palpable. But things are slowly changing. For starters, companies like Tendril are no longer just talking to utilities. “We’re very excited it’s going through multiple approaches,” said Steklac, who said Tendril was in discussions with various other market participants, potentially telecoms or big-box stores. Lowe’s is already teamed up with AlertMe; EnergyHub is working with Earth Networks, which runs WeatherBug; EcoFactor has teamed up with Comcast.
That’s not to say utilities are no longer a target. But in the future, Steklac thinks that crowdsourcing is the way forward for utilities that know the business is changing. Earlier this year, Tendril worked with Dutch retail utility Essent to create something like an apps store for utility customers.
The utility was so impressed by a hackathon in Amsterdam that used Tendril’s APIs that it chose a handful of developers to create apps specifically for Essent and test them out on some households that chose to take part in the competition. Eventually, three winners will be rolled out to all of the utility’s customers.
The end of piloting is not about eliminating a testing period where utilities can gather data to inform a larger rollout, but rather is based on the argument that piloting should not be the end in and of itself. Although Essent is in a deregulated market, by offering different apps to customers, “It begins to show regulators that customers can choose,” said Steklac. Tendril has also opened its API for various hackathons stateside, including ones involved with the Green Button.
Another way that crowdsourcing might come to utilities is to enroll customers that already have smart thermostats into demand response programs. San Diego Gas & Electric, for instance, is offering an increased credit for Alarm.com and EnergyHub customers that want to join the Reduce Your Use program.
For utilities, it’s a low-cost way to roll out programs to additional customers at minimal cost. Technically, the partnership is still a pilot, and the utility will evaluate the results after a year, but unlike other pilots that go nowhere, SDG&E did not launch the project as a whim.
California is also the likely place where utilities will start to build something that looks like an apps store for utility customers. Currently, there are tons of hackathons and handfuls of apps, but there’s no one-stop-shopping for customers to access them. Most people probably have no idea what the Green Button even is. But if utilities don’t figure it out, someone else will -- no pilot required.
The smart grid presents an interesting problem for the world of big data, and particularly the field of unstructured data. Where traditional data management requires its data to be formalized and regimented, unstructured data systems take their data as-is, so to speak, from the literally uncountable numbers of inputs by which information is digitized, and then make sense of it.
That’s an approach ready-made for the heterogeneous and evolving world of smart grid big data, to be sure. All those smart meters, distribution automation systems, plug-in vehicle chargers and demand-response-enabled homes and businesses send and receive massive amounts of data, using a variety of communications networks to connect with a variety of back-end software systems, which can be managed by utilities themselves or their vendor partners.
Integrating them one-to-one is tricky enough. Sharing their data universally -- whether to analyze it, or to actually manage and control the disparate systems connected to the unstructured data engine -- is another level of integration altogether.
That’s the kind of capability that AutoGrid Systems is promising. The Palo Alto, Calif.-based startup unstealthed on Monday, and announced it has raised $9 million Series B round from investors Foundation Capital, Voyager Capital and Stanford University. Since its 2011 founding, it has also won backing from the U.S. Department of Energy’s ARPA-E program, which awarded it a $2.87 million grant last year, as well as the California Energy Commission with a grant earlier this year.
AutoGrid’s core technology is its Energy Data Platform, the cloud-based unstructured data analytics and management engine that takes in data from a multitude of sources and applies real-time predictive algorithms to the flood. CEO Amit Narayan, a former VP of research and development at semiconductor firm Magma Design Automation and founder of Berkeley Design Automation, has been director of Stanford’s smart grid simulation research for the past two-and-a-half years or so, and AutoGrid has also partnered with U.C. Berkeley, Columbia University and Lawrence Berkeley National Laboratory in its work.
The company also revealed its first two named utility customers: Palo Alto’s city utility, which used AutoGrid to roll out a commercial-industrial demand response project covering seven customers with about 26 megawatts of peak load, and the Sacramento Municipal Utility District (SMUD), which is using AutoGrid to manage a home energy DR project involving several hundred customers, Narayan said.
Both Palo Alto and SMUD are using the first of what Narayan promised would be many new applications from AutoGrid, known as the Demand Response Optimization and Management System, or DROMS. In simple terms, DROMS allows a utility, or another customer, to organize its entire DR portfolio, from picking out the programs and customers it’s going to work with, to actually executing the real-time shutdown of power loads across tens of thousands of endpoints, to verifying and accounting for the results.
Big Data = Device Control, Business Intelligence, More
In a Friday briefing in Palo Alto, AutoGrid executives showed off a quick demo of the system’s capability to manage a home demand response event from a simple web-based platform. It was a typical office demo setup, with devices from vendors like Silver Spring Networks, Energate, EnergyHub, Echelon, Itron and Coulomb’s ChargePoint car charging platform lined up against the wall, while Jimmy Caputo, senior product manager, turned them all on and off from a single web console. He even set up the system to call my cell phone and send a text to another reporter’s cell phone, warning us that our “home” was experiencing a peak power event.
