Hawaii’s electric utility companies, Kauai Island Utility Cooperative and Hawaiian Electric Cos., are among the leading utilities in the United States for energy storage, according to a new report.

Both companies are featured on this year’s top 10 list for energy storage, which is compiled annually by Smart Electric Power Alliance.

The 2018 survey ranks utilities based on their addition of solar and energy storage in 2017, both in total megawatts and watts per customers, according to the nonprofit’s website.

KIUC led the nation by adding 415.3 watts per customer of energy storage during the last year. That is over eight times more than second-placed Tucson Electric Power with 50 watts per customer.

Maui Electric and Hawaii Electric Light Co., both subsidiaries of Hawaiian Electric Cos., also made the top 10. Maui Electric came in third with 36.5 watts per customer and HELCO was ranked seventh with 16.4 watts per customer.

In terms of total megawatts, KIUC took home the fifth place with 13.7 megawatts, while Maui Electric and Hawaiian Electric Co. rounded out the top 10 with 2.6MW and 2.2MW, respectively. The utility adding the most energy storage last year was Southern California Edison with 56.2MW, according to the report.

“This year’s Top 10 lists reflect a pivotal moment in the U.S. energy transition, as utilities increasingly focus on solar and storage as distributed resources providing value to customers and the grid,” SEPA CEO and President Julia Hamm said in a statement. “Beyond their impressive numbers, Hawaiian Electric, Maui Electric and Hawaii Electric Light embody a strong model for innovation and leadership that utilities across the country will continue to build on as we move toward a clean, smart and resilient energy future.”

Governor Andrew Cuomo announced new energy efficiency standards for New York on Friday, calling for investor-owned utilities to achieve annual efficiency savings equal to 3 percent of sales by 2025.

The new target would accelerate energy efficiency by more than 40 percent over current forecasts and reduce energy consumption by 185 trillion Btu. The state also committed $36.5 million to train more than 19,500 New Yorkers for clean energy jobs.

“Energy efficiency is the most cost-effective way for New Yorkers to lower utility bills, curb harmful emissions and battle climate change,” said Governor Cuomo, in a statement.

The energy efficiency plan should help the state achieve nearly one-third of its climate goal to reduce emissions by 40 percent by 2030.

New York’s Public Service Commission also approved a series of measures last week as part of the state’s Reforming the Energy Vision (REV) initiative. Now in its fourth year, REV is a sweeping overhaul of utility and energy regulations meant to enable more distributed energy on the grid.

One of the changes will allow distributed energy storage projects of up to 5 megawatts to connect to the grid, which the commission says will expand the integration of larger energy storage technologies.

“New York is sending strong signals to the storage industry to come to invest in New York, and those signals are coming in [the form of many] different changes, and this is one of them,” said Anne Reynolds, executive director of the Alliance for Clean Energy New York.

Regulators also improved upon the application and contract process for Standardized Interconnection Requirements, which should help developers connect distributed generation projects to the distribution system more efficiently.

After a barrage of wicked nor’easters this winter, Massachusetts residents probably aren’t worried about having too much sun — but they should be.

Over in Hawaii, California and Arizona, middaysolargeneration has begun to cause major swings in the balance of supply and demand on the grid. The resulting “duck curve” has become emblematic of the logistical challenges involved in massive renewables adoption.

As it turns out, this duck infestation is migrating from the sunny, palm-lined enclaves of Venice Beach and Scottsdale to the Bay State.

“We are absolutely beginning to see a duck curve,” said Judith Judson, commissioner of the Massachusetts Department of Energy Resources, in an interview at the Energy Storage Association conference in Boston last week. “It shows that we’re being very successful in increasing renewable energy generation, but we need to start thinking about…how [we can] match up that generation with demand.”

The telltale shape of the duck is appearing in the daily energy charts from ISO New England, the grid operator for Massachusetts and five neighboring states. The ISO has about 2,400 megawatts of cumulative solar capacity, most of which is small-scale.

Massachusetts represents almost half of the load in the territory, and the bulk of the solar capacity too. The data covers more than just Massachusetts, but the state drives regional trends.

