Renewable Energy World By: Steve Leone May 25, 2012

These are the Solyndras of the world. Their science may have raised the bar, but ultimately they were judged by the market, which measures the bar on cost alone. From that perspective, it’s more like a limbo line — “How low can you go?”

For an industry struggling to get to price stability because of factors unrelated to technology, it can be a difficult exercise to envision which advancements will get to move on and which will be referred to only in the past tense.

In a new report titled “Searching for Game Changers in Photovoltaics Materials Innovations,” Lux Research details the emerging technologies that will thrive and those that will eventually sputter out. Along the way, the report gives us a couple new acronyms to squirrel away as we consider the ROI on our R&D.

The basis for much of the research is the volume of development funding we’re seeing right now, and the forecast that the industry will return to double digit margins by 2014. Conceivably, once those margins return, many of the innovations in the background today will be ready to step into the market. The formula to get there is based on solid economics — the technologies that succeed will offer both a low cost per watt and the ability to scale using existing PV infrastructure.

The report also offers a fair warning to those who assume that the U.S. will continue its role as innovators while China takes on the function of manufacturing. Many of the technologies that currently dominate PV were developed in American laboratories and academic institutions. But China is making significant investments within its own universities and government research institutes. The end result, says Lux, is that the innovation gap will soon close.

The Technology Winners

Epitaxial-Si: The report calls this technology the last nail in the amorphous silicon (a-Si) coffin. Uni-Solar has gone bankrupt and Oerlikon has sold its a-Si thin film business. The problem with a-Si has been the lower efficiencies achieved when compared with other thin film technologies like CdTe and CIGS. Epitaxial Si (epi-Si), which is thin monocrystalline silicon, has the potential for higher efficiencies, and it could replace a-Si infrastructure.

CZTS: Copper zinc tin sulfide cell technology has been receiving interest over the past few years because of its ability to replace CIGS with with cheaper materials. Indium and gallium, both used in CIGS, are rare earth minerals, which mean they’re expensive and subject to shortages. Some big names are looking into this technology, such as IBM and Dupont. Another exploring CZTS is Solar Frontier, which has made big inroads recently with its CIS operation. Lux expects CZTS, which still faces issues of thermal instability, to reach commercial scale and competitive thin-film prices within the next five years.

The Technology Losers

Kerfless Wafering: There’s been lots of buzz lately about ion implantation and how the tools needed for this technology can save lots of money compared to the current wafering technology. But the tools themselves are big-ticket items. According to Twin Creeks, each 350-square-foot tool would put out the quivalent of 6 MW of cells per year. That output is certain to go up with new generations, but according to Lux, the capex with ion implantation is still too high. Additionally, throughput for wafering is lower than the traditional wire-saw techniques and the exfoliated wafers that come from these tools require an additional step. SiGen and Twin Creeks have yet to report cell efficiencies. Solexel, which recently received $25 million to build a pilot plant, says it has reached 12.6 percent effient monocrystalline cells. That, says Lux, is too low for c-Si cells at any stage of development.

Quantom Dots: Quantom dots and nanowire cell technologies have drawn investment from academic researchers because both require less material than current thin-film technologies. But both quantum dots and nanowire structures result in larger surface areas, which are hard to passivate. And the cell efficiencies recorded thus far are well below what you’d need for commercialization. Without an unexpected breakthrough, neither technology will be commercialized any time soon, says Lux.

Since early this spring, Little has been predicting a tariff in the 30 percent range would be put on Chinese solar panel imports. On May 17, the U.S. Department of Commerceimposed a 31 percent tariff on panels from China’s biggest panel makers.

U.S. solar manufacturers have been struggling against low-price panels from China. The tariff is intended to prevent what domestic trade groups have described as “dumping” by the Chinese of below-production-cost products. Chinese panel makers are attempting to unload excess inventory even though they are being forced to do so at a loss.

There are two parts to the Commerce Department tariff, one punitive and one preventative. The 61 Chinese companies identified with the dumping will be required to pay the 31 percent tariff. To prevent those companies from shipping into the U.S. under a false front, Chinese panel makers who have not been exporting to the U.S. will be required to pay a 250 percent tariff if they begin doing so.