This kind of functionality isn’t new: pager-operated AC cycling programs, load control switches, smart thermostats and other such devices are adjusting household and business customer power usage today. But almost all of those programs feature single-source vendor relationships, and very few are integrated in a way that allows a utility to control its different systems from a single console, he noted. On that front, AutoGrid might face competition from integrated demand response offerings like that being offered by Aclara and Calico Energy, or Silver Spring Networks and its various DR partners.
Narayan also described a pretty impressive set of business and operational tools that DROMS brings to its customers, whether those might be utilities, retail energy service providers, demand response aggregators, or the owners of the buildings that are consuming the energy. Here, again, the ability to combine lots of unstructured data and analyze it can yield insights into the bewildering set of variables that go into setting up a DR program.
Take Palo Alto’s seven-customer DR program, now being managed by AutoGrid’s system. Most of today’s demand response aggregators like EnerNOC, Comverge, Constellation Energy and the like wouldn’t tackle a project that small, because the return in megawatts of reduction wouldn’t justify the customer acquisition and technology set-up costs, he said.
But AutoGrid, using its big-data-crunching magic, was able to identify critical utility customers that already had dial-up modem “smart” meters, giving the utility a way to measure its power reduction. As for telling the customers when to shed load, Palo Alto is using good old-fashioned email and phone calls to building operators to get the job done, Narayan said -- an option that worked out to be the most cost-effective. (Big-data-based startups like FirstFuel, Retroficiency and IBM are applying similar principles to the building energy efficiency field, by the way.)
Other customers will seek out more technologically advanced, and thus higher-yield, demand response options, Narayan said. SMUD’s project is using OpenADR, the emerging open standard for transmitting demand response and pricing data from utilities to customers, for instance.
What’s particularly nice about AutoGrid’s unstructured data-crunching method of combining different smart grid devices is that it can leverage multiple such systems to make the combined parts work better together as a whole, said Andy Tang, the former Pacific Gas & Electric smart grid chief who’s now AutoGrid’s vice president of business development.
For instance, old-fashioned one-way radio controlled air conditioner switches can turn down power use at homes, but can’t communicate back. Add smart meters to those homes, however, and you’ve got a device that can give you fifteen-minute updates on the resulting power reductions, all measured against an industry-accepted baseline.
But that can only happen if the system managing the interaction can quickly and accurately combine those two disparate sets of data to come up with the answers that utility operators need, Tang noted. That, of course, is what AutoGrid’s big data platform is all about.
In the long run, AutoGrid’s DROMS is seeking to deliver demand response services at a cost that’s one-tenth that of today’s way of doing demand response, while offering a 30-percent higher yield on investment in terms of achieving customers’ goals for their demand response programs, Narayan said. That’s a pretty lofty goal, and it will be interesting to see how the company and its customers perform on it — Narayan said that AutoGrid is expecting to announce several new customers in the coming months.
Silver Spring Relationship, Potential Partnerships Afoot
Narayan also noted that AutoGrid is working on communicating over the AMI networks of Silver Spring, a startup also backed by Foundation Capital which has about 12 million meters connected to date and millions more under contract. While Narayan wouldn’t go into details on the Silver Spring relationship, one piece of data that emerged during AutoGrid’s Friday presentation indicated that the two may in fact already be working together on real-world deployments.
In particular, the presentation featured a map of the Oklahoma City area, featuring clusters of homes that are connected to a utility demand response program that AutoGrid is working with. Silver Spring just happens to be working with utility Oklahoma Gas & Electric and smart thermostat vendor Energate on a smart-meter-enabled demand response program in the Oklahoma City area.
None of the AutoGrid executives at Friday’s briefing would say whether or not the company is involved with Silver Spring on that OG&E project, which is one of the first large-scale residential DR projects of its kind in the U.S. leveraging smart meters to manage home energy.
They also wouldn’t comment on whether or not AutoGrid’s Energy Data Platform was being used today by other vendors, including Silver Spring, as a backbone to various smart grid analytics projects they’ve been rolling out over the past year or so. But Chris Knudsen, AutoGrid’s CTO and former PG&E smart grid architect, said that AutoGrid was intent on getting its technology out to the industry via a variety of channels, including licensing it to partners who could white-label it under their own brand.
Of course, nobody’s going to tackle the big (and unstructured) data smart grid challenge without making lots of partnerships. AutoGrid itself uses the host of big data tools, such as Hadoop, that have been so integral to the big data needs of internet giants like Google and Facebook. We’ve seen other partnerships emerge to tackle big data challenges, like NoSQL vendor Versant and EPRI, or Dell and OSIsoft, or Itron and IBM, or Silver Spring and EMC, to name a few examples.
Eventually, AutoGrid plans to incorporate actual grid physics modeling into its suite of offerings, so that utilities can predict how demand response programs, weather events and the predictably unpredictable behavior of energy consumers will affect the actual ebb and flow of electrons on the grid, Narayan said.
