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Trump Confirms He Wants a Solar Border Wall: ‘We’re Working It Out’

June 22, 2017

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President Trump touted the idea of building a solar border wall between the U.S. and Mexico for the first time in public on Wednesday night, speaking at a campaign-style rally in Iowa.

"I'm thinking of something that's unique, we're talking about the southern border -- lots of sun, lots of heat. We're thinking about building the wall as a solar wall, so it creates energy and pays for itself," he said, and the crowd cheered.

"You're the first group I've told that to: a solar wall," he continued. "Makes sense, let's see. We're working it out, let's see. A solar wall. Panels, beautiful."

"Pretty good imagination, right? My idea. So we have a good shot. That's one of the places that solar really does work, with the tremendous sun and heat -- it really does work there," said Trump. "So we'll see what happens with that. That would be great. And I think we could really make it look beautiful that would be nice."

Trump's comments confirm reports from earlier this month that he was considering a solar border wall. He addressed the proposal directly in a speech yesterday congratulating the Republican winners of Tuesday's special elections in South Carolina and Georgia.

While some in the cleantech industry have entertained the idea of building a solar border wall, both seriously and in jest, the concept of installing solar panels over the entirety of a 50-foot-high barrier that's roughly 1,000 miles long would likely have such a high price tag -- among other issues -- that it's difficult to see how the project could become a reality. 

The biggest setback for the solar border wall is that the president has yet to secure funding for any type of border wall. And there's no indication that it will win support from Congress.

It's not entirely clear how serious Trump is about installing solar panels, in the event a wall does get funding. But it's notable that the president addressed it, nonetheless. 

Trump's acknowledgement of solar's cost-effectiveness comes after he criticized the renewable resource on the campaign trail.

"I know a lot about solar -- I love solar," Trump said at an event in California last summer, NPR reports. "Except there's a problem with it. It's got a lot of problems with it. One problem is it's so expensive."

Trump also referenced the now-bankrupt solar firm Solyndra while criticizing U.S. energy policies during a presidential debate last year. And since taking office, Trump has sought to slash government funding for renewable energy programs, and put renewable energy critics in key leadership positions. He's also bashed wind farms for being ugly and unreliable. 

In this context, the president's solar wall comments represent an unexpected endorsement of renewable energy. However, Trump appears to have little interest in deploying low-carbon energy resources at scale. In last night's speech, he reiterated his position that staying in the Paris climate accord would have cost millions of jobs, "billions and billions of lost dollars" and put the U.S. at a "permanent economic disadvantage."

"I could tell you stories; I could give you stats; I could go on all day. It's a catastrophe if we would have agreed," he said. "And they all say it's non-binding. Like hell it's non-binding. When we get sued by everybody because we thought it was non-binding, then you can tell me it was non-binding."

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Austin Energy Seeks to Boost Value With a United Fleet of Solar and Storage

June 21, 2017

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The municipal utility in Austin, Texas is trying to figure out how much money can be saved when solar and storage talk to each other.

Austin Energy will install its first large-scale batteries this year to join a growing fleet of solar generation, both central and distributed. With funding from the Department of Energy, the utility is syncing up the efforts around an integrated control system, to quantify the value added by coordinating the dispersed assets.

That will be more than an academic exercise, because Austin Energy is working toward 10 megawatts of distributed storage and 55 percent renewable energy by 2025. The grid implications of that surge will manifest more acutely in a smaller, municipal-sized service territory.

Kurt Stogdill, green building and sustainability manager for Austin Energy, pointed out that “200 megawatts [of] PV spread over 437 square miles is different from 200 megawatts spread over the whole of ERCOT."

The program started with a challenge to reach a 14 cents per kilowatt-hour levelized cost of energy for solar and energy storage. The utility won $4.3 million from the DOE's Sustainable and Holistic Integration of Energy Storage and Solar PV (SHINES) program, in addition to $1 million from the Texas Commission on Environmental Quality, to support the solar-plus-storage exploration.

To get the costs down that low, the team started looking at how to add value with intelligent controls, rather than leaving the distributed resources to operate independently.

