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A Call for More Solar in the Wake of South Carolina’s Nuclear Debacle [GTM Squared]

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Be the first to comment - What do you think?  Posted by Editor - August 20, 2017 at 6:10 am

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Aspiring Battery Innovator and Developer Alevo Files for Chapter 11 Bankruptcy

Alevo has joined the ranks of bankrupt battery manufacturers.

The company set up shop in a spacious former Philip Morris cigarette factory outside of Charlotte, North Carolina, to produce utility-scale GridBank battery systems. Persistent production challenges led to “insufficient revenue,” the company said in a statement.

Alevo finished its first commercial unit in January for deployment in Hagerstown, Maryland. It originally had planned to produce 200 megawatts by the end of 2015.

“The Alevo entities have actively sought new funding sources to finance their operations and growth strategies,” the statement said. “Unfortunately, despite best efforts, the funding has not been realized in time to permit continued operations.”

The company is the latest in a series of energy storage startups to run out of cash before they achieved sustainable revenue. Saltwater battery maker Aquion suffered a similar fate in March, even after outfitting its own factory in Pennsylvania to better control production costs. 

Alevo will lay off 245 workers from its North Carolina factory Friday, with another 45 to leave at the end of September, The Charlotte Observer reported. The company plans to liquidate its assets.

In October 2014, Alevo unstealthed with claims of a new lithium-ion battery that could beat the competition in grid applications. As GTM previously reported, Alevo claims its sulfur-based inorganic lithium-ion electrolyte chemistry has achieved 50,000 complete cycles without failure or loss of power density, while operating at close to room temperature.

The system passed a suite of performance testing by Parker Hannifin in January.

The company had two primary challenges: to bring an exotic new chemistry into production, and to own and develop projects with said chemistry. 

“Rather than waiting for third-party sales to drive that volume cost reduction, we’re driving it ourselves,” Jeff Gates, Alevo’s vice president of operations, told GTM in 2015.

The vertically integrated approach saves the trouble of convincing established developers to take a chance on a new technology. It also forces the company to excel at two very different and challenging roles simultaneously. Commercializing a new storage technology is notoriously labor- and money-intensive, even without bankrolling the installations as well.

The technology had some upsides, on paper at least. Alevo chose its sulfur-based chemistry in part because of its relative abundance and protection from wide swings in commodity costs, compared to components in conventional lithium-ion. It also theoretically comes with longer and deeper cycle life and low overheating risk. 

In choosing that kind of product, Alevo entered the battlefield of the lithium-ion alternatives, marked by numerous contestants and limited revenue opportunities.

Some, like Alevo and Ambri, have struggled to get their technology into commercial production on schedule. Flow battery companies ViZn, Vionx, UET and ESS have gotten a handful of initial demo projects installed, and are working on scaling up. Eos is in a similar position with its proprietary zinc-hybrid cathode battery.

Aquion passed that stage and achieved 250 deployments before it went bankrupt. The company recently emerged from bankruptcy under mysterious new management; its next steps are not clear. Fluidic Energy of Scottsdale, Arizona has fared better, raising $200 million and deploying 100,000 units of its zinc-air cathode in remote island and off-grid markets.

At the end of the day, there aren’t many customers for grid-scale batteries, and there are even fewer looking for batteries that haven’t been vetted by years of monitored operations in the field.

Those companies hope to capitalize on the value of long-duration storage, which lithium-ion is not well suited for. Alevo, though, was not chasing long durations to differentiate itself from the incumbent. Its core GridBank product comes in containerized 2-megawatt/1-megawatt-hour units.

Alevo was targeting the frequency regulation application, in which batteries provide and absorb electricity on a second-by-second basis to keep grid frequencies stable. PJM’s frequency regulation market remains the largest storage market in the U.S., but rule changes this year decimated that market signal.

This story is developing. Stay tuned for more updates.


Be the first to comment - What do you think?  Posted by Editor - at 6:00 am

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Inside New York REV’s Summer of Pilots, Non-Wires Alternatives, and Behind-the-Meter Frustrations

New York’s Reforming the Energy Vision initiative may appear to be moving slowly to the outside observer. But for the utilities, regulators and technology providers carrying it out, it’s innovation at a breathtaking pace.

