The heat exchange fluid for high temperature applications that has been patented also has the advantage that it does not compromise other relevant variables, such as the stability of the fluid at high temperatures. This characteristic allows it to be used in current facilities, without the need for any changes to be made to infrastructures in order to adapt them. The cost of this new nanofluid (to which nanoparticles are added in order to enhance and improve heat conductivity) is similar to that of the base fluid, since both the nanoparticles and the stabilizers used are inexpensive. All these features make it suitable for industrial applications that employ heat transmission/exchange systems. The lecturer of Fluids Mechanics at the UJI, José Enrique Juliá Bovalar, explains that, after testing the thermal properties of the nanofluid and patenting this new technology, the research group has started the phase of searching industrial partners either to transfer the nanofluid over to them or with whom applications can be jointly researched and developed.

Heat exchange fluids are fluids used to transport heat in a number of industrial applications. These fluids are employed to transport energy in the form of heat from the point where the heat is generated (burners, cores of nuclear reactor, solar farms, etc.) to the system that is going to use it (thermal storage systems, steam generators, chemical reactors, etc.). The most widely used thermal fluids are water, ethylene glycol, thermal oils and molten salts. One characteristic that is common to all of them, according to Juliá, is “their low thermal conductivity, which is what limits the efficiency of the heat exchange systems that use them. The technology that we have developed at the UJI overcomes these limitations and increases the thermal conductivity by adding an exact proportion of nanoparticles consisting on carbon and other additives to the base fluid (diphenyl/diphenyl oxide), while maintaining the original range of operating temperatures of the base fluid, which can range from 15°C to 400°C”. In this way, it becomes possible to obtain increases of up to 30% in the thermal conductivity of the base fluid. All this is achieved without compromising the stability of the fluid and with a moderate increase in its viscosity, which means that it does not give rise to any problems with pumping, the precipitation of nanoparticles or the obstruction of conduits.

Finally, Juliá notes that the method employed to produce the nanofluid is easily scalable to the industrial level, since it is not necessary to make significant changes at the facility where the base fluid is used. In addition, the nanofluid developed is based on a heat transfer oil (diphenyl / diphenyl oxide) that is widely used in industry, and it does not increase costs because both the nanoparticles and the stabilizers used are abundant, readily accessible and inexpensive.

After a national public tender process the results are available. The four corporations GDF SUEZ, EDP Renewables, Neoen Marine und Areva want to work together to build offshore wind farms with a capacity of about 1,000 MW in France. The start of construction is planned for 2019.

The Dutch equipment manufacturer Eurotron opens the world first Competence Center for back contact module technology in Bleskensgraaf, the Netherlands. The Eurotron Competence Center is capable for lab-, test- and pre-production of all sorts of back contact solar PV modules.
Although the exact amount of Eurotron’s investment is not disclosed, a view in the Competence Center presupposes that a significant investment has been done.

Here you can find a small selection of comprehensive market overvies from the solar thermal sector:

Market Overview: Vacuum Tube Collectors

Market Overview: Flat Plate Collectors

Market Overview: Solar Stations

Market Overview: Thermosiphonic Systems

With few exceptions, most commercial projects we see come from developers going out to the market with each individual project, which will then go to the highest bidder. That sounds straight-forward. Why wouldn’t a developer want to go after the highest price? Two words: transaction costs.

Though auctioning a project to the highest bidder and getting a couple extra cents may sound attractive, it is important to account for higher legal and other transactional costs associated with negotiating these one-off deals. The longer you work together with someone, the easier, quicker, and [subsequently] generally more efficient — and less costly — the transactions become for all parties. Relationships matter.

Moreover, working with a trusted investor partner from day one can provide developers with the necessary guidance to craft the most profitable project possible and get legal documents and deal structure right the first time. Developing a project with the end buyer, the investor, in mind willl increase deal value once the project or portfolio is ready to be financed.

For the middle market (what we define as 200 kW to 5 MW) to be successful, strong financing partnerships — whether formal or informal — must be in place. Given the high transaction costs associated with relatively smaller deal sizes, investors are more likely to consider a one-off sub-1MW solar project when repeat business is a sure bet.

When evaluating potential partners, Sol Systems looks first at whether a developer is relationship or transaction driven. If they are relationship driven, we are more likely to work through “hairier,” smaller deals (i.e. deals with less-than-ideal host credit, property tax issues, long development timelines, etc.). In an industry where pipeline is king, the prospect of future business makes the time (and thus, the money) spent on these projects worth the effort.

For Sol Systems, ideal developer partners are those who can develop at least 5 MW in a given year. That said, when looking at an ideal partner, size isn’t everything. More than anything, we value trust, transparency, and integrity. Together, these characteristics make for a long-lasting, fruitful relationship for all parties.

The following is an excerpt from our Solar Project Finance Journal, a monthly electronic newsletter analyzing the solar industry’s latest trends based on our unique position in the solar financing space. To view the full Journal or subscribe, please e-mail pr@solsystemscompany.com.

“Countries that aggressively expand solar have significantly higher costs than their neighbors” for energy, said Johnson, who has sell ratings on five of the six solar manufacturers he covers.

Solar power doesn’t compete with oil as a source of electricity except on small islands and in some crude exporting countries. Oil generates less than 1 percent of U.S. power supplies and 5 percent globally.