Here’s what's planned so far for the fleet of DERs:

  • More than 1 megawatt of distributed solar in the Pecan Street clean energy housing development
  • 2.5 megawatts of community solar to be built in east Austin by late fall
  • A 1.75-megawatt/3.2-megawatt-hour Younicos battery at the Pecan Street distribution feeder
  • A 1.5-megawatt/3-megawatt-hour LG Chem battery at the substation next to the community solar
  • Seven Stem battery systems sited on commercial properties
  • Six residential batteries to come at Pecan Street
  • Solar forecasting software from Clean Power Research
  • DER optimizer from Doosan Gridtech to assess supply and demand across the network and control the whole system. Austin Energy is testing multiple communications pathways (internet, cellular and AMI) to see how they perform for different applications.

This is technically a pilot project, but it's also a learning exercise carried out at scale across the city, serving real operational needs.

The Younicos battery will help smooth distribution in the solar-heavy Pecan Street neighborhood, to guide future deployments of large batteries elsewhere in the city. The LG Chem system will play a similar role integrating the large community solar array.

The Stem battery systems will be aggregated to test the value of distributed storage in Austin’s market conditions. Some of them will be optimized for the customer’s economic return, and others will be under direct utility control, to determine how the systems perform based on those settings. If the utility-controlled systems don't provide enough payback to the host customer, the utility will figure out a way to compensate them appropriately.

“From my perspective, the single biggest obstacle there is to the proliferation of storage -- price is one -- but the other is being to able to understand the value of the potential resource,” Stogdill said. “Right now, even the folks who are selling the storage systems sometimes can’t tell a utility or customer what it’s going to be worth to them.”

Modeling a single value stream, like demand shaving, is simple enough, he said. But layering on energy arbitrage and multiple other potential applications makes it complicated to predict. The data from this deployment will help the utility better predict the potential value of future storage deployments.

“We understand that other geographies are going to have different needs, and whatever we develop for Austin may not be perfect for somewhere else, but we want to make a framework that could apply somewhere else,” Stogdill added.

That replicability is top of mind for commercial storage powerhouse Stem as well. Slated to come on-line in 2018, this marks the company’s eighth utility contract, joining projects in California, Hawaii and New York, CEO John Carrington said. It’s the company’s first foray into Texas.

“SHINES has helped us in other areas before that have grown into bigger markets,” Carrington said. “When we get in a new location and prove the model, it just starts to grow. We expect the same in Texas.”

If it works in Austin, this model will be a strong candidate for adoption by the many other municipal utilities in Texas.

That’s significant, because Texas has so far played a minor role in the energy storage market, despite its massive energy-use profile.

The Lone Star State has just 140 kilowatts of residential storage, no installed commercial storage and less than 50 megawatts at utility-scale, according to GTM Research’s latest count. Austin's deployments alone will register on the statewide scale.

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A Sneak Peek of The Energy Gang’s Live Podcast in San Jose

June 21, 2017

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Are oil companies about to become the biggest players in renewable electricity?

What are some of the most novel approaches to using distributed energy assets for grid reliability?

Are Amazon, Apple and Google finally preparing to dominate in home energy services?

Those are some of the big questions we'll be asking -- and hopefully answering -- at our live taping of The Energy Gang podcast next week in San Jose, California.

The Gang will be taking the stage at GTM's Grid Edge World Forum to debate the future of grid technologies and market design. (And it's just one part of an incredible multi-day conference and expo bringing together top utilities, energy experts and companies from around the world.)

All Energy Gang listeners get 15 percent off their registration. Just use the code ENERGYGANG at checkout, and you'll save hundreds of dollars on your conference pass.

If you're a GTM Squared member, you'll get free access to our conference livestream so you can watch in real time from your couch or desk chair.

Each week, the Gang puts together a compilation of top news stories to discuss and debate. Here's a sneak preview of the stories we'll be covering, including links to some handy resources.

Topic 1: Oil majors get serious about renewable electricity

After mostly abandoning renewables investments, the world's biggest oil companies are getting interested in them once again. Faced with carbon constraints, low prices for oil, and a coming shift to electrification, oil supermajors may end up becoming significant players in solar, wind, electric cars and battery storage.


  • GTM: Global Oil Majors Are Poised for a Resurgence in Solar and Wind
  • GTM: Oil and Gas Heavyweights Back a Roadmap for Deep Decarbonization
  • Guardian: Oil Giants Need to Invest Heavily in Renewables by 2035, Says Analysis
  • Wall Street Journal: Oil Giant Sees Its Future in Electricity
  • Wood Mackenzie: Could Renewables Be the Majors' Next Big Thing?