In the end, the main question for all these big-data data management technologies is, do they stand up to their promised capabilities? Certainly partners like ARPA-E, CEC and Stanford would appear to give AutoGrid some bona fides on its core technology. How it executes on its vision -- delivering the latest in big data technology via smart grid-tailored applications like DROMS -- has yet to be seen.
When the Federal Energy Regulatory Commission approved Order 745 in March, elation blanketed the world of demand response.
Fair play! More compensation! Take that, old-school power generation! The ruling said that many grid operators will have to pay the full market price, known as the locational marginal price, to economic demand response resources in real-time and day-ahead markets as long as dispatching DR is cost-effective.
A year and a half later, the hard work has settled in and there are only two regions in the U.S. where the ruling has so far been implemented. The news so far, however, could not be better, Brendan Endicott, director of economic demand response at EnerNOC, suggested during a webinar hosted by Restructuring Today entitled "How Big of an Impact Did Order 745 Have This Summer?"
“Prior to 745, demand response was just tacked on to the side” of markets, he noted. Now, at least in PJM Interconnection, the grid operator that covers much of the mid-Atlantic, demand response is a fully integrated offering.
In PJM, total economic energy reduction has increased by 800 percent in the past six months. For demand response participants, payments have increased nearly 400 percent from 2011 to 2012 even though energy prices are 20 percent lower in the same period of time. “It basically shows that as a result of the order, the proper incentives are there to get people into the market,” Endicott added. Economic demand response participants in PJM have netted about $6 million since April.
In ISO New England, there have been some changes, primarily an extension of the day-ahead load response program, but demand response cannot yet set the locational margin price.
Forget about the other grid operators, NYSIO, MISO, SPP and CAISO; they’re still working out how to implement the ruling.
When the rest of the grid operators figure out how to incorporate the new requirements for demand response, it will be a glorious day for negawatts.
Or will it? Paul Centolella, VP of Analysis Group and former commissioner of the Public Utilities Commission of Ohio, had a far less rosy and more critical look at what the ruling meant for the future of demand response. “We can very quickly see that it was not an efficient way to incent demand response within the market,” he said.
But what about all those rosy figures from PJM? Well, it depends on how you define demand response.
Centolella noted that the winners were largely large commercial and industrial customers. By paying the full LMP, he argues that it incents self-generation over efficient regional dispatch and is actually discriminatory.
Order 745 does not even get close to the larger issue of how to optimize demand across the entire spectrum in a much more dynamic way, Centolella argues. “Most of our end-use devices are intelligent in some way,” he said, noting the variety of gadgets in our lives that have chips in them. “If we could take advantage of that capability, we could have a more resilient grid.”
In other words, Centolella sees Order 745 as a somewhat distracting market mechanism when the real effort should be in enabling demand response into every facet of our lives, rather than a system that only reduces demand during peak. He argues that improving load factors through a demand optimization strategy is the only way to close the glaring investment gap that the grid faces.
He sees automated demand response, standardized formats for energy usage and on-bill financing for energy efficiency upgrades as programs that can help push toward a truly optimized grid. But many real world examples, from an OpenADR standard to the Green Button initiative, are in the very early stages.
So how do you move to a more integrated grid, where demand does not just respond but acts as an integrated facet of the system? “The answer really lies in creating a framework for collaborative innovation,” says Centolella. “It depends on changing the focus of our vision to ‘How do you create more efficient markets?’ and not just ‘How do you create more demand response?'”
In 2012, China’s electric grid will become the largest in the world in terms of both installed generation capacity and electricity produced. China also possesses the world’s largest installed wind power base and the world’s largest declared investment in renewable energy. These facts alone suggest that China is also the most attractive market for energy storage in the world, even though China currently has just 4 percent of the worldwide energy storage capacity.
Whereas other markets have focused on power quality and ancillary services, China’s grid energy storage market has developed with a focus on renewable energy integration, load-shifting and peak shaving.
In a new report, Azure International and GTM Research forecast that pumped-hydro storage capacity will reach 40 to 60 gigawatts by 2016, while other storage technologies will rise from currently insignificant levels to over 700 megawatts installed by 2016. Download the report’s brochure to see the complete scope at www.greentechmedia.com/research/report/china-grid-scale-energy-storage-2012-2016.
FIGURE: Overall Energy Storage Installed Capacity (Excluding Pumped Hydro), 2011-2016E
With strong government support and steadily improving technology, we anticipate the energy storage market will grow to a $500 million per year market by 2016. In this 142-page report, we analyze the market's outlook with a realistic assessment of the policy, market and technical barriers that energy storage faces.
FIGURE: Active Energy Storage Companies in China by Technology and Development Stage
For more information on this report and the state of the China energy storage market, visit www.greentechmedia.com/research/report/china-grid-scale-energy-storage-2012-2016.
Trade shows, including the recent Solar Power International (SPI), have historically been a good way to take the vitals of the solar industry. However, the perspectives of the solar industry are starting to concentrate on a single topic: quality.