Some say Chinese manufacturers are likely to get around the tariffs by using a non-Chinese false front. Others fear China will counter-accuse U.S. polysilicon manufacturers of unfair practices before the World Trade Organization.

Media reports say Chinese solar company stock prices fell with the Commerce Department announcement while U.S. panel makers’ share prices rose.

“From a broad view,” Little recently told GTM, referencing data that put the U.S. imported price of a Chinese module at 94 cents per watt, “a tariff would not be good for the industrybecause it would likely result in higher-priced modules.” But, as with the cost of Spire’s turnkey facilities, Little said, variables make all the difference.

In the same assessment from which he got the 94 cents per watt Chinese module price, Little found that U.S. manufacturers would require a 31 percent tariff if they were to import Chinese wafers to manufacture modules. The wafer price would be 35 cents, the wafer to module conversion cost would be 88 cents and the U.S.-made module would cost $1.23.

Domestic manufacturers would, however, only need a 14 percent tariff if they were toimport Chinese solar cells at 53 cents to make modules. The cell-to-module conversion would cost 54 cents, making the cost of a U.S. module $1.07.

And, Little found, if a U.S. manufacturer were to import laminates at 70 cents, a laminate-to-module conversion cost of 24 cents would make the price of a U.S. module cost 94 cents and no tariff would be needed.

Spire offers turnkey assembly lines that perform all three of those manufacturingprocesses.

Spire, Little said, will continue to thrive despite the tariff. They have customers all over the world. They rode the Chinese expansion of the last few years very successfully and have turned their attentions more recently to India, where a 20,000-megawatt solar target, incentive programs and an entrepreneurial inclination are sparking a major expansion. His company has also recently done business in such disparate and expanding markets as Ethiopia, Turkey and Romania.

“We know what’s going on all over the world,” Little acknowledged. He had no fear of a backlash or a trade war from the tariff but, in fact, saw it as an opportunity.

Germany-based SolarWorld and Japan-based Sharp, which according to Little dominate the U.S. crystalline silicon PV market, obtain their manufacturing equipment in their home markets. Spire, Little said, therefore has no chance to win their business.

A tariff, though, will bring new customers. “We talk to the top ten Chinese manufacturers,” Little said. “We have a come-to-America program. We’ll give you the machines, we’ll set you up, we’ll help you do the whole thing in America.”

Ultimately, Little said, the real problem will come if the tariff impedes the advance of the levelized cost of solar energy-generated electricity in the U.S. and around the world towardgrid parity.

Module prices may rise, Little predicted, but a healthy competition will return to the broader solar sector and that could drive prices down. “I would’ve loved to have seen theconcentrated solar cell (CPV) market take off. But CPV has the same problem everyone else has,” he explained. “There’s no traction because of these 88-cent modules coming in.”

Parity, Little said, is “a systems-driven equation.” The total calculation could remain competitive, he insisted. “If you start with the laminate, you can compete right now.” But, he said, if you want to start with cells, it’s going to cost you a little more.”

To keep the price low, U.S. manufacturers have to learn where the competitive point to enter the value chain is, Little said. “That’s the whole point.”

The tariff will also shift the international market, Little acknowledged. Chinese laminate manufacturers will find a ready market in the U.S. but cell and wafer manufacturers “will have a difficult time being competitive” unless the tariff drives them “to manufacture in the U.S.” Likewise, he added, with the knowledge of where to enter the values chain, domestic manufacturers “can compete then, too.”

“An extended outage of both SONGS units may create local reliability issues during heat waves for San Diego and parts of south Orange County,” the California Independent System Operator Corporation (CAISO) said. “Parts of the grid serving the Los Angeles Basin may also be stressed during high demand periods.”

To meet Southern California’s demand for electricity without hamstringing its economy, the ISO is making plans that will put into action idled power plants, new transmission, the state’s best practices, renewables and cutting edge grid tools.

“Southern California Edison’s four replacement steam generators at their San Onofre Nuclear Generating Station failed in less than two years of operation, while the original equipment operated for 28 years,” noted a just-released Fairewinds/Friends of the Earth report.

SCE has, according to the Fairewinds report, acknowledged replacing the steam generators as “a strategic decision to avoid a more thorough license amendment and review process” by the Nuclear Regulatory Commission (NRC).