That link may be more emotional than based on fundamentals, said Josh Baribeau, an analyst at Canaccord Genuity Inc. in Boston.

“We believe that part of the solar sell-off may also be driven by the fall in oil prices,” he said in a note to clients on Oct. 14. “We have never liked the psychological correlation between solar stocks and oil, but it exists to some degree.”

All but two companies in the solar index have declined in the past month. Yingli Green Energy Holding Co., the biggest panel maker, slipped 17 percent and Trina Solar Ltd., the No. 2 producer, declined 24 percent. The index rebounded to gain 2 percent at the close yesterday in New York.

“A drop in oil doesn’t affect our space,” David Crane, chief executive officer of NRG Energy Inc., said yesterday in an interview. This year, the largest U.S. independent power producer acquired three solar power supply companies.

Copyright 2014 Bloomberg

Lead image: Oil rig via Shutterstock

The EPA’s proposed rule to regulate carbon dioxide from existing power plants emphasizes the ample flexibility it provides to states. However, careful analysis of the rule shows that it provides significant flexibility for how states can achieve the required CO2 reductions, but little flexibility on when to achieve them. In fact, most of the emission reductions it calls for are required in 2020, the rule’s first year.

These dramatic early emission reduction requirements — often 30 percent to 50 percent below the 2012 benchmark — should be expected to render large numbers of coal plants uneconomic and hence lead to their retirement in 2020.

This sudden retirement is likely to cause resource adequacy risks, high power prices, and the rapid deployment of large numbers of new natural gas combined cycle power plants, especially in certain states and regions. Large amounts of new natural gas power plants at the beginning of the 2020’s, in turn, will tend to lock-out renewable and other clean energy technologies, potentially for decades — especially since more efficient end use is likely to keep overall demand for additional power plants from growing.

This lock-in of new gas generation and corresponding lock-out of renewable and other energy technologies could seriously delay the longer term de-carbonization of the U.S. power sector. However, this unintended consequence of the proposed rule can readily be avoided by one or more of the following modifications in the EPA’s final rule.

• EPA should broadly defer to states to set the actual emission reduction trajectories needed to achieve the ultimate emission reduction goals in EPA’s final rule. Each state can craft an emission reduction trajectory to achieve these goals that will address legitimate state concerns such as resource adequacy, cost and stranded assets.
• Alternatively, EPA should modify the rule’s 10-year average compliance requirement, which is largely responsible for the dramatic first-year reduction requirements of the proposed rule. Allowing states to comply by meeting, on average in the first ten years, half of the reductions required by their interim goals would allow each state to select a uniform “glide path” trajectory from its 2012 benchmark levels to the EPA’s 2030 goals.
• EPA should also modify the timing of and the degree to which various building blocks in its assumed best system of emission reductions are activated. In particular, the EPA’s assumption that a full re-dispatch of existing gas to displace coal could be implemented overnight is unwarranted. Such a dramatic change needs to be phased in over time to avoid the significant resource adequacy, cost and other consequences of suddenly rendering large numbers of existing power plants uneconomic. 

These changes will support state plans that ensure the gradual but persistent transition from high to low power sector CO2 emissions, while limiting the reliability risks, price shocks, and other significant problems the proposed rule is poised to create. At the same time, they will help avoid the immediate lock-in of large amounts of new gas. Instead, they will ensure states can devise gradual transitions to renewable energy, fossil resources that capture and use carbon, and efficient distributed clean energy systems, thus producing far greater overall CO2 reductions at a lower cost. 

Lead image: Path on hillside via Shutterstock

PV systems can be a valuable asset to virtually any building if the correct factors are evaluated. A comprehensive rooftop PV installation should minimize building owners’ and large energy users’ risk while maximizing their return on investment. Therefore, those interested in pursuing these renewable options should look to experts to select the ideal system for their buildings.

When considering PV, it is crucial to first carefully evaluate the integrity of the existing roofing system. A typical rooftop PV investment is based on a 25-year financial projection. Therefore, the roof must be capable of sustaining an installation for at least that long in order to maximize returns.

Those considering a rooftop PV system should also remember to ask the following questions: 

• If you are a building owner, did you engage a roofing professional to ensure your roof is properly designed to sustain a heavy, expensive and long-lasting PV installation?
• Is the current or new roofing system suitable for traffic, weight and at least 25 years of performance of today’s PV systems?
• Will the maintenance or eventual replacement of the roofing system disrupt the power output of the PV?
• Who is responsible for paying to remove and reinstall a PV system during roof repair?

Integrated PV systems can be added to new cool roofing installations to create programs aimed at establishing concurrent lifecycles between roofing and PV systems. A “cool roof” reflects and emits the sun’s heat back to the sky instead of transferring it to a building below, according to the Cool Roof Rating Council, an organization created to develop credible methods for evaluating the integrity of these roofing options. A roof’s “coolness,” the council states, is measured by two properties: solar reflectance and thermal emittance. By syncing the lifespans of an integrated PV system and cool roofing installation, building owners can maximize renewable energy production and financial rewards.

Rooftop solar is purchased based on a calculated return on investment, ROI. The expense of disassembling and moving a solar array for roof maintenance or replacement can destroy building owners’ anticipated solar ROI. It is, therefore, crucial to check with building products manufacturers on ways to protect these investments, such as long-term warranties.