Arizona is setting out to prove clean energy leadership doesn’t exist solely in coastal states like California and New York.

Andrew Tobin, a member of the Arizona Corporation Commission, proposed a clean energy overhaul Tuesday that would put the state at the front of the pack. The Energy Modernization Plan aims to produce one of the cleanest energy mixes in the nation, while lowering prices for consumers and improving grid reliability.

That means not only tackling the issue of clean baseload power, but also figuring out how to supply peak power in a cost-effective and clean way. Peak hours drive increasing expenses for utilities and their customers, a challenge that intermittent wind and solar alone cannot address. As such, Tobin’s plan includes an 80 percent clean energy target by 2050 coupled with a 3,000-megawatt energy storage procurement target for 2030.

That would leapfrog the state ahead of California and New York, which have dominated the grid modernization discussion so far. They both have 50 percent renewable energy targets on the books for 2030, and storage targets of 1,300 megawatts and 1,500 megawatts, respectively.

“We’re not trying to get on the train; we’re trying to be the engine in the train,” Tobin told GTM. “This is Western people doing things and setting lofty goals and reaching them.”

He has asked to get the concept on the agenda for the ACC’s meeting on February 6. If the five-member commission adopts the plan, as Tobin hopes it will, staff would begin a rulemaking to finalize the official language. That process could take up to a year and would involve stakeholder input.

Time for an update

The state currently is working toward a 15 percent renewable portfolio standard for 2025. The ACC set that policy in 2006, and included a 30 percent carve-out for distributed generation starting in 2012.

Since that time, solar generation has expanded, but so have the other tools available for sophisticated grid planning. That means it’s time for an update, starting with the name. Tobin suggests switching from the “Renewable Energy Standard and Tariff” to the “Clean Resource Energy Standard and Tariff.”

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Chicago grid equipment company S&C Electric built its first large-scale battery storage system in 2006, before almost anyone else was doing it. Now, it’s winding down that line of business.

Storage will still feature in its microgrid offerings, but the employee-owned company will procure it rather than producing it in-house, said Senior Director for Business Development David Chiesa. Meanwhile, S&C is refocusing on what it sees as its core competency: medium-voltage switching and protection, with a special focus on microgrids.

The move reflects the maturation and consolidation of the market in the 12 years since S&C built its first utility-scale battery, a sodium-sulfur unit for AEP. Demand for batteries has boomed, and a crop of electric-vehicle producers has established gigafactories to mass-produce battery cells and packs.

“We have other people in the marketplace who are taking single-use-type energy storage systems and just throwing them at the market for some incredible prices,” Chiesa told GTM at DistribuTech in San Antonio. “That high-volume manufacturing game has never really been what S&C is great at. We’re a standard manufacturer that features lots of customization to our standard products.”

That competition forces battery makers to either match the scale, which isn’t feasible in this case, or carve out a niche.

“For years we survived in that specialty space, because we knew how to integrate the really hard jobs,” Chiesa said. 

In the current, not-yet-fully-formed energy storage market, market design and regulatory structures prevent storage from making money on the full range of technical services it can provide. Vendors are innovating in anticipation of the expected hockey-stick growth curve, but finding a present-day buyer is a different story.

“One of our systems came with 12 use cases pre-engineered into the system,” he said. “Do you know how much value we got for that in the marketplace? None. You can only use three or four at a time.”

The baked-in versatility meant a customer could easily change use cases years down the road without an expensive retrofit, but again, that’s not a monetizable value at this point.

It’s hard to make money by building out product values that aren’t yet monetizable. The dilemma facing many early entrants into the storage industry is how much to invest in storage expertise before there’s a large enough market to support a thriving ecosystem of vendors and installers.

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Behind-the-meter battery startup Stem has raised $80 million in a Series D round, with three new investors — including one that’s helping bring the company’s lithium-ion battery systems to a new international market. 

The oversubscribed round was led by growth equity firm Activate Capital. It was joined by Singapore-based investment firm Temasek and the Ontario Teachers’ Pension Plan, which manages about CAD $180 billion Canadian (USD $145 billion) in Canada’s largest single-profession pension fund. 

The Ontario Teachers’ Pension Plan is interested in projects serving the province’s unique renewable energy integration needs, Stem CEO John Carrington noted in an interview. While he wouldn’t provide specific details, he did say that Stem is deploying systems in Canada, making it the company’s third international market, after the United States and, more recently, Japan. 