The rhetoric surrounding long-term quality has been consistently overshadowed by cost per watt. This is something that must change, and finally, it appears to be changing. There is fear that unprecedented downward pricing pressure on PV panel manufacturers will compromise quality but it won’t be because manufacturers don’t care. The reality is, buyers are demanding the lowest price that the banks can tolerate and manufacturers are racing to comply. A majority of the manufacturers will continue to employ best practices and it will be the negligence of a few that’ll end up costing the industry as a whole.
Related to this is consolidation. A necessary transition in an emerging market, this is happening now and it is as scary as we expected. However, this consolidation is not just an aggregation of quality companies to remain competitive; there is an undertow of unprofitable marketplaces forcing good companies out. This exit from the marketplace creates two challenges. First, investors and banks cannot tolerate uncertainty, and when large global players decide to abandon or sell a business, it sends a signal of an uncertain future. Second, this consolidation is leaving existing asset investors with less certainty of the product warranty because the protection of a large balance sheet may be eroded or simply gone.
Buying solar panels reminds me of shopping for wine in my early days of college. I was careful to find the lowest price with the trendiest label. I didn’t consider much beyond that. If it had a good name and wasn’t the absolute cheapest, it must be good, right? I assumed that the "market" would set the price to compensate for higher quality. As one can imagine, I found that wine was inconsistent at best. Solar PV today is suffering from a similar challenge: the perception that "top-tier" modules are inherently higher quality just because they are top-tier. So then it is a question of price and "label." Unfortunately, this mindset has left an assumption of quality based on the brand and less on the actual product delivered. And as is typical, this paradigm will leave a lot of quality manufacturers fighting for a top-tier distinction through marketing rather than relying on better quality.
As the dialog shifts from price per watt to levelized cost of energy (LCOE), both of these paradigms stop short of the underlying and more complex story, and both require an open acknowledgement that the performance of the asset is uncertain. The answer, then, is to embrace the uncertainty with rigorous control of the solar project quality control chain. The modes of failure for solar are mostly known and testing exists to uncover those latent defects.
The bankruptcies and wholesale abandonment of the solar business is not over, yet PV is a proven technology and can have a successful and profitable life. It is important to note that the investors are -- now more than ever -- betting on the underlying technology as warranties and performance commitments are based on deteriorating financials. Financiers will become more active in the technical discussion, ensuring that debt coverage ratios are sufficient to cover any lack of confidence in the asset to perform in aggregate. Because PV panel manufacturers will face increased pressure to shave pennies, the industry needs a stronger presence for review and compliance. A perfect factory audit is not the end… it is just the beginning.
A broken quality chain has negative consequences not just for the project, but also for the industry. The volatility and fast growth of the solar industry is inevitably creating opportunities for the chain to be broken. Solar energy is pre-paying for fuel twenty years in advance. The longevity of these assets gives ample opportunity for poor decisions or honest oversight to manifest in a field issue. In extreme but rare cases, there are physical consequences of safety and property, but more often, field issues damage investor confidence, which leads to higher costs of capital or limited capital availability. It is therefore critical that as an industry we have third-party verification that the chain remains intact to protect developers, manufacturers, owners and the industry at large.
The quality chain is not a new concept for solar, but it does matter more today than in years past.
The solar industry is at a crossroads. Globally, project sizes are growing, the geography is rapidly expanding, and it is becoming clear that the panel supply landscape will look different in twelve months. It is essential that the industry not attempt to hide the fact that modules are not all created equal. It is also important to be united across the industry about the fact that that underperforming assets will exist, but will be a small minority. Remaining competitive requires that all stewards of the quality control chain increase concern but not perpetuate fear.
There is a silver bullet: well, sort of, maybe more like silver buckshot. Solar projects should trust and defend their suppliers, but only with verification procedures in place. The added cost of substantially increasing confidence is a fraction of a penny per watt to assess the risks. PV Evolution Labs and GTM Research are addressing this need with a new program called the PV Module Reliability Scorecard. Buyers are increasingly demanding that their suppliers participate in this Consumer Reports-style program. Scorecard test results could highlight whether a panel is appropriate for a specific climate or system configuration. Buyers are leveraging PV panel technical experts at firms like SolarBuyer, BEW, and Black & Veatch to provide factory audits. Buyers should always test to verify IEC compliance, and demand validated PAN files to ensure actual performance meets predicted performance. Today's buyers understand that procuring modules without any testing or independent evaluation is a risk they no longer have to take. In today’s market, quality is no longer binary. By thinking less about how a top-tier name is marketed and thinking more about the underlying technology, we help the industry support the strength of the quality control chain.
David Williams is the CEO of Dissigno and former Chief Risk Officer of CleanPath Ventures.
The California Public Utilities Commission (CPUC) voted unanimously to launch a formal investigation of the nearly nine-month outage at the San Onofre Nuclear Generating Station (SONGS) Units Two and Three.