As much as 40% of grid-connected battery storage projects that have been announced worldwide propose co-location with solar PV, from a pipeline of more than 10GW, analysts at IHS Markit have said.

The research firm has just published its analysis of the global battery storage market in 2017, extending into the first quarter of this year. It found that the “global utility-side-of-the-meter pipeline” increased by 2.9GW in Q1 2018 alone, from 7.5GW at the end of 2017 to 10.4GW today. It’s important to note that the pipeline is collated from announced, not completed, projects.

The company is forecasting the deployment of some 3GW this year around the world, a jump up from 1.9GW of global deployments that IHS tracked in 2017. Among the findings was that 40% of the utility-side-of-the-meter (known also as front-of-meter) pipeline consists of solar-plus-storage projects, co-locating batteries with solar.

“We’re not predicting that in the future that’s what 40% of all projects will be, but 40% of the announced pipeline that we’re tracking, is [solar-plus-storage],” Sam Wilkinson, associate director for solar and energy storage research at IHS Markit, told Energy-Storage.News.

“It’s mostly driven by a number of very large project announcements in Australia and the USA. In Australia in particular, there have been a huge number of solar projects that have announced they will add storage at a later date. Some of them are very clearly going to be installed this year, some of them have a much lower, what we would call ‘confidence rate’, that they’ll actually add storage at all. It might be that they’re waiting for a policy change or new business models to evolve,” Wilkinson said.

Co-location can also mean various things. At its most basic level, solar farm owners might take advantage of an existing grid connection to look at installing a battery on the same network, but the batteries and solar might behave entirely independently of one another. Conversely, it can mean the battery system is charging from the solar panels directly and could provide services to the solar farm, such as storing the energy for later use or helping the PV plant to ramp up to meet grid demand. The former would use longer durations, more megawatt-hours of energy, the latter would use shorter durations and respond quickly. Wilkinson pointed out that there does appear to be a trend forming towards that longer duration use for ‘solar firming’ with batteries.

It took a long time for commercial solar installations to take off. In fact, despite an increasing tendency for big corporations, big box retailers and vast data centres to make high profile, headline-grabbing long-term commitments on rooftop PV, you could see why many businesses, often going from short-term lease to lease on their properties, weren’t as keen to take the plunge.

By contrast, on paper at least, even at this relatively early stage of its market development, energy storage could have instant appeal for a broad range of companies – and is already doing so. Over five years, commercial and industrial (C&I) energy storage in the US is forecast by IHS Markit to grow from 60MW of annual installations in 2017 to 400MW in 2022.

That would mean the market reaching a total installed base of more than 1,500MW by then. With the cost of this once-expensive and no-longer-so-exotic (at least as far as the finance community is concerned) set of technologies falling, C&I energy storage can enable benefits to the customer, and even when installed behind the meter in this way can offer benefits to utilities and the grid in front of the meter.

Behind-the-meter (BTM) energy storage systems at C&I sites are well positioned to provide benefits to the end customer (e.g., demand charge management and back-up power) and utilities (e.g., meet capacity requirements and provide demand response). As such, they form a crucial part of a more decentralised energy system. From the commercial customer’s point of view, signing a relatively flexible contract for a service-based proposition – where the provider takes care of even the economic modelling of the system throughout the life of the contract simplifies the whole process. And unlike rooftop solar, the customer does not have to effectively take custody of a huge structural addition to their building, batteries are perhaps more like industry equipment that can be deployed – or removed again – fairly easily.

Not to mention that while economics vary hugely from project to project, in some specific cases, a C&I energy storage system in the US could achieve payback in not much longer than a year.

EnergySage says that in 2017, 74% of customers shopping for solar on their online solar marketplace were considering energy storage. The company’s Solar Marketplace Intel Report also offers evidence that customers will pay the extra costs for storage – as residential solar panel purchases have moved upmarket toward SunPower, LG, Panasonic and other premium brands. When extrapolated – these interests represent a 1-2TWh, or larger, market opportunity.