Topic 2: Novel approaches to using distributed energy for grid management

As traditional baseload power comes under pressure, debate rages over the reliability of a distributed grid. Meanwhile, top developers and engineering companies working on renewables, electric cars, smart appliances and battery storage are coming up with novel ways to make these distributed assets valuable actors in the electricity system. We'll look at the latest real-world experiences in this domain.


  • GTM: How First Solar and NREL Are Balancing the Grid With Utility-Scale Solar
  • GTM: GE Can Now Put Battery Storage on Any of Its Power Plants
  • GTM: Inside GE and SoCal Edison’s First-of-a-Kind Hybrid Peaker Plant With Batteries and Gas Turbines
  • GTM: BMW and PG&E Prove Electric Vehicles Can Be a Valuable Grid Resource
  • GTM: A Deep Look at Sacramento’s Groundbreaking Use of Distributed Energy and Customer Data
  • Bloomberg: Trump Power Study Riles Trade Groups Before It's Released
  • Advanced Energy Economy Report: Reliability and the Evolving U.S. Power System

Wildcard: If Rick Perry's baseload study comes out, we will talk about that in more detail as part of this conversation.

Topic 3: The circuit

In this rapid-fire segment, we'll tackle of the most talked-about stories in energy. Are they worth your attention?

Topics include:

  • Is blockchain the great disrupter in energy or just a novel application?
  • How drastically will artificial intelligence change the utility workforce?
  • Will we see a billion-dollar software company serving the grid edge by the end of the decade?
  • Are Google, Apple and Amazon finally ready to become major players in energy management?
  • Are we going to price carbon under the Trump administration?
  • What is the single most important market design question in the utility sector today?
  • Grid decarbonization post-Paris: Does the pathway change?

If you haven't signed up for Grid Edge World Forum yet, do it. We're giving new registrants a 15 percent discount. And if you want to watch from home, become a GTM Square. (Added bonus: Squares get all our podcasts in transcription form, too.)

Listen to our recent live show from GTM's Solar Summit below.

The Energy Gang is sponsored by KACO New Energy, a leading solar inverter company with superior engineering and unmatched customer service.

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No, Cities Are Not Actually Leading on Climate. Enough With the Mindless Cheerleading

June 21, 2017

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The idea that cities are leading on climate change is applauded over and over and over. There’s just one problem.

It's not actually happening.

Retrofit programs for buildings and homes aren't delivering results. Power distribution remains rooted in century-old thinking and technology. And those cities that claim to be on track to go "100 percent renewable"? Not even close.

With the U.S. withdrawal from the Paris accord, city contributions are needed more than ever. But it’s time to stop with the empty platitudes and face reality.

We’ve got a lot of work to do.

Cities haven’t yet taken on key roles 

The truth is that cities have done little to contribute to recent declines in carbon pollution. Renewable portfolio standards have spurred tons of new renewable generation, but states adopt those, not cities. Transportation-related CO2 is down in many cities, but that's largely the result of improved national fuel-efficiency standards. And urban areas did nothing to create cheap natural gas, which, by displacing coal, has been the leading driver of reduced emissions.

A central issue is that cities seldom have jurisdictional authority over energy infrastructure. There are few municipally owned utilities -- and most regulators are chosen at the state level. Even with respect to the critical issue of building codes, mandates are frequently determined by counties, states, and the International Code Council.

It turns out that when cities claim reductions in greenhouse gases, they're usually taking credit for things they didn’t do.

Minimal progress with energy efficiency and solar

This doesn’t mean that cities can’t play a vital role. They can.

As San Francisco’s Renewable Energy Task Force stated in a 2012 report, "Reaching [100% renewables] will require coordinated action in three main areas: improving energy efficiency to reduce total electricity demand, increasing in-city renewable distributed generation (DG) to reduce the need for imported green power, and providing all customers a 100% renewable power purchasing option.”

Most city climate plans reflect these principles -- focusing on reducing demand (i.e., efficiency) and increasing renewable supply (i.e., distributed solar) within their borders.

With energy efficiency, however, it’s difficult to identify much progress. The American Council for an Energy-Efficient Economy (ACEEE) recently released its 2017 City Energy Efficiency Scorecard. Among the leaders in energy efficiency, you’d reasonably expect improvements with energy efficiency. You'd be wrong.