At the same meeting, the CPUC voted unanimously to approve revised power purchase agreements (PPAs) between BrightSource Energy (BSE) and Southern California Edison (SCE) (NYSE:EIX) for the electricity generated by BSE’s 500-megawatt Rio Mesa solar power tower project and a 250-megawatt unit of its Sonoran West power tower project.
The revised PPA for Rio Mesa makes contractual provisions for BSE’s planned deployment of more advanced solar power tower technology. The revised Sonoran West PPA allows for the incorporation of thermal storage.
More power capacity and stored generating capacity will allow the plants the flexibility to serve the grid in ways that help balance transmission system supply and demand and make electricity delivery more reliable.
In an early August CPUC debate about the SONGS outage, Commissioner Michael Florio called for the Commission to issue an Order Instituting Investigation (OII) of SONGS. Chair Michael Peevey said it was too soon. But, Peevey told Florio and the Commission, if operator and 78 percent owner SCE could not get at least one unit of the nuclear plant on-line for “at least 100 continuous hours of operation” by November 1, the nine continuous months out of service would require SCE “to file notice pursuant to Section 455.5 of the Public Utilities Code.”
Such a filing, Peevey explained, “requires this Commission to institute an investigation within 45 days.” That investigation will now go forward.
What initially appeared to be a maintenance issue at SONGS Units Two and Three in January was soon diagnosed as failed steam generators. Both units have been offline ever since.
Unit Two went on-line in August 1983 and Unit Three went on-line in April 1984. Both rely on an older technology built by Combustion Engineering (subsequently bought by Westinghouse).
Mitsubishi Heavy Industries (TYO:7011) replaced the two steam generators of the 1,172-megawatt Unit Two in January 2010 and the two steam generators of the 1,178-megawatt Unit Three in January 2011. (The SONGS Unit One went on-line in January 1968, was built to last until 2004, but was decommissioned in 1992 due to wear.)
The steam generators are where the heat generated by the light water reactors turns water into the steam that drives the facilities’ electricity-generating turbines. Such turbines also generate electricity when driven by steam created by boiling water with coal, natural gas, geothermal stations or concentrating solar power plants.
Each SONGS steam generator is 65 feet tall and weighs 1.3 million pounds. Each has two large U-shaped tubes, which have 9,727 U-shaped, three-quarter-inch-diameter tubes running through them.
The failure of a steam generator tube, wrote Nuclear Regulatory Commission (NRC) Public Affairs spokesperson Lara Uselding in March, “is a problem, because radioactive water that passed over the nuclear reactor and into the steam generator may escape into the created steam through a hole in the tube.” The radioactive steam could eventually escape to the environment.
To prevent radioactive leaks, plant operators perform regular inspections. If a tube is found to be severely worn, it is plugged.
SCE reported wear and plugging of tubes in of both units in January.
Vermont nuclear watchdog group Fairewinds Associates, at the request of Friends of the Earth, used NRC data to compare “the replacement steam generator plugging at both San Onofre Units Two and Three to the replacement steam generator plugging history for all other replacement steam generators at U.S. nuclear power plants.”
The San Onofre reactors, it concluded, “plugged 3.7 times as many steam generator tubes than the combined total of the entire number of plugged replacement steam generator tubes at all the other nuclear power plants in the U.S.”
In the scramble to keep electricity customers supplied after the shutdown, SCE, San Diego Gas and Electric (SDG&E) (NYSE:SRE), the other major co-owner with a 20 percent stake, and the California Independent System Operator (the ISO) brought retired facilities back, inaugurated new transmission, and hardened demand response capabilities. Their efforts allowed Southern California to get through the summer without a power failure.
The CPUC will now investigate the “reasonableness and necessity” of the decisions of SCE and SDG&E leading up to, and subsequent to, the January outage, and it will consider the future of SONGS.
The investigation could result in the utilities being required to return “over $800 million in fixed costs (rate base)” and “over $300 million in annual variable costs (operation and maintenance)” that were passed to ratepayers, according to CPUC documents.
The CPUC could also prohibit the utility-owners from passing the $671 million SONGS repair bill on to their ratepayers.
Several nuclear industry watchers, including Geesman and Dickson Partner John Geesman, formerly of the California Energy Commission, told GTM in August this could be a potentially significant financial hit for SCE, which in its last quarterly report acknowledged already being in dire financial straits.
The urgency of SCE’s position is accentuated by the fact that Nuclear Electric Insurance Limited (NEIL), the SONGS nominal insurer, according to Geesman, is less an insurance company than an industry pool, and it is unclear what its resources or responsibilities are.
LDK (NYSE: LDK), based in China, is one of the world's largest producers of solar wafers, as well as a manufacturer of high-purity polysilicon. But, the solar industry is painfully oversupplied, and most if not all solar firms are losing money.
LDK had an operating loss of $172 million in the second quarter and three straight quarters of losses before that. Because it is a major employer in the poor province of Xinyu, the local government stepped in to pay off $80 milllion in debt a few months ago. As Jeff St. John wrote, "Looks like the Chinese model of solar capitalism has entered a new and, at least for its global competitors, a more troubling phase."