After all, an ambitious overhaul of a state’s energy markets and utility grid operations and planning paradigms doesn’t happen overnight — or without a few unforeseen roadblocks derailing a project or two. 

Greentech Media’s New York REV Future 2017 conference next month will bring together policymakers and utility and technology executives working on this statewide transformation. (And remember, all GTM Squared members get access to our live stream!)

To inform next month’s discussion, we’ve pulled together utility updates, project descriptions, and other filings with the New York Public Service Commission under the REV proceeding, to get acquainted with what’s been, after an eventful spring, a relatively quiet summer.

Our team of analysts at GTM Research provided a good overview of the key accomplishments of REV this year, and what key questions remain to answer. These include whether or not the state will set an energy storage target, the status of the 17 REV demonstration projects ranging from virtual power plants to smart home energy portals, and how the state’s six big investor-owned utilities will start opening up more RFPs for non-wires alternatives — DERs deployed in lieu of grid investments — beyond the showcase Brooklyn Queens Demand Management project. 

The latest demo project reports reveal more challenges, like interdepartmental delays and technology integration challenges. Con Edison notified the PSC this spring that it was canceling its 4-megawatt-hour distributed solar-storage virtual power plant project with SunPower and Sunverge, after it couldn’t reach agreement with state building officials and the NYC fire department on how to permit its behind-the-meter lithium-ion batteries. 

This summer also saw New York’s utilities unveil a bigger list of non-wires alternative projects they’re planning to put up for bid, as well as award a couple of contracts to relieve load in midtown Manhattan by 2021.

On the customer-facing side of things, utility-branded marketplaces are getting homeowners online to check their bills, buy LED light bulbs and smart thermostats, and in a few cases, get up-to-date energy data — if they’re OK with the utility installing a special meter, since New York has just started to roll out smart meters. 

(A note to readers interested in reading the original documents: The PSC’s website doesn’t support direct linking very well, so if you want to read a particular filing, visit the PSC’s main REV docket page, find the title you’re looking for, and click.) 

The DER demos: A long way from pilots to DSPs

Let’s start with the demonstration projects linked to REV’s overall vision of a medium- and low-voltage distribution grid that’s fully capable of managing DERs at mass scale and compensating them for their grid value. REV has come up with some key goals on this front.

First, each utility is creating a distributed system implementation plan (DSIP) to guide how DERs will fit into its ongoing grid planning and operations. Each utility filed a DSIP last year, and after the PSC demanded some more information in a March filing, the utilities refiled amended versions in May. 

Second, REV is asking each utility to work toward becoming a distributed system platform provider, connecting “transactions between customers and third-party DER products and services.”

The set of technologies that will allow this to happen has been dubbed a distributed system platform, or DSP — it’s a bit like a goosed-up distribution management system, a bit like a transmission grid operator’s suite of operations and market management software, and it brings together a whole lot of new technologies now just being put to the test in real-world applications. 

National Grid’s Distributed System Platform pilot with the Buffalo Niagara Medical Campus and startup Opus One is taking on the challenge of field-testing its version of a DSP. We covered the launch of this $4.8 million, two-year effort at last year’s REV Future conference, when the partners were just starting on their plan to link up DER-equipped buildings to distribution feeders.

The eventual goal is to test Opus One’s real-time, two-way power flow modeling of these distribution circuits to dispatch and control DERs to solve grid problems, from voltage and VAR support in real time, to peak load modifications and dynamic load management over the longer haul. 

This is a complex effort, and not something that gets off the ground right away. In its second-quarter 2017 update, National Grid noted that it’s seen multiple delays, including a three-month delay to refine the financial modeling methodology for hourly price signals to DER owners, a formulation known as LMP+D+E (the local transmission node marginal energy price, plus distribution system values, plus environmental and social values).

Meanwhile, delays on advanced feeder modeling and forecasting from National Grid’s internal teams mean either waiting for that work to be done, or coming up with “other alternatives for feeder modeling and forecasting that are not as accurate.”

Still, the utility and partners are “working on a fast-paced schedule to catch up,” despite losing about one-third of their allotted time to reach second-phase goals like laying out the flow of data and controls between all the parties involved. A high-level overview of what they came up with is shown in the graphic below.