Electricity consumption, a primary source of carbon emissions, is flat or growing in each of ACEEE's top 20 cities with available information. In a host of frequently lauded cities, building electricity use is up over the last five years of data: Los Angles (+3 percent); New York City (+1 percent); San Francisco (+1 percent); Boston (+2 percent); Denver (+3 percent); Austin (+5 percent); and D.C. (+1 percent).

On a per-capita basis, residential electricity use is down in Austin (-9 percent) and San Francisco (-9 percent), but it’s up in Boston (+7 percent), Los Angeles (+9 percent), and D.C. (+17 percent).

This is bad news. The bottom line is that in urban areas, where new residents often live in highly efficient apartments and businesses operate in increasingly dense office buildings, electricity use must drop. That's not happening.

While potentially less impactful than efficiency, solar is another top priority. But according to the 2017 report, Shining Cities, only a few cities have more solar per capita than the national average. For example, while Los Angeles accounts for 10 percent of its state's population, just 2 percent of California’s solar is in L.A. 

Solar panels may dot farmlands and deserts, but the sun is not yet powering most urban areas. Just 0.3 percent of NYC’s power comes from solar, and the situation is similar in other cities, including San Francisco (1.2 percent); Boston (0.4 percent); Denver (1 percent); Austin (0.3 percent); D.C. (0.4 percent); Chicago (0.1 percent); and Baltimore (0.2 percent).

"100 percent renewable"

This lack of progress hasn’t stopped cities from making increasingly aggressive climate goals. Most notably, many cities now have "100 percent renewable" pledges. Unfortunately, at this juncture, it’s not entirely clear what these commitments really mean. 

[Note: The issue of carbon accounting can lead you down a rabbit hole from which you’ll never return. The main issue to understand, however, is that electricity generation creates two tradable commodities: “null electricity” (e.g., electrons) and environmental attributes (e.g., RECs). These commodities are routinely decoupled, wherein renewable generators sell electricity to one entity and RECs to another.]

I know about the bizarre implications of “100 percent renewable” and RECs firsthand. When I led the energy division for government facilities in Washington, D.C., we became entirely "green-powered" by purchasing one wind REC to account for each megawatt-hour of electricity we bought from the grid. “D.C. schools, firehouses, and offices are 100% powered by wind,” declared USA Today.  

This is where things get strange. Because the government was already "100 percent renewable” through RECs, our subsequent long-term power-purchase agreements (PPAs) -- to actually buy electricity from an offsite wind farm and new onsite solar panels -- had no impact on our greenhouse gas emissions. Technically, our emissions were not even reduced in buildings where efficiency measures cut consumption by 30 percent or more. 

To appreciate this insanity, it’s helpful to consider two scenarios.

Building A doubles its electricity consumption with an inefficient air conditioning system, but it buys RECs from an existing wind farm. Building B installs solar panels that provide all of its power, but it sells the RECs from those solar panels. According to the bizarre world of carbon accounting, Building A is preferable to Building B. That’s a problem -- because in actuality, it is not.

At scale, the muddled nature of this issue is showcased, ironically, in “100 percent renewable” Burlington, Vermont.

The city has created a website to provide clarity about its energy portfolio. It’s worth reading; pay particular attention to the journey from chart #1, to chart #2, to chart #3, and finally to chart #4. With respect to Burlington, clearly a well-intentioned jurisdiction, this path to "100 percent renewable” is a laughably confusing shell game.

Ultimately, put plainly, all of this means that cities can meet nebulous climate goals by purchasing credits. This is a worrisome path. Instead of obfuscating climate-related success, our focus should be on impactful action.  

Lack of transparency

Moving back to the real world, the electric meter for buildings should be a central barometer for climate progress. It’s not perfect.

Natural gas and transportation fuel are obvious contributors to greenhouse gases; weather and occupancy can create short-term fluctuations; and, as electric vehicles reach scale in the future, their energy consumption should be decoupled. But if we had to pick one metric, the building electric meter is a good one. 

Whether it's energy efficiency or onsite electricity generation, progress is tethered to metered building consumption. In order to make metered electricity use go down, you must reduce consumption and/or increase onsite generation -- full stop. 

Given the importance of electricity meters, then, how are cities doing so far this year? Well, we have no idea. 