It gets worse.
LDK just sold a 20 percent stake in the troubled firm to Heng Rui Xin (HRX) Energy, a Chinese state-run entity, for approximately $23 million, according to a report in Bloomberg. According to the report, Heng Rui Xin is paying a 21 percent premium to LDK's Friday closing price of 71 cents. The owner of Heng Rui Xin is Hi-Tech Wealth Investment and Developing Co. and state-owned Asset Management Co., with a 40 percent stake. LDK calls HRX "a PRC company invested by privately owned and state-owned funds" on its website.
The news comes amidst a full-blown solar trade war with the United States, which has put tariffs on Chinese imports that are driving some companies out of business. China is threatening retaliation. Meanwhile, it’s not clear that U.S. tariffs will have the intended effect. GTM Research has reported that Chinese module suppliers can avoid it by sourcing cells from Taiwan at an estimated additional cost of only 6 cents to 8 cents per watt, and sources have confirmed that Chinese module prices in the U.S. have continued to trend downward even after the tariff ruling.
Does this validate the SolarWorld and CASM claim of unfair competition and trade? Will tariffs even the playing field for U.S. solar manufacturers? Could this announcement impact the final ITC decsion next month?
Any U.S.- or EU-based firm with financials similar to LDK would long since be bankrupt, in the spirit of Q-Cells or ECD.
If China rescues a strategically important industrial firm and employer -- is that an unfair trade practice? Or is that a sovereign state's right to influence industrial policy, akin to a bank bailout or an automotive bailout?
If a foreign nation subsidizes solar, doesn't that mean the foreign nation is paying for a part of that solar panel? Is China subsidizing solar power in America or looking to monopolize the global PV market and eventually raise prices?
GTM Research's take on the situation? In a recent article on consolidation in the solar industry, Shyam Mehta wrote, "There are ... natural synergies to be gained from the acquisition of certain pure-play Chinese solar firms by larger diversified Chinese firms -- either those that are already involved in module manufacturing or new entrants, such as the state-owned enterprises."
Suntech's founder, Zhengrong Shi, is headed for a showdown with the Chinese government according to Young's China Business, which notes, "Suntech is in similar need of cash, both to fund its operations and also to pay nearly $600 million worth of debt that will come due early next year. But media are reporting that the company's proud founder and Chairman Shi Zhengrong is refusing two government proposals that would give him the funds he so desperately needs."
"One of those proposals would see the government buy the bonds coming due next year and provide an additional capital injection. But a key condition of that package would require Shi to provide his own personal assets to guarantee that those bonds would be repaid -- meaning Shi would probably lose the 30 percent of Suntech shares he owns. Those shares once made him one of China's richest men but are now worth a meager $46 million based on the company's latest market capitalization. The second plan would see Suntech de-list and become a state-owned company."
GTM Research adds, "LDK Solar could serve as a bellwether for future cases. Our sources in China report that a number of state-owned enterprises (e.g., Sinoma, CECEP, CNBM, Guodian, Shenma) have met with LDK regarding possible acquisition deals. The Chinese press also reported that Jiangxi Copper Corporation, a Jiangxi-based SOE (in LDK’s home province), has sold RMB 300 million ($47 million) worth of shares to fund the purchase of LDK shares, which could make LDK one of the first (at least partially) nationalized PV manufacturing giants."
In any case, a $23 million cash injection doesn't make a dent in LDK's debt, finances, or structural issues -- whether the firm is a free-standing entity or owned by the state.
Jeff St. John contributed to this article.
If you don’t mind a little risk, it might be a good time to be buying solar businesses. Lots of sellers out there.
The latest to join the get-out-now club is the German industrial giant Siemens, which said on Monday that it would sell off its solar businesses, led by a concentrating solar power unit that was caught with a technology losing popularity in a stagnant market.
It was just three years ago this month that Siemens announced it was spending $418 million to acquire Solel Solar Systems, a company that had been doing well selling components for utility-scale parabolic-trough solar thermal plants, particularly in Spain. These plants consist of long rows of curved, sun-tracking mirrors that focus sunlight on a fluid-filled receiver tube running directly above the mirrors. The heated fluid is then used to create steam to drive a generator.
But it wasn’t long after the Solel acquisition that the utility-scale solar market began to shift. Plunging panel prices made photovoltaics a good option. And even where the concentrating/thermal model was preferred, power tower technology -- using arrays of big mirrors to focus sunlight on a giant tower -- often moved to the fore.
We see such towers going up in California, with BrightSource’s big Ivanpah project, and SolarReserve is at work on the Crescent Dunes plant in Nevada. More power tower plants are crowding what Siemens said was a shrinking pipeline for concentrated solar.
“The global market for concentrated solar power has shrunk from 4 gigawatts to slightly more than 1 gigawatt today. In this environment, specialized companies will be able to maximize their strengths,” Michael Süß, CEO of Siemens' energy sector, said in a statement.