This isn’t the only REV project struggling to stay on its timeline. The Flexible Interconnect Capacity Solution demonstration project from Iberdrola’s New York Service Energy Group (NYSEG), Smarter Grid Solutions and Clean Power Research is aimed at creating “a new model for interconnecting [DERs] to the distribution grid using Active Network Management rather than firm capacity.” 

ANM is Smarter Grid Solution’s tech platform, which combines hardware at key DER and grid sites with a centralized software platform that orchestrates their operation for grid needs. The startup has already put its technology to work to balance wind power and loads to mitigate overloads on circuits feeding Scottish islands, for example.

NYSEG is hoping its own version will allow it to “manage DERs within grid constraints (e.g., voltage, overloads, etc.) using real-time sensing and controls, avoiding more expensive upgrades.” 

But to test that out, you need some DERs to play with — and that’s been slow going.

One, a 2-megawatt solar PV farm, landed an interconnection agreement with NYSEG in June 2016, but isn’t expected to come on-line until sometime between January and April 2018. Another, a 350-kilowatt farm waste generator, has been put on hold. Two more megawatt-scale PV farms are being considered, but one isn’t moving ahead because the owner of the site passed away “without providing land rights.”

Delays have proven deadly to Con Edison’s Clean Virtual Power Plant project. In April, the utility announced it had terminated its contract with SunPower and put its plan for hundreds of behind-the-meter residential batteries “on hold until further notice.” 

“While Con Edison, SunPower, and Sunverge have had many productive discussions with the [Department of Buildings] and [the Fire Department of New York], we have not yet been able to come to an agreement that would allow the system to be installed in a manner consistent with its original design, nor without making changes that would impact the timing of program goals as envisioned under the original contract with SunPower,” the utility wrote.

FDNY’s opposition to lithium-ion batteries behind closed doors has “caused challenges for New York City’s storage market for quite some time,” GTM Research analyst Brett Simon noted. A storage safety evaluation is underway, but it has yet to lead to faster permitting processes, he said. “New York City continues to be a market where developers note huge opportunity that’s hamstrung by Li-ion permitting issues.” 

Con Edison isn’t giving up completely, however. It pledged to keep working with the state and FDNY to find a “path forward” for residential battery permitting. When that happens, it plans to “enter into another contract, either with SunPower or another vendor, to deliver the program under a new agreement.” 

Non-wires alternatives: 200 megawatts and counting 

REV’s non-wires alternative (NWA) projects aren’t demonstrations, but rather first-of-their-kind contracts to open up utilities’ “black box” distribution grid planning and investment to participation from DERs. So far, only one has gotten off the ground — Con Edison’s Brooklyn Queens Demand Management project, meant to defer a $1 billion substation upgrade with a cheaper set of distributed alternatives — mainly energy efficiency, but also demand response, energy storage and solar PV. 

Over the course of the spring, the state’s big utilities complied with a PSC demand that they publish all their NWA opportunities in the form of an RFP and questionnaire posted online. Con Edison, O&RNYSEGRG&E, Central Hudson and National Grid now have their sites up and running, giving us more insight into what’s on offer. 

Con Edison is leading right now, with BQDM underway and two other projects recently opened and the other closed for bidding. The Hudson and Columbus Circle primary feeder relief projects in midtown Manhattan are seeking a collective 11.1 megawatts of summer peak load reduction. Two more projects seeking a combined 11 megawatts in Williamsburg and Flushing are expected to open this fall, and three more seeking 4 megawatts, 6 megawatts and a whopping 50 megawatts, respectively, are expected to open by the fourth quarter. 

One challenge with NWAs is that the underlying need for them can change underfoot. Con Edison canceled its 65th Street project due to lower-than-expected peak load in the area; it also scaled back in terms of both megawatts and delivery date another project within BQDM for the same reason. Reducing peak load through existing efficiency, demand response, or on-site power generation and energy storage business cases is a good thing, but it does tend to undermine the business case for DERs as a means of achieving grid asset deferral. 