“We are growing very, very fast, and I would say, exceeding [expectations] in a variety of areas,” Carrington said of the company’s recent metrics. In the past six months or so, Stem has grown its portfolio of energy storage systems from 150 megawatt-hours in August to more than 200 megawatt-hours as of this week, with 1,500 sites “operational or in construction.” 

The company now has hundreds of systems under management across five states, mainly in California, where state incentives and high demand charges have aligned to create the country’s largest market for behind-the-meter energy storage. Stem also has its 85-megawatt capacity contract with utility Southern California Edison, part of the utility’s groundbreaking distributed energy resource (DER) procurement in 2014, to provide it a steady pipeline of business. 

Stem is also active in Hawaii and New York. It has a 1-megawatt pilot project with utility Hawaiian Electric on the island of Oahu. And it’s working with utility Con Edison to deploy 14 megawatt-hours of batteries across 80 locations in New York. More recently, Stem expanded into Massachusetts, with a $1.25 million grant to pilot distributed energy storage under the state’s newly created energy storage target, alongside Constellation Energy. 

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In December 2016, Panasonic and Tesla finalized an agreement to begin manufacturing solar PV cells and modules at the “Gigafactory 2” in Buffalo, New York.

Under the arrangement, Panasonic agreed to cover the capital costs associated with the factory and Tesla agreed to purchase Panasonic’s custom-manufactured solar products.

“These high-efficiency PV cells and modules will be used to produce solar panels in the non-solar roof products,” according to Tesla’s statement. “When production of the solar roof begins, Tesla will also incorporate Panasonic’s cells into the many kinds of solar glass tile roofs that Tesla will be manufacturing.”

Production of Tesla’s Solar Roof product did not begin for months after the initial announcement. But one year later — following delays and a brief trial run — Panasonic reports that cell manufacturing for the solar roof is now officially underway.

“Panasonic is already inside that factory making solar panels. That started in October of last year,” said Peter Fannon, vice president of technology policy at Panasonic Corporation of North America, in an interview at CES. “Also, we are just now beginning to manufacture cells.”

The Japanese multinational made an initial $260 million investment in the Buffalo facility, where it makes HIT (heterojunction with intrinsic thin layer) solar cells for Tesla. With the plant now up and running, Panasonic is prepared to invest more.

“We expect that investment, along with Tesla, as it grows, will grow with it,” Fannon said.

But it’s unclear how much growing is going on. 

Tesla completed the first solar roof installations on the homes of executives and employees in August. Little was heard about the solar roof after that, save for reports of several more installations for employees. The tiles were initially produced at small scale at the former SolarCity pilot production line in Fremont, California.

Last summer, Tesla CTO JB Straubel said solar roof production at Gigafactory 2 would ramp up “in a substantial way” by the end of 2017, and increased the company’s goal to achieve 2 gigawatts of solar panel capacity per year. But as the new year arrived, the status of Tesla’s solar tile production was still murky.

Tesla confirmed today, however, that solar roof manufacturing began in Buffalo in December. The company also said that it is now starting Solar Roof Textured and Smooth installations for non-employee homeowners.

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The California Public Utilities Commission ruled Thursday to authorize PG&E to procure energy storage or preferred resources (such as demand response or distributed solar) to ensure local reliability in areas previously served by the gas plants. The new resources can be individual or aggregated, and must be available by 2019 “if feasible and at a reasonable cost to ratepayers.”

This appears to be the first time a utility will procure energy storage to replace existing gas plants for local capacity needs. In Oxnard, a procurement process has begun to select storage instead of the proposed Puente gas plant. California deployed more than 100 megawatts of storage to shore up capacity after the loss of a major gas storage facility in the southern part of the state.

In this latest decision, though, regulators have chosen storage as a potentially cheaper alternative to maintaining two gas peakers and a 580-megawatt combined cycle plant. This process could become a playbook for phasing out more gas plants that become uneconomical in the future.

“The commission is showing confidence in the idea of preferred resources and energy storage as an alternative to the gas assets that currently provide reliability,” said Katie Ramsey, staff attorney at the Sierra Club, which filed a motion in support of the proposal. “This is a signal that clean resources don’t just compete with new gas plants — they can also perform the same services as existing gas plants.”

The case will test the economics of storage compared to existing gas infrastructure, and whether batteries in practice can provide the full range of services that a large gas plant performs.