Solel founder Avi Brenmiller is said to be considering making a bid for his old business. Brenmiller told Reuters that his new company, Brenmiller Energy, is looking to pair thermal solar with natural gas in power plants. That would make for a steady supply of energy and, depending on the market, could bring down the cost (gas is cheap in the U.S., but not everywhere). And price is, always, the market driver.
The pressure from vastly cheaper PV has hurt concentrating solar -- but it has also hurt plenty of PV companies. The Santa Clara, Calif. thin-film startup MiaSolé, after taking in around a half-billion dollars in private money, was gobbled up for $30 million by China’s Hanergy Holding Group a few weeks ago. As reported by Reuters, that prompted Raymond James analyst Pavel Molchanov to say in a message to clients, ”Here is the latest entry to the list of PV manufacturers getting bought for pennies on the dollar.”
Still, it is important to note that while the solar sector is grinding through a torturous realignment after building wildly excessive capacity, and demand growth has slowed, more and more solar continues to be installed.
What kind of vehicles will commuters use In 2022? What kind of vehicles will deliver goods? Energy storage experts at the third annual Advanced Energy Solutions symposium offered some potential answers.
US Hybrid President Abas Goodarzi:
The biggest inefficiency in transport is traffic. That’s where hybrid batteries come in. Just like a laptop or cell phone, we need to be able to have that engine go to sleep or decouple. Hybrid is the only way to do that.
For trucking, more than 50 percent of energy consumed is to move the weight. You have to dramatically change the architecture of the truck to a powered platform, especially for ports. The battery power system is in the trailer bed. Independent axles make maneuverability more efficient.
In five years, self-powered cargo handling goods movers will be in more than half of all ports and, with this, all-electric becomes feasible.
FLUX Power CEO Chris Anthony:
Petroleum products will become scarce and we will be incentivized to use electrons to push vehicles, but we will still be lithium-powered in 2022. It will more ubiquitous and cheaper. I hope maybe 20 percent to 30 percent of our vehicles will be electric.
We’ll see progress in developing countries in inexpensive electric vehicles, something that costs $5,000 or $6,000 that could last for five or ten years instead of $50,000 to $100,000 technology planned to last ten to twenty years. Over the next ten years, government subsidies will fall away and commercial markets will produce that $6,000 car.
Heavy transport vehicles will be more efficient, more lightweight. Aerodynamics will be crucial. I can imagine solar devices on long-haul trucks by 2022, if solar gets less expensive and lighter-weight. Not using 60 feet of space across the top seems silly. It could be charging the battery.
BAE Systems HybriDrive Solutions Senior Engineer Tom Apalenek:
When I was in high school, in 1976, I read an article about how everybody would be driving electric cars by the year 2000. Everybody is not driving electric cars. I think the highest likelihood is hybrids. Something electric, something with energy storage.
I don’t see a breakthrough in battery technology by 2022 that will make it possible for all-electrics to be a broad market. Batteries are running up against physics in terms of how much energy you can store and, even if you solve the battery problem, there is the charging infrastructure. Everybody today is used to being able to refuel in five minutes.
Ioxus VP Jeff Colton:
We could make an educated guess that by 2022 the CAFÉ standard is going to be around 40 miles per gallon. Currently, the approach is all-electric vehicles. I think the cost of electricity will increase faster than the cost of gasoline. And it is more difficult and more expensive to increase electric charging capacity than to increase gasoline or natural gas capacity.
There are estimates that a subsidized all-electric vehicle that might sell for $45,000, but the estimated manufacturing cost ranges from $90,000 to $250,000. Those subsidies are not going to exist in ten years. All-electric vehicles are not the answer.
Recovering wasted energy through regenerative braking is the answer. It is using less fuel, not just a different kind of fuel.
In ten years, you can recover the difference between today’s CAFÉ standards and 2022’s CAFÉ standard by recovering the energy wasted during braking. You don’t have to dramatically change the entire system and double or triple your utility's generating capability.
That’s where ultracapacitors fit. I am talking about a 30 percent gain if, every time you brake, you recover all of that energy. Ultracap technology has to advance -- but not as much as the technology necessary to make electric cars work.
Cost-wise, we are not there, but it is a more cost-effective solution than a $250,000 electric car. In two or three years, as we reduce the overall systems cost, it becomes very viable. Electric car mass adoption doesn’t work because the whole system has to change.
OPTIMARK President and CleanFleetReport.com Founder John Addison:
In 2022, if we project current trends, smart apps will make electrified, efficient modes of transportation increasingly easier to use.
We will move more slowly in long-distance trucks and airplanes. We will have more efficiency but we will still depend on petroleum fuels or, possibly, sustainable, cost-effective biofuels.
Vehicles are, on average, on the road in this country fifteen years, so it is going to be a gradual turnover. In 2022, probably at least 30 percent of personal vehicles will have an electric motor and advanced energy storage system. And the electrification of transportation could very well be the killer app of the smart grid.