Orange & Rockland has seven projects seeking a collective 32 megawatts of peak reduction, ranging from 15.5 megawatts to 280 kilowatts, between now and the mid-2020s. Central Hudson claims four projects, all already underway. And National Grid has the most projects, including 17 separate bids with a collective 117.5 megawatts of load relief and reliability need between 2019 and 2022. 

Meanwhile, NYSEG has a total of 10 projects, and fellow Iberdrola utility Rochester Gas & Electric has five projects, which they’ve measured not in megawatts but in cost: $49 million for RG&E and $57.5 million for NYSEG. These utilities also have the widest timespan in projects, with some delivery dates in 2030 and beyond, as shown below.

Customer connectivity, online marketplaces, and the matter of smart meters 

Most of the REV demo projects are aimed at getting utility customers online, connected, aware and involved in how they use energy. They’re also aimed at helping customers understand how their distributed energy investment choices affect the broader system’s needs.

Five of the 17 projects are testing out “utility-branded marketplaces” — web portals that offer online shopping and easy-claim rebates for LED light bulbs, smart thermostats, and other third-party gear, along with customer service features like bill payment, energy alerts and enrollment into load-control programs. 

The general approach is largely traditional, as evidenced by last month’s update from Rochester Gas & Electric’s Energy Marketplace. The portal is run by Simple Energy, a San Diego, Calif.-based startup with big utility customer connectivity projects across the country. In its recent quarterly update, it reported such efforts as “promoted thermostat and lighting sales in conjunction with Earth Day and Mother’s and Father’s Day as well as the summer season in general.” 

Some of the customer-focused REV demos are getting deeper into customer data. Central Hudson’s CenHub project involves Simple Energy and Comverge, the demand response provider now owned by Itron.

In June, Central Hudson started testing Insights+, a subscription service for residential mass-market enrollment, which “enables drill-down into time-based electric usage dashboards,” with data in annual, monthly and hourly intervals. It also started a 63-home test group whose subscriptions are paid for by Comverge, and had installed 17 Insights+ meters, the cellular meters supported by its January agreement to have Itron take over its advanced metering efforts.

Central Hudson, like the rest of New York’s utilities, is hampered by its lack of smart meters — a big difference from California, which has been fully smart-metered for most of this decade. Smart meters provide interval data, the lifeblood of energy data analytics. And while most large-scale commercial and industrial customers have some form of interval metering, the mass of New York’s residential customers are still equipped with old-fashioned electromechanical meters. 

The limitations of this situation are displayed in utilities’ proposals for how to test out Smart Home rates — the REV-defined rate structures meant to support time-of-use and peak pricing today, and a broader set of options for DER-equipped homes in the future.

Central Hudson is proposing a new time-of-use electric rate for customers in specific geographic regions who agree to get an Insights+ meter or load control device. National Grid is proposing a test in its Clifton Park project, featuring about 1,400 meters from Itron. And NYSEG and RG&E have proposed a “distributed storage simulation platform to test price signals and the associated customer response that results.” 

Con Edison and O&R, meanwhile, have proposed adding “smart home capabilities” and demonstrating new pricing frameworks alongside their AMI deployments with Silver Spring Networks. Silver Spring CEO Mike Bell noted in an earnings call earlier this month that Con Edison turned on its first metering connections in Staten Island this spring, marking a milestone in terms of real-world deployments.

But there are still 5 million more meters and five years to go before every customer in the territory has one. Sister utility Orange & Rockland filed an application in January that included an expansion of its existing AMI rollout to a full deployment for an additional $98 million.

New York’s AMI lag is playing to its advantage in terms of technology, however.

Con Edison’s $1.3 billion smart meter rollout with networking vendor Silver Spring Networks will support an AMI network with more granular interval data capture and exchange, more robust two-way connectivity, and a more smoothly integrated back-end than the Silver Spring network rolled out with California’s Pacific Gas & Electric. And Itron’s rollout with Central Hudson uses technology far more flexible than the smart meters it deployed for Southern California Edison and San Diego Gas & Electric. 

Interested in going even deeper? We’ve got you covered at GTM’s New York REV Future 2017 conference on September 26 and 27 in Brooklyn, New York. Sign up today. It’s a must-attend if you’re doing business in New York, or if you’re from another area of the country and trying to understand the Empire State’s reforms.