Not a single city reports its electricity consumption more frequently than annually. Tons of cities do not appear to publicly report their electricity consumption at all, including Portland and Philadelphia. Others, like Chicago, have not reported data since 2010.

This is wildly unacceptable. When we want to track our steps, we put on a Fitbit and see activity in real time. Yet in the world of energy, where we spend billions of dollars on efficiency programs to reduce consumption, data is unavailable for years after the fact.

The Fitbit analogy is telling. Imagine a “step challenge” in your office to see who takes the most steps this summer. Except with this particular competition, you can’t see how you’re doing on a daily leaderboard. Also, the winner won’t be announced until next year. Would you even bother signing up?

Or imagine that your city has seen a rash of violent crime. There’s a new police chief, though, who says the city is on track to reduce robberies and murders by 75 percent. There’s just one twist: The police department has decided to stop releasing crime statistics to the public, at least until 2021.

That police chief would be fired. 

It does not have to be this way. In any jurisdiction with smart meters, it’s feasible to see electricity use in near-real time. Even with analog meters, monthly updates are possible. There is just no will or urgency to make it happen.

Rationalizations everywhere

This lack of will was plainly evident after I recently testified at a local hearing on D.C.’s energy budget. I noted that D.C.’s per-capita residential energy use is flat, at best, despite huge spending on conservation programs for homes. One local environmental leader said he thought I was being too tough on D.C. I needed to consider all of the new technology, he said: “Think about all the iPhones we’re charging these days. Flat is good.”

No, it’s not.

I also heard maddening rationalizations when we worked to improve efficiency with new school construction. Shortly after taking the job, it became apparent that our new schools were using more energy than the ones they replaced.

More stunning than the energy data, however, were the responses to my concerns. I was reminded that we needed electronic blackboards and computers, and that air conditioning systems made sure students weren’t suffering. Never mind that utility savings would go back into the classroom, or that student comfort and learning should be unaffected by well-designed efficiency. “This isn’t your issue,” I remember being told.

We can’t be in favor of conservation, except when we’re not. Almost all climate models show that buildings must become more efficient in order to avoid catastrophic temperature rise. In cities, the gains should be massive. We have no choice but to figure out how to make this happen, even with iPhones and air conditioning.

Offseason champs

When it comes to climate, it often seems as if cities have substituted press releases for action. This reminds me of D.C.'s football team. Every offseason, there’s lots of excitement. For as long as I can remember, I’ve heard, “This is the year!” But unfortunately, the games aren’t decided by how good you say you are, think you are, or plan to be. (Our football team has only won two playoff games in the last 25 years.)

Cities have fallen into this habit of being “offseason champs.” It’s an easy temptation. The risks of global warming are relatively long-term, and, relatedly, success is difficult to measure. In this environment, it’s easy to say you’re leading -- because there’s no scoreboard to say otherwise.

This is dangerous. On an issue of this importance, refusing to acknowledge failure is almost as bad as failure itself. Moreover, this head-in-the-sand approach limits our ability to recognize and improve what’s actually working. Iterations on success are central to the ability of all actors -- including cities -- to make progress on climate, but that’s not possible if we don’t know how we’re doing.

One small idea: Create a leaderboard

In this spirit of incremental change, I conclude with one small proposal.

There should be a website (paging Al Gore, Michael Bloomberg) that simply displays electricity consumption data for every city in America. On a regular basis, awards should be given to the top-performing cities. Some cities would do worse than others, but that’s the point. Public accountability could move the needle, at least a little, to spur cities to make real progress on a central metric of success. 

Enough with the mindless cheerleading. It’s time to put actual points on the board.


Sam Brooks was director of the energy division for the D.C. Department of General Services from 2012-2014. He now runs ClearRock, a  Washington, D.C.-based consulting firm that serves as an owner’s representative for clean energy purchasing.

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BMW and PG&E Prove Electric Vehicles Can Be a Valuable Grid Resource

June 20, 2017

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The concept of using electric vehicles as a grid resource is no longer just theory. A pilot program recently conducted by BMW and Pacific Gas & Electric successfully demonstrated that electric vehicles can serve as reliable and flexible grid assets, which could eventually save money for both utilities and EV owners.

The BMW i ChargeForward Project is one of the best examples to date of a utility and an automaker working together to develop new technologies and use cases for electric vehicles (EVs) and their batteries.