It is a classic case of technology crossing the chasm. You are going see advanced technology adopted in little segments and then move into the general market. So much of whether you are optimistic or pessimistic about electric cars depends on whether you jump straight to this mass consumer market. But technology never evolves that way. It is not happening in transportation either.
The same day these ideas were collected, Westport Innovations and Clean Energy announced they will take a demonstration Peterbilt 388 heavy-haul eighteen-wheeler powered by a natural gas engine from Dallas, TX to Oklahoma City, OK using Clean Energy's new network of LNG stations.
Module Supplier Taxonomy
To make sense of the existing landscape of module manufacturers, we categorize firms using the following criteria:
- Location of company headquarters
- Corporate presence (pure-play solar firms vs. diversified firms)
- Other categories (sub-region, bankability tier, technology, etc.)
The figure below illustrates the taxonomy as applied to firms based in China (click to magnify).
The figure below shows year-end module capacity by producer type in 2012. Chinese pure-play suppliers make up a full 60 percent of the total, with diversified Chinese firms accounting for another 10 percent. The other 30 percent is roughly evenly shared between companies headquartered in Japan (8 percent), Rest of Asia (7 percent), Europe (9 percent), and the U.S. (6 percent).
Competitive Positioning Metrics
We list six key metrics that define module supplier competitive positioning:
- Efficiency-adjusted manufacturing cost structure
- Near-term liquidity
- Future availability of capital
- Technology differentiation
- Channel penetration
Competitive Positioning Assessment: Methodology
Our approach to high-level competitive positioning analysis is very simple: we assess the existing landscape of module suppliers by awarding them points based on a five-point scale. These scores can roughly be interpreted as follows:
- 5: Industry-leading status, best-in-class
- 4: Very strong, just short of industry-leading status
- 3: Competitive
- 2: Weakly positioned
- 1: Worse than most firms
We admit this method is at best quasi-quantitative. But at the very least it allows us to differentiate between the many firms in the space with some degree of granularity. For example, not all China-based module suppliers have similar cost structures, and it is necessary to differentiate between industry leaders such as Trina and Yingli and higher-cost firms such as Suntech Power. Moreover, it also helps us establish facts and gain insights about groups of companies on a somewhat empirical basis. Below, we examine the competitive positioning of the diversified Chinese firms in more detail.
Competitive Positioning Assessment: Diversified Chinese Firms
Diversified c-Si firms own 31 percent (6.8 gigawatts) of domestic capacity share. Most of these are privately owned -- the large state-owned enterprises have yet to make any significant mark in PV manufacturing thus far. Some diversified firms (Hanergy, ENN) have also made bets on thin film technology. The figure below shows the competitive positioning matrix applied to select major diversified Chinese solar firms (click to magnify). Below, we examine their performance on key metrics in greater detail.
- Manufacturing Costs. While the diversified Chinese c-Si firms are comfortably below most non-Chinese firms on manufacturing costs, they generally trail the larger pure-play firms on manufacturing costs by around 10 percent to 12 percent. The thin film firms (Hanergy, ENN, QS) are not currently cost-competitive on an efficiency-adjusted basis.
- Brand/Bankability and Channel Penetration. Most diversified Chinese firms are relatively new to the PV module business and so trail the Tier 1 and Tier 2 firms with regard to brand and performance/reliability-related bankability. Unlike the Japanese and Korean conglomerates, these firms are not well known globally, and most of them have not spent any real marketing dollars to raise their profile, aside from Astronergy. At the same time, their bankability on a balance-sheet basis is very strong due to their well-capitalized parents. Some of these firms (e.g., Alex Solar, Astronergy) have leveraged their parents’ networks to move into project development and EPC in the domestic market, and expect to deploy significant volumes there going forward.
- Technology/IP. Most diversified firms are relatively undifferentiated in terms of manufacturing technology and leverage innovation at the equipment and materials level for further improvement. Some notable exceptions are Astronergy, which has been an early adopter of Varian’s (now a subsidiary of Applied Materials) ion implantation technology for emitter diffusion, and BYD, which is commercializing a proprietary variant of selective emitter (NES, or narrow finger and busbar electroplated selective emitter).
- Balance Sheet and Capital Availability. Unlike their pure-play peers, the diversified firms can count on the support of their parent companies for additional funding -- but only as long as the parent remains committed to the PV business. In the current business environment, this cannot be taken for granted.
- Strengths. The key advantage that diversified Chinese firms have is access to their parents’ capital, which confers obvious advantages in terms of capacity expansion, balance sheet-related bankability, and available finance for project development. The strong position and connections held by their parents also gives them an advantage in the domestic market.
- Weaknesses. Most of the diversified firms have poor brand recognition outside of China, and trail most of the industry when it comes to time-in-market. They generally lack the several years of field data that could alleviate concerns around module performance and reliability that are a key consideration in bankability-sensitive markets such as Canada and the U.S. Thus far, they have displayed little business model flexibility outside the domestic market, and they have struggled to penetrate markets outside Germany and China.