Be the first to comment - What do you think?  Posted by Editor - August 19, 2017 at 6:40 am

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The Threat of Tariffs Is Already Reshaping the US Solar Market

You’ve probably heard about the solar eclipse that will pass across the U.S. on August 21.

But if you’re in the solar industry — whether a manufacturer, contractor or service provider — you’re no doubt aware of a much more significant eclipse: the United States International Trade Commission (ITC) case on imported crystalline-silicon solar cells and modules.

You may think that this industry eclipse is not a big deal, or that it’s someone else’s problem. You’re wrong. It’s time to break out your peril-sensitive sunglasses.

Suniva and SolarWorld are seeking tariffs of $0.40/watt on all imported solar cells and a minimum price of $0.78/watt on solar modules that use imported solar cells. On September 22, the ITC will determine if the crystalline-silicon PV industry was harmed by global trade practices. If harm is determined, a remedy recommendation will be sent to President Trump.

I’m normally a very optimistic guy — otherwise I wouldn’t be in the solar industry. But a tariff or minimum price of this magnitude would present severe difficulties.

It would effectively double the price of the vast majority of modules installed in America. Current production of solar cells in the U.S. is currently negligible, and it takes two or more years to begin production of solar cells at a new or relocated factory. If a tariff or minimum price is imposed, we can expect that all solar module prices that use imported cells will increase (including those assembled in the U.S.), and this increase will persist for several years until domestic cell capacity ramps up. 

Long-time industry participants have seen a similar story play out before. The worldwide silicon shortage that began in 2004 had a significant effect on solar module pricing.

At that time, the worldwide solar industry was much smaller, and the $1.00/watt increase in prices did not have as big an impact when average installations were still in the $6 to $10/watt range (12.5 percent). However, a $0.40/watt increase today will be applied to utility-scale system prices of $1.00/watt (40 percent), substantially reducing the economic benefits of these large projects. 

Supply chain impacts

Simple economics tells us that the tariff price increase will reduce demand from residential, commercial and utility customers.

Let’s consider what is happening throughout the entire solar supply chain. First, solar module manufacturers are already reacting by accelerating shipments to the U.S. before mid-November. Any shipments that arrive after a tariff decision would be penalized. Building U.S. inventory is a low-risk way to continue to supply the market, but shipments that arrive after the tariff is imposed will be subject to an unknown cost increase.

As soon as this ITC action was initiated, suppliers to worldwide solar module manufacturers started ramping up deliveries of “ingredients” such as glass, aluminum and wafers. But there is only a limited amount of surplus component capacity that can be manufactured into modules — so shortages are already occurring.

Since a final remedy decision will not be made until January 2018, it is uncertain which countries will be affected and what the size of the tariff will be. Manufacturers are sitting on the sidelines waiting to see what happens before they make any major U.S. investments. During these uncertain pricing times there is unlikely to be any production planned for shipment to the U.S. that would arrive after a tariff imposed.

Savvy consumers of solar modules, primarily utility-scale developers, are taking early delivery of modules for their projects right now — even if these projects may not be slated to begin construction until 2018. Distributors and installers are also preordering for upcoming projects. Available inventory is getting soaked up like water seeping into a dry sponge.

From a solar module manufacturer’s standpoint, demand is very high and supplies are limited. Since many of these companies were making tiny profits (if at all) before, they are taking the opportunity to increase prices. These prices are being passed on to distributors and installers, who must pass these increases on to their customers or lose profit on jobs.

Customer impacts

Utility-scale customers are deferring purchasing decisions. Since this is the biggest market segment, it should come as no surprise that utility-scale developers and suppliers have mobilized swiftly to fight this tariff action. Companies in the entire utility-scale supply chain will be hit the hardest since a $0.40/watt increase in prices destroys the current economics of most projects.

Financiers, developers, engineers, salespeople, consultants, racking manufacturers and inverter companies are seeing their post-2017 pipelines disappear as customer economics have deteriorated. The C&I solar segment is seeing a similar contraction in demand, although one that’s not quite as dramatic, since prices in these segments are higher.