The right solution to the vibration problem that led to the shutdown, according to Fairewinds, requires “major modifications with repair and outage time that could last more than eighteen months if Edison and Mitsubishi are even able to repair these faulty designed steam generators,” adding, “the safest long-term action is the replacement of the San Onofre steam generators.”

While SCE continues to work with the NRC to bring SONGS back, the ISO is working to minimize impacts.

“We are not the safety experts. That’s the NRC,” said ISO Director of Communications and Public Relations Stephanie McCorkle. “Our job is to plan.”

The ISO is, McCorkle noted, doing “contingency planning in coordination with the Governor’s office, state energy agencies, federal officials and the utilities [because the loss of SONGS] reduces local electricity supply and the ability of the high voltage grid to import power into the region that already has limited transmission lines.”

McCorkle was blunt. Without contingency planning and mitigation of that 2,200-megawatt loss, she said, “We would be in the hole.”

The focus of the ISO’s planning has been two gas-fired power plant units previously closed as a result of the state’s efforts to clean up its power supply and two under-construction transmission lines.

The ISO considered it “absolutely critical to get units three and four at the Huntington Beach Power Plant available for dispatch, and that was done as of Friday,” McCorkle said.

“The Huntington Beach units not only add 452 megawatts of capacity in the LA Basin,” the ISO reported, “but also enable 350 megawatts of additional imported power to transfer into San Diego.”

Bringing these units back will cost SCE and San Diego Gas and Electric (SDG&E) $2.5 million per month. Air quality regulators have permitted their service through November 1.

Completing the Sunrise Powerlink and Barre-Ellis transmission lines on schedule in June, before the summer’s peak demand hits, McCorkle said, will “strengthen the transmission system in general and allow us to import more power from the Southwest.”

Without these mitigations, McCorkle said, the LA Basin would be short 240 megawatts on a high-demand, hot day and the San Diego area would be short 337 megawatts. With them, she said, we only have reserve margins of thirteen megawatts in San Diego and of 212 megawatts in the LA Basin.

The ISO has also secured $9 million in funding from the California Public Utilities Commission (CPUC), McCorkle said, to reactivate its Flex Alert conservation campaign. Radio and TV ads will begin appearing in late June that will teach consumers conservation measures for Southern California’s 4 p.m. to 6 p.m. “air conditioner rush hour,” when load is most likely to exceed ISO capacity.

Finally, McCorkle said, the ISO and the utilities are “encouraging more participation in local voluntary demand response (DR) programs.” As a result, recent SCE and SDG&E smart meter programs may pay off sooner and bigger than expected in heading off rolling power outages.

“Because SDG&E has 100 percent smart meter penetration,” McCorkle said, “it can track how much customers are cutting back.” Customers who conserve will, for the first time in California, be compensated without having to enroll in a program. It is “a way for people to respond and be compensated,” she explained. And conserved energy, she added, “iscounted like any other resource. This is where people power is going to pay off.”

The ISO is also, McCorkle said, “analyzing the potential long-term implications of being without the San Onofre units.” Its conclusion, she said, is “there aren’t adequate resources to replace San Onofre permanently. We’re just trying to fill the holes as best we can."

The verdict is in. And it’s not good for Chinese solar manufacturers.

Eric Wesoff: May 17, 2012

Advocates say solar’s “civil rights policy” is under attack, and utilities say it is unfair to ratepayers.

Greentech Media By:Herman K. Trabish: May 15, 2012

After a series of fits and stops, a Califor­nia gasified coal generation project par­tially funded by the Energy Department advanced this month when its Massachu­setts-based owner filed a new construc­tion plan with the California Energy Com­mission for the project, which it bought a year ago from original backers BP plc and Rio Tinto. Privately held SCS Energy California LLC on May 3 submitted the amended applica­tion for a construction permit for the Hy­drogen Energy California (HECA) project, an integrated gasification combined cycle power plant that will create hydrogen to generate nearly 300 megawatts of electricity using a fuel blend containing 75 percent western bitu­minous coal and 25 percent petroleum coke. 