“One of the things that we really wanted to test here was, how can we work closely with an automaker?” said David Almeida, electric vehicle program manager at PG&E. “We are an old company, and we're a large company. Automakers are old companies, and they're large companies. We both have our own internal bureaucracies. And so, one of the challenges I wanted to understand when we were setting this up was, how do we make those two independent entities work well together?”

“By and large, we didn't have any of those institutional challenges that I was [worried about],” he said. “We ended up working very closely, I think partially because we've got this common shared goal of increasing electric transportation.”

With the i ChargeForward pilot, BMW was required to provide PG&E with 100 kilowatts of grid resources when called upon, through a combination of delaying charging for nearly 100 BMW i3 vehicles in the San Francisco Bay Area and drawing from a second-life stationary battery system built from reused EV batteries, for the duration of 1 hour. The grid services demonstrated in the pilot included day-ahead and real-time signals that were modeled after existing proxy demand resources from the California Independent System Operator (CAISO), in order to test whether these resources could eventually participate at the wholesale level.

Over the course of 18 months, from July 2015 to December 2016, the i ChargeForward project dispatched 209 demand response events, totaling 19,500 kilowatt-hours, according to a recently released program report.

The events were called using an OpenADR protocol, the agreed-upon pathway for demand response communications. Olivine, an approved scheduling coordinator with CAISO, acted as the interface between the utility and the automaker. Once triggered, BMW’s aggregation software determined how much of the 100-kilowatt load drop would be met by the stationary battery and how much would come from managed charging, and used the onboard vehicle telematics system for communicating grid messages to the cars.   

All of the DR events included a mix between the second-life battery and the vehicles, with around 80 percent participation from the battery and 20 percent from the vehicles. However, when the utility called events at different times of the day, specifically when there was a high vehicle load, vehicle participation jumped up significantly, to around 50 percent. 

The vehicle response rate was highly correlated with PG&E’s residential time-of-use rates, which offer lower electricity prices at night from 11 p.m. to 2 a.m. Almeida said that a high percentage of EV drivers plugged in their vehicles as soon as they got home, but delayed actual charging until later in the evening when rates declined. This showed that the vehicles have even more flexibility as a grid resource than initially thought, because they’re plugged in for longer periods of time and because customers are effectively responding to the rate structure.

“That gives us an indication that we have some ability to move vehicle charging throughout that window of [plug-in] time,” said Almeida, who will discuss EV infrastructure on a panel next week at Grid Edge World Forum.

“We also saw there wasn't really any negative impact,” he said. “For most of these people, this program ran in the background of their lives and they didn't even notice it.”

Customer research conducted as part of the pilot found that 98 percent of participants were satisfied with the program, and 93 percent said that they would likely participate in a similar program in the future. For BMW, the pilot proved that they could successfully manage the customer relationship in this new setting, and that currently available technology is capable of turning a mobility product into a grid asset.

“We were using production vehicles in our pilot that were owned by real households and that used our production telematics system,” said Adam Langton, energy services manager for BMW North America. “We were able to use that to execute grid event signals from the utility and send them to vehicles and get them to perform. So from our perspective, for demand response events and those types of use cases, vehicles are ready right now and can be a really valuable resource to utilities.”

"The champ of the program"

With only 100 participants in the EV program and participation restricted to home charging, there was a limit to how big of a role EVs could play in each DR event. Despite very few opt-outs, just seven vehicles participated in a given event on average.

In order to supplement smart charging, BMW developed a solar-powered energy storage system made from eight second-life lithium-ion batteries from BMW MINI E demonstration EVs (100 kilowatts/225 kilowatt-hours). A microgrid system was built at BMW’s Mountain View office to coordinate stationary battery charging with an on-site solar array, which provided electricity to the main office building while also ensuring enough charge to participate in the DR events. Almeida called the second-life battery “the champ of the program.”

Langton said that BMW was able to assemble the stationary battery with very few modifications. However, the report notes that “several issues” were discovered as the system was being commissioned, and a BMW task force was brought in to resolve them. Following the initial installation, however, the system ran reliably throughout the pilot with only “minor issues.”

These minor issues included a battery cell replacement that took longer than expected, a malfunction with the battery control program and temporary communication errors with the battery control system. There were also communication lags between the DR signal and the vehicles, and there were events where the system failed to meet the required load curtailment. But in each case, the root cause was identified and the error was prevented from happening again.