I spend most of my time focused on the residential market segment, where sales cycles are much faster. As such, most residential contractors have not been affected too dramatically — yet.

Module prices have increased by about 20 percent, and future availability is uncertain. It will indeed be more difficult to sell systems when the price of the main component goes up by about $0.50/watt (the $0.40/watt will be marked up). For contractors who have inventory, sales through the end of 2017 could be brisk. But if contractors need to purchase modules on the spot market at higher prices, they could see their profits completely wiped out.

This same situation happened in 2004 and 2005 when prices of modules went up by about $1.00/watt. Customers generally refused to renegotiate contracts due to higher prices, and some contractors defaulted on contracts or went out of business when they realized they would lose money on their pipeline of jobs.

Overall I expect the U.S. residential market to be smaller than we expected in Q4 of 2017, and for the foreseeable future, until affordable U.S. production of cells and components ramps up.

Companies in all segments of the residential supply chain — including racking, inverters, financiers, lead generators, software developers and service providers — will be hit by this slowdown. Attendees at Solar Power International 2017 in Las Vegas next month will have a chance to reconnect with suppliers and friends, but there will be no “selling” among module companies, since they will have no inventory to sell and will not know what their future price will be.

There is a silver lining to this eclipse, but only for a few companies — primarily thin-film module manufacturers that do not use crystalline-silicon cells.

American module manufacturers are seeing an almost ludicrous demand increase, but since they source cells from overseas, they will also have to pass on the increase in price from a $0.40/watt tariff.

Moreover, these manufacturers have limited ability to quickly increase their capacity. Cell equipment manufacturing companies are seeing an increase in interest, but probably no committed orders until a final tariff determination is made. Remember that it takes two or more years to design, purchase, build, install and configure a new state-of-the-art cell manufacturing line, so the U.S. industry will be in the doldrums for several years.

What can we do to rebuild American solar ​manufacturing?

A Section 201 trade case is an incredibly blunt instrument when applied to a complex global industry like solar module manufacturing. I read with dismay that another component supplier recently shut down operations in Oregon after its biggest solar module customer went bankrupt. Tariffs on solar cells did not work the last time around.

The ITC’s prehearing staff report on this case noted that 26 solar manufacturers shut down operations in the U.S. since 2012.

So what can we do to rebuild U.S. solar manufacturing? Unfortunately, slapping a $0.40/watt tariff on all imported cells may not be enough of an incentive to quickly release the billions of dollars it will take to build gigawatts’ worth of state-of-the-art solar cell manufacturing. We need to consider the entire solar module supply chain — not just the cells themselves.

Because of the complicated supply chain for solar module manufacturing, just building a solar cell plant here in the U.S. that will come on-line in 2020 will not make the U.S. competitive with modules from other countries.

American manufacturers still must import almost all the other components, since domestic supply is either not available at all or priced higher than from other countries. For example, frame extrusions for solar modules cost twice as much in the U.S. than those available at comparable quality from Asian countries.

A dozen years ago, when China decided to make a big commitment to the solar industry, it incentivized not just cell and module manufacturers, but also silicon, glass, aluminum, backsheet and junction-box manufacturers. Large-scale module manufacturers designed integrated operations combining almost the entire supply chain.

China planned complete solar manufacturing cities — like Detroit for cars, but for solar modules. Wafer and cell operations were situated next to extruders, junction box companies and module assembly plants, thereby reducing logistics costs and reducing turnaround time. Of course, many of these companies benefited from favorable government policies — just as America provides in terms of federal tax credits, as well as state and local incentives.

Here in the U.S., we must put thought into a comprehensive solar industrial policy that considers all aspects of the supply chain. Expecting a better outcome by adding capacity at one point while ignoring other points is insanity.

In order to compete in the global module manufacturing industry, the sum of the costs of all the ingredients, including labor, must be competitive. Right now, virtually every factor of production is more expensive in the U.S. Once this rationalized supply chain policy is in place, existing U.S. module assembly companies will benefit the most — as well as customers that prefer modules made in the U.S.

In the meantime…

While trade commissioners and legions of lawyers figure things out, many of us have businesses to run. We can see this slow-motion train wreck materializing, so there are actions we can take to reduce the harm to our businesses.