The project, sited in the oil-rich Kern Val­ley, will use Mitsubishi Heavy Industry’s ox­ygen-blown dry feed gasification technology to capture at least 90 percent of its carbon di­oxide (CO2) emissions and will transport the greenhouse gas for use in enhanced oil recov­ery in the nearby Elk Hills Oil Field owned and operated by Occidental of Elk Hills Inc.

And in a new wrinkle aimed at improving the project’s economics, SCS Energy says the HECA project also will generate up to 1 million tons annually of nitrogen-based products, in­cluding urea, urea ammonium nitrate and an­hydrous ammonia to be sold for agricultural, transportation and industrial use.

While the amended construction applica­tion signals new life for HECA, the project un­derscores the difficulty DOE faces in retaining industry participants in public-private part­nerships to demonstrate carbon capture and storage (CCS) technologies, seen as crucial for the continued use of coal for electricity in a carbon-constrained regulatory environment.

One of the five CCS projects awarded size­able grants under DOE’s Clean Coal Power Initiative—a post-combustion CCS project at American Electric Power’s Mountaineer Plant in West Virginia—was shelved by the util­ity after state regulators refused to allow cost recovery for the project. A second, Southern Co.’s Kemper Count integrated gasification combined cycle plant, is still on track but fac­ing increasingly vocal opposition due to sub­stantial cost increases and legal challenges.

HECA, unveiled in 2007 by BP and Rio Tinto, was one of a wave of projects that BP, in partnership with U.S. or foreign compa­nies, proposed to demonstrate various CCS technologies. In statements explaining the project, BP and Rio Tinto officials said they formed the joint venture to help meet the huge increase in projected energy demand over the next 25 years while minimizing emissions of CO2.

In September 2009, DOE selected HECA to receive $408 million in funding from the American Recovery and Reinvestment Act of 2009 through the department’s Clean Coal Power Initiative. The agency had disbursed about $54 million of that competitive grant when BP and Rio Tinto, which each contrib­uted $55 million for feasibility studies and other work, walked away from the project and sold their shares to SCS Energy in May 2011.

“We simply could not make the project commercially viable in that form at that time, whereas it obviously suited the purchaser better than BP and Rio Tinto,” BP spokesman Robert Wine told The Energy Daily Friday.

At the time of the sale to SCS Energy, HECA officials said the sharp drop in natural gas prices did not play a role in BP’s and Rio Tinto’s decision to sell the project.

BP also apparently scaled down plans an­nounced in 2006 to partner with Edison Mis­sion Group, a subsidiary of Edison Internation­al, to build a 500 MW hydrogen-fired power plant at BP’s Carson, Calif. refinery and seques­ter 40 percent of the project’s CO2 emissions. Instead, the companies on April 11 received ap­proval from the California Energy Commission to build an 85 MW gas combustion turbine at the refinery to complement an existing 385 MW cogeneration facility at the site.

The HECA project under SCE Energy is ex­pected to benefit California by furthering the state’s pioneering carbon policies, boosting oil production in the state and replacing im­ported, high-carbon footprint fertilizer with domestic, low-carbon footprint fertilizer, state officials said.

“They have developed an innovative busi­ness model that improves the economic vi­ability of the project,” California Public Utili­ties Commission President Michael Peevey said in a May 3 press release. “HECA intends to ramp up the facility to produce more elec­tricity during peak hours of need in order to maximize the energy and capacity value of the plant. This is an example of the kind of creative thinking we will need to solve the climate crisis.”

DOE continues to push the project, saying it will be among the cleanest commercial fos­sil power plants built or under construction. The plant also will far exceed California’s CO2 performance standard, which requires new plants to emit no more CO2 than a gas-fired combined cycle plant.

“The HECA project underscores the signif­icance of [CCS]—the creative combination of business drivers and environmental responsi­bility,” DOE Assistant Secretary for Fossil En­ergy Chuck McConnell said in a statement. “It demonstrates how carbon capture tech­nology will help us fully develop and use our vast domestic energy resources in a sustain­able way. And by utilizing the captured CO2 for enhanced oil recovery, the project pro­vides significant economic and job creation benefits.” 