Also, to simplify the installation of second-life stationary batteries in future, automakers may start to think about how they can design EV batteries from the outset for stationary applications.

BMW is already thinking along these lines. A year ago, the automaker announced it would begin to turn new and used i3 batteries into plug-and-play energy storage solutions for homes and small businesses. These batteries do not require additional software, cooling systems or safety equipment, which significantly reduces the overall product cost. The used batteries can also be scaled into much larger grid resources, like the stationary battery in the i ChargeForward Program, an area which BMW plans to continue to explore.

A new business opportunity

For BMW, smart charging and second-life EV batteries represent a natural extension of the company’s sustainability mission, starting with the fuel switch from gasoline to electricity, said Langton. It also represents a potentially attractive new business opportunity.

“The higher cost of an EV compared to a traditional internal combustion engine (ICE) vehicle is widely considered the major obstacle toward mass market EV adoption,” the pilot report states. “The strategy of this pilot was to develop a mechanism that partially or fully levels the higher costs of EVs compared to internal combustion vehicles. The project aims to accomplish this goal by bundling the grid value of an EV’s demand response capability over the vehicle’s useful life and beyond (as a battery second-life stationary grid storage asset). This value is paid to the EV manufacturer, who then passes on this value to the driver.”

If revenue from grid services can help offset the cost of an EV, it could incentivize more EV purchases -- a win for auto manufacturers. For the utility, smart charging could play a significant and perhaps essential role in stabilizing the grid as more EVs and more intermittent renewable energy resources come on-line. PG&E forecasts it will have 1.2 million EVs in its service territory by 2030. Managing how those electric vehicles pull power off the grid can help the utility cope with electricity use spikes in the evening and over-generation of renewables, especially solar, during the middle of the day.

Smart charging programs also enhance the relationship between the automaker, the utility and their customers, which could pave the way for additional programs and interactions.

“The program demonstrated that automakers could serve as a trusted partner to drivers in programs like this,” said Langton. “Having the automaker involved in a program like this, we're able to get greater participation levels from customers, which means more grid value to the utility.”

“This is a new concept [and] customers are apprehensive about new things like this, because they worry about how it will impact the vehicle that they spent a lot of money on, and how it could impact their morning commute and their mobility,” he added. “Having BMW in their corner on this program gave them more confidence to participate, because they trusted us to protect their vehicle and make sure that they could meet their mobility needs.”

Phase 2 takes the show on the road

Based on the success of the i ChargeForward pilot, BMW received a grant from the California Energy Commission to continue with a second phase of the pilot.

“The second phase of the pilot will explore two primary themes: testing advanced smart-charging use cases that promise additional value to the grid, and evaluating customer engagement strategies that incentivize drivers to provide additional flexibility in their charging behavior,” the report states. With the new grant, BMW will work with PG&E to explore how charging can be moved throughout the day and to different geographic areas.

“We asked ourselves, ‘What if we use mobility as a strength of a vehicle grid resource?’ The fact that it moves means it appears on different parts of the grid, which means that you can manage it across time, which we're already able to do…and across different geographic locations,” said Langton. “This could be potentially valuable to utilities as they get more and more solar energy, and it's producing a lot more generation during the day. […] If we have the ability to manage charging across different locations, we can take some of that nighttime charging and move it to the daytime hours where a utility needs it.”

In 2017 and 2018, BMW will work with a pool of over 250 vehicles, including i3 and i8 EVs, to explore the grid benefits of increasing charging flexibility, as well as customer engagement. BMW will also be looking for additional utilities and new programs to accommodate smart charging and second-life batteries as a grid resource.

From PG&E’s perspective, the EV advanced charge management testing has been a success so far.

“The cool thing about it is there's a win-win. You’ve got a win for the customers, because they're going to get a value off of [these grid services]. [...] Then there's a win for the utility, because we're better managing the grid, which is becoming increasingly important as the grid is changing,” he said.

“I think there's an additional win too, because this helps to support these larger policy goals of not just decarbonizing transportation, but decarbonizing the grid,” Almeida added. “If you have a more flexible resource, then you're able to allow for more renewable generation moving forward. So it's a win-win-win.”