Rhone Resch’s recent GTM article provided terrific advice for project developers. Residential and commercial contractors who operate with fewer resources and shorter time frames can take action to mitigate the risks to their businesses.

Now is a good time to preorder inventory for installations in Q3 and Q4 — there is still some product availability. If past experiences are any indication, some module manufacturers may cancel purchase orders or increase prices on unshipped orders. Distributors will do the best they can to ration out supplies to their best customers. No company is likely to get all the inventory they want. And everyone should plan on continued price increases.

Contractors must make sure they price jobs based on when they will receive modules for that job. One good strategy is to purchase inventory immediately when a contract is signed, even if the job will not be ready to start for a few months. Customer proposals should have a fairly short time frame during which prices will be honored (say five business days).

Consult with your attorney to see if a “force majeure” clause can be added to your contracts that would allow you to cancel a contract or raise prices if a tariff is imposed. The one shred of good news for contractors is that a 2018 price increase is a good incentive for customers to buy now.

Finally, we should continue to support our solar industry advocacy organizations, including the national Solar Energy Industries Association and the state SEIA chapters. Although not everyone may agree with SEIA’s position on this trade case, we are all on the same page when it comes to building a thriving and sustainable solar industry.


Barry Cinnamon is the CEO of Spice Solar. He’s also the host of The Energy Show podcast.


Be the first to comment - What do you think?  Posted by Editor - at 6:30 am

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It’s Been a Decade Since Google Jumped Into Energy. Is It Any Closer to a Moonshot?

It’s been 10 years since Google shifted some of its attention from bits and bytes toward the world of therms and electrons.

It started with a wide-ranging investment and R&D initiative, called RE<C, designed to make renewables cheaper than coal. That initiative was abandoned in 2011 after engineers realized they were tackling the wrong problems.

Today, new renewables are far more competitive than coal. But the economic shift didn’t play out in the way Google imagined.

In the decade since, Google has since dabbled in pretty much everything — power electronics, home energy analytics, smart thermostats, residential geothermal, flying wind, solar lead generation, autonomous cars, and direct corporate procurement.  

What can we conclude about the company’s track record? And at a time of uncertainty in both venture capital and government support, is Google the best vessel for cleantech R&D?

In this week’s episode of The Interchange, we debate Google’s place in energy.

On one side, Stephen argues that Google hasn’t lived up to its long-hyped claims about transforming the energy sector.

On the other side, Shayle argues that Google deserves credit for taking such a diverse approach to low-carbon technology development.

We’ll also bring on some guests for more context about where energy fits into the X Moonshot Factory. We talk with Mark Bergen, a Bloomberg journalist covering Google, who recently wrote about struggles of Makani Wind under the X Moonshot Factory. And we interview Kathy Hannun, the CEO of geothermal startup Dandelion, about how X deploys resources to energy R&D.

Google’s history in energy is extensive. Here’s a condensed timeline.

  • In 2006, Google builds a 1.6-megawatt solar system at the Mountain View campus.
  • In 2007, Google launches the RE<C initiative. It invests in geothermal companies AltaRock and Potter Drilling, as well as CSP companies eSolar and BrightSource.
  • In 2009, Google becomes a major tax equity provider for renewables, ramping up massively in wind, and later, solar. It is now the biggest corporate purchaser, with a plan to get 100 percent of its energy from renewables through contacted electrons.
  • In 2010, Google secretly creates X. Engineers at the so-called “moonshot factory” get serious about autonomous vehicles.
  • In 2011, Google ditches RE<C, realizing CSP and enhanced geothermal are extremely challenging. They maintain an equity stake in BrightSource’s Ivanpah CSP project. Engineers later say that conventional renewables aren’t enough to combat climate change.
  • That same year, 2011, Google kills off its home energy suite, PowerMeter. That’s when most tech providers start re-evaluating their approach to the home energy management market.
  • In 2013, Google acquires the flying wind company Makani. 
  • In 2014, Google makes another smart-home play by acquiring Nest for $3.2 billion. Nest has since struggled to define itself under the company, and it’s not clear where the smart-device maker is headed.
  • Today at X (now under the Alphabet umbrella), engineers continue to pursue flying wind, thermal storage, power electronics and even hybrid hydro-solar. But these efforts have either been abandoned, are facing hiccups, or are still too nascent to judge.