By Thomas Spencer -- The Birmingham NewsThe Birmingham News

The coal-powered Gaston Steam Plant near Wilsonville in Shelby County was first opened in 1960. The plant's five generating units are together capable of nearly 2 million kilowatt hours of electricity. (The Birmingham News 2000 file photo)

BIRMINGHAM, Alabama-- Utilities in Alabama are using more natural gas and less coal to generate electricity as gas prices fall and clean air standards get tougher. And the trend is likely to continue.

Alabama Power disclosed this week that it plans to connect its coal-fired Gaston steam plant in Shelby County to a natural gas pipeline, allowing smaller and older units at that plant to use natural gas rather than coal to generate power.

That comes on the heels of a conversion earlier this year of the Alabama Power plant in Gadsden from coal-fired generation to natural gas.

In 2011, Alabama Power used coal to generate 58 percent of its electricity. Compare that to 1999, when 77 percent of Alabama Power's electricity was produced through coal-fired generation. In 1999, natural gas produced only 1 percent of Alabama Power's total. In 2011, it had risen to 16 percent.

Natural gas prices have plummeted thanks to advances in drilling and extraction technology that allow for the extraction of gas from fractures in rock formations deep underground.

Natural gas burns cleaner than coal and produces less carbon dioxide. However, its environmental toll is still being calculated. The new drilling method requires vast amounts of water, which is combined with chemicals and injected underground. So-called fracking has the potential of tainting drinking water. It is non-renewable and contributes to greenhouse gases. Environmentalists are fighting a land rush for drilling rights and fear the cheap abundance of natural gas is removing a motivation to develop non-polluting energy sources.

Alabama Power uses gas in a variety of settings. Plant Barr near Mobile and its Greene County plant can switch between coal and natural gas. Alabama Power also provides power to private industrial clients at co-generation facilities that use gas.

The utility also purchases electricity generated by gas on the open market when prices are favorable.

According to company spokesman Michael Sznajderman, those prices have been very favorable lately: "If we can buy power cheaper than we can produce it, then we do. It's a benefit to our customers and helps us keep prices low."

Alabama Power hopes to have its four smaller generating units at Gaston, representing 1,000 megawatts of generating capacity, converted to natural gas by 2015. Sznajderman said that project will involve building a gas pipeline to tie into the Transcontinental pipeline, which runs across Alabama about 30 miles south of the plant.

TVA spokesman Scott Brooks said the Tennessee Valley Authority is also increasing gas use and decreasing its coal dependence: "I would say that we are following the same pattern." According to a 2011 settlement with the U.S. Environmental Protection Agency, TVA agreed to retire 18 coal-fired generating units.

That includes six at TVA's Widows Creek plant in Stevenson. Other coal units, including five units at its Colbert plant near Tuscumbia, are being evaluated for further air pollution control work or retirement. "At that same time, we have increased our gas capacity over the past year," Brooks said.

TVA has set a goal of moving toward a generation mix of 30 percent gas, 30 percent coal, 30 percent nuclear, and the remaining 10 percent from hydro-generation and other renewable sources, including energy efficiency measures.

New standards

Alabama Power is not giving up on coal. Gaston's largest unit, which can produce 880 megawatts, will remain coal-fired.

That unit already has updated pollution control devices, and will likely require additional measures to meet new standards requiring a reduction in the power plant's releases of mercury and other air toxics. The company is looking at installing a "baghouse," a pollution control device that removes particles from the air, there and at three coal-fired units at its Gorgas plant in Walker County.

The mercury and air toxics rule is just one of a series of tightening environmental regulations that are causing a reconsideration of coal. Ozone and particle pollution standards are both expected to be tightened within the next couple of years.

Burning coal also leaves behind vast amounts of coal ash, a residue waste that is tainted with heavy metals.

Typically, it has been stored on site at power plants either in landfills or settlement ponds. Following the massive coal ash spill at a Tennessee Valley Authority plant in December 2008, the U.S. Environmental Protection Agency has taken a much more aggressive approach toward regulating that waste.

Beyond that, in March the EPA proposed a rule to limit carbon dioxide releases from power plants. The new rule does not apply to existing plants. However, energy analysts say if the proposed rule goes into effect, it would effectively prevent the construction of any new coal-fired plants.

Oil’s market share has dropped to below 40 percent and continues to decline.

Toby D. Couture: May 10, 2012