The report published a new metric, Badges – “an additional layer of information that educate shoppers about the various attributes of one quote versus another.” High quality equipment stood out by far, and only one of the top seven items – lowest $/W – suggested shoppers were focused on bargains.

The report also showed that system prices continued fall on a price per watt basis. However, total system size increased – which actually meant a net increase in total system cost (8kW at $3.36/W at the end 2016, versus 8.7kW at $3.13 at end of 2017).

Installers in Florida, Arizona and Maryland brought average costs below $3.00/W on the EnergySage marketplace, and there were some counties where average costs fell as low as $2.00/W.

That overall prices are falling while equipment from premium players like LG and Panasonic are making inroads in the solar panel market is likely a testament to the ability of those two companies to deliver higher efficiencies at respectable prices.

Another chart shows that SolarEdge has become the dominant brand in residential installations. That the size and complexity – think multiple surfaces, at multiple angles facing multiple directions – of installations has increased may be directly due to module-level electronics from SolarEdge and Enphase.

Net metering compensate solar customers for the power they contribute to the grid — but if they route the electrons through a battery, they’re out of luck.

Utilities understandably don’t want to pay net-metering rates for batteries charged by grid power. So far, that means solar generation stored in batteries for later use doesn’t earn net metering dollars either. That could change, once the California Public Utilities Commission responds to a petition that, unusually, drew support from both the solar industry and utilities.

“If I’m not charging from your electricity, if I’m charging only from a solar source, the battery is basically an accessory to the solar system,” said Joshua Weiner, who worked on the concept as president of design engineering firm SepiSolar, which specializes in solar plus storage. “All the policies in place support this. […] Somebody just needs to say that this is allowed.”

If certifiably solar-powered batteries can get paid, that could unleash a market signal with sweeping ramifications for solar customers and utilities trying to balance a highly renewable grid.

California’s shift to new time-of-use rates lowers the value of solar at midday, when it floods the wires, and increases the price of evening power. That means reduced payback for traditional solar customers who can only export when the sun shines and then have to buy power at night.

Those who pair solar panels with batteries, though, could store midday generation and sell it to the grid at the peak time-of-use rates, if allowed. That personal profit addresses a systemic challenge: the dreaded “duck curve.”

Solar customers would make more money by exporting just when utilities are scrambling to fulfill the steep ramps required in the evening, when solar generation drops off and electrical demand spikes.

“We’ve become very good at supplying solar power in the daytime; now we need to start supplying solar power in the evening,” said Brad Heavner, policy director at the California Solar & Storage Association.

Play that out on a statewide scale, and it’s not hard to envision the collective behavior of thousands of solar customers delivering peak power that otherwise would come from gas plants. It simultaneously reduces the technical headaches associated with a surplus of midday solar on the wires.

The U.S.solar industry breathed a sigh of relief yesterday when Chinese-made solar cells and modules were not included on a list of products that could be subject to new Trump administration tariffs. Inverters were also absent.

Other clean energy technologies did make the list, but the U.S. market impacts appear to be modest.

The U.S. Trade Representative published the catalog Tuesday, naming some 1,300 Chinese imports the administration plans to hit with a 25 percent tariff under Section 301 of the Trade Act of 1974.

Industrial robots, communication satellites and aircraft parts were among the products covered by the proposed tariffs, which are framed as retaliation for Chinese theft of U.S. intellectual property and other unfair trade practices.

Certain Chinese wind power and battery products could also be subject to trade sanctions, as well as a motor cited as “primary source of mechanical power for electric vehicles.” However, USTR trade data shows these products make up a relatively small share of the U.S. market.

In the first case, the administration is specifically targeting “wind-powered electric generating sets.” According to the U.S. Department of Commerce’s Trade Policy Information System database, Chinese-made wind products included on the tariff list made up 25 percent of U.S. imports in 2017, representing just $53.3 million.

The USTR document does not specify if the tariffs apply specifically to wind turbines or wind generators. However, the $53 million figure generally aligns with the value of wind turbines imported to the U.S. from China in 2017, said Aaron Barr, principal consultant at MAKE Consulting. That amounts to between 30 and 75 turbines, depending on scope and size.