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Last month at Greentech Media’s Energy Storage Summit, I had the pleasure of moderating a panel, Crowdsourced Market Insights: Role of Energy Storage in Creating the Grid of the Future. This panel employed a unique structure where our experts on stage were asked to interpret and weigh in as 500 attendees answered live polling questions on the top themes in the market. 

The results, with additional context from our research, are presented in a new research report, available for free here. Below, I summarize some key findings.

Storage will displace natural gas peakers (eventually!)

Only 1 percent of attendees feel that natural-gas plants will always out-compete storage, a perspective that may have been shaped by Shayle Kann’s earlier presentation indicating that 4-hour storage begins to compete with peaker plants within four years, and always wins financially within 10 years. The majority of attendees foresee energy storage dominance outside of a five-year time frame.

Broad optimism among the industry on utility engagement

More than four out of five attendees believe 41 percent or more of utilities will be including energy storage in their IRPs within five years — and their optimism seems justified. GTM Research’s tracking shows the trend is not just emerging — energy storage is becoming the norm in utility planning. 

In fact, Oregon is a sign of the times for utilities — Portland General Electric recently announced RFPs for up to 39 megawatts, the upper limit of the state’s energy storage mandate. When was the last time we saw a utility outpace legislators?

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On December 12, 2017, Senior Energy Storage Analyst Dan Finn-Foley moderated a panel at Greentech Media’s Energy Storage Summit, Crowdsourced Market Insights: Role of Energy Storage in Creating the Grid of the Future. This panel employed a unique structure where our experts on stage were asked to interpret and weigh in as 500 senior-level energy professional attendees answered live polling questions on the top themes in the market.

The results were insightful and, in some cases, surprising, with optimism mixed with skepticism in equal doses as the industry took stock of a market that was roiled with activity in 2017.

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You purchased that spiffy new rooftop solar array and waited patiently in the queue to get interconnected to the grid. Now that you’re generating kilowatt-hours, you’ve decided to invest in a residential energy storage system to maximize your ability to avoid paying for peak-priced power. There’s one hiccup, though: What do your state’s interconnection rules mean for connecting your new battery to the grid? 

We’ve now arrived at a cutting-edge topic in interconnection, one that several states have recently addressed or are working on addressing, and which many more will need to address soon.

As the Interstate Renewable Energy Council discussed in our recent report, Charging Ahead: An Energy Storage Guide for State Policymakers, energy storage promises to play a critical role at all levels of the electric system, from traditional utility-scale generation down to residential customer applications. It is also vitally important in accelerating integration of all types of distributed energy resources, or DERs. Energy storage offers a broad suite of electricity services, including deferral of expensive transmission and distribution line upgrades, the regulation of voltage and frequency, and expanding consumers’ ability to control their energy use and costs.

But while energy storage is affected by many of the same interconnection issues we’ve discussed in previous posts, it also raises new issues because of the technology’s unique characteristics — specifically, its ability to act as both energy “generation” (by injecting stored electricity onto the grid) and load (during its charging state), as well as its ability to be controlled so that it operates only when intended.

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It’s been an interesting year for mergers and acquisitions in the distributed energy space, with some unexpected developments.

We haven’t seen the same massive M&A deals of years past, such as GE’s purchase of Alstom or Honeywell’s acquisition of Elster — although Tuesday’s announcement that smart metering and utility software provider Aclara was being sold for $1.1 billion to Hubbell Inc. helped bring this year’s total closer to the peaks of the past. 

But when you look at the activity in 2017, a pattern emerges.

Over the past year, we’ve seen a number of major European energy companies — and some Japanese, American and Israeli ones as well — buy into the proposition that providing distributed energy technologies and services to their customers will be a significant part of their futures. 

This pattern stands out most clearly in the big European energy giants’ shopping spree this year, starting with Enel’s purchase of Demand Energy in January and closing with Centrica’s purchase of REstore in November.

In between, we’ve seen Total, E.ON, Engie and Shell also make significant acquisitions ranging from demand response and electric-vehicle management to energy storage and the connected home. 

Only a handful of these acquisitions have publicized their purchase price, including Enel’s $300 million purchase of demand response provider EnerNOC, Centrica’s $81.4 million purchase of REstore, and Ormat’s $35 million for Viridity Energy. This makes it difficult to calculate total values for the year’s M&A activity compared to multi-billion dollar deal of the past. 

But the pace of M&A activity, plus the observations of industry insiders, indicates that European utilities are in a bit of a land grab for acquisitions that can help them break into competitive distributed energy opportunities outside their core businesses — or as part of spun-out arms directly focused on the market.

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