After everything, Google’s impact has arguably been greatest in conventional wind and solar procurement — the very technologies that engineers at RE<C once criticized as not enough to address climate change.

This brings us to some of the bigger questions that we try to answer in the podcast.

What can we conclude thus far about Google’s track record?

Does Google’s “10x” approach to innovation mean we should judge the company by a different standard? Are there limitations to applying that philosophy to energy?

Where are Google’s greatest strengths, and how can it apply them to energy?

Shayle also proposes a plan: Should Google simply buy a utility?

We still haven’t witnessed any major energy breakthroughs at the company — at least compared to the expectations it set back in 2007. But that doesn’t mean Google failed. It may simply tell us how difficult it is to scale new energy technologies and business models.

Make sure to subscribe to The Interchange podcast via iTunesSoundCloud or Stitcher, or integrate our RSS feed into the podcast app of your choice.


Be the first to comment - What do you think?  Posted by Editor - at 6:20 am

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Energy Capital Partners buys power plant operator Calpine Corp.

ECP offered Calpine’s stockholders $15.25 per share in the deal


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Ohio utilities board signs off on FirstEnergy rate hike

The money is supposed to go toward improving the utility’s power grid


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Paringa Resources constructing new coal mine in Kentucky

Paringa Resources says it is planning to begin mining coal at the McLean County site next year


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Victory for Indigenous Peoples as Brazil’s Supreme Court Rejects Attempts to Limit Indigenous Land Rights

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Why the UK’s Booming Capacity Storage Market Could Soon Go Bust

The U.K.’s December capacity market T-4 auction took place at the center of a perfect storm for energy storage.

Factors including 15-year contracted revenue, the ability to stack value streams with enhanced frequency response contracts, and requirements for only 30 minutes of committed capacity combined to drive a remarkable success for storage — resulting in 500 megawatts of new-build energy storage clearing the auction.

In a new report, GTM Research modeled out the lifetime project economics of a hypothetical 10-megawatt, 30-minute storage system participating in the U.K. capacity market and found that the system could yield a 11.1 percent internal rate of return (IRR) between 2018 and 2034, relying primarily on contracted revenue streams and favorable energy arbitrage opportunities.

FIGURE: Forecasted Annual Energy Revenue, Cost and Arbitrage Opportunity (USD, not inflation-adjusted)

Source: GTM Research, Wood Mackenzie

The model uses proprietary data from GTM Research and Wood Mackenzie and accounts for capital costs, replacement costs, system degradation, energy costs and multiple revenue streams.

In the months that have passed since energy storage had its moment in the spotlight, however, the news has not been good. Most of the mechanisms that enabled energy storage to compete so effectively are either being examined for potential changes or have already been altered. Proposals to derate capacity payments for shorter-duration systems could dramatically alter project profitability.

The report models lifetime economics across 30-minute, 1-hour, 2-hour and 4-hour systems. A hypothetical long-duration 4-hour system fails to pencil out, with a projected IRR of -0.7 percent.

According to GTM Research, while storage costs primarily scale with megawatt-hours, U.K. capacity market revenue scales up only with megawatt capacity, meaning a 30-minute battery and a 4-hour battery would be recognized for having the same value under the current system. This essentially prevents long-duration battery systems from using capacity payments as a primary revenue stream, as the 4-hour requirement with no corresponding revenue recognition for higher energy potential prices them out of the market.

Given the likelihood of the auction mechanisms being altered, the U.K. capacity storage market is a boom market about to go bust.  

But even if market rules change, the 500 megawatts from December’s T-4 auction is an impressive capacity contracted over the next four years. If opportunities for energy storage in the U.K. change, these projects will become even more critical for the market — demonstrating multiple use cases, establishing economics for arbitrage opportunities, and further proving energy storage’s value. All eyes will now be on the next T-4 auction to see if developers can adapt to potential changes and continue to drive the storage market forward.


The report, Energy Storage in the U.K.’s Capacity Market, complete with model assumptions and analysis, is available as part of GTM Research’s Energy Storage Service


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