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New Microinverters and Metrics From Enphase in Its Race Against Time

June 20, 2017

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Monday was analyst day at Enphase. The microinverter and energy storage firm is making good progress in product development, cost reduction, and opex reduction. And company executives say they see a path toward sustainable profitability.

The big question is whether Enphase has enough time (or in this case, enough money in the bank) to get to that promised land.

New, slick microinverters

Enphase is rolling out new microinverter designs that are progressively smaller, more functional and more integrated. The microinverters are going to have to be cheaper, too; Enphase expects inverter pricing to settle at a 7 percent to 10 percent year-over-year reduction in cost.

Oppenheimer Equities "came away impressed with the company’s technology roadmap, which reaches $0.10 per watt cost structure on software-defined products which are expected to operate as plug-and-play microgrids."

Reaching profitability?

Enphase set a goal of reaching a $0.10 per watt cost (a 50 percent reduction) in 24 months, and the company is running "approximately six months late."

The company has streamlined its operations, let go of a large number of employees, and will have to continue to run lean to reach the profitability of module-level electronics market leader SolarEdge.

Growth in residential will be tough this year

"Welcome to the era of sub-15 percent annual growth. This is the new normal for residential solar," notes Austin Perea, a solar market analyst at GTM Research.

Enphase is counting, heavily, on the long tail to grow its market share in 2017.

Do the math

Enphase is losing money, expects an opex of $18 million this quarter, and has $30 million on its balance sheet. That leaves "limited wiggle room on execution," according to Oppenheimer.

Solar module-level electronics rivals SolarEdge and Enphase reported their respective first-quarter earnings last month, allowing for a side-by-side comparison of their financial results.


As we recently reported, despite the optimism and a claim of "60,000" AC battery preorders, Enphase's AC battery and energy storage aspirations seem to be fizzling, or are at least very delayed.

Enphase CEO Paul Nahi did some backpedaling: "We are facing a more competitive pricing environment and are actively working to reduce our cost in 2017. In addition, we believe the total addressable market is developing slower than anticipated." He added, "I don't think we’re going to see those [preorders] materialize. I think the actual numbers are going to be substantially less."

For the more conspiratorially minded...

In a recent SEC filing from Enphase, spotted by the GTM AI platform, we see a licensing agreement between Enphase and its manufacturing partner, Flextronics: 

On June 13, 2017, Enphase Energy, Inc. (“Enphase”) entered into a Master License Agreement (“Agreement”) with Flextronics Industrial, Ltd. (“Flextronics”), under which Enphase licenses its intellectual property to Flextronics in order to allow Flextronics to market, manufacture, and sell certain Enphase products. Such rights may be used to assure continuity of supply to Enphase customers.

That seems like an innocent enough assurance of continuity to its long-tail installer base. Or a pragmatic plan B if Enphase runs out of runway.

Oppenheimer has a price target of $2.00 per share for Enphase stock, currently trading at $0.80 per share with a market cap of $65.5 million. 

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Is California’s Weak Q1 a Sign of Residential Solar’s Future?

June 20, 2017

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Residential solar has seen brighter days.

As detailed in the most recent U.S. Solar Market Insight report, national residential PV installations fell both year-over-year (17 percent) and quarter-over-quarter (11 percent) for the first time since GTM Research began tracking the market on a quarterly basis in 2010. That’s a big deal.

When one takes a closer look at the data, it’s clear that much of this downturn can be pegged to the fortunes of California, which is still the largest state market for residential PV. But the state’s standing is diminishing.

In Q1, California accounted for its smallest share of the national market at 35 percent -- down from 42 percent in Q1 2016 -- while falling over 30 percent year-over-year.

And though California is not in danger of losing its position as the largest state market for residential solar, the downturn in the national market remains inextricably linked to the fate of California. So why is the state experiencing weakness, and what can we learn about what’s happening on the national level?

Policy and the weather explain some, but not all, of California’s weak Q1 performance

Many folks have pointed to the evolving regulatory and policy environment in California (e.g., NEM 2.0) as the reason behind the downturn in Q1, as both SDG&E and PG&E have transitioned to NEM 2.0 and SCE is transitioning in July. But while NEM 2.0 and the corresponding shift to residential time-of-use rates has complicated the sales pitch to customers, conversations with installers suggest that the actual impact on rooftop economics is minimal.

Additionally, this explanation would be more compelling if it was only PG&E that experienced contraction in Q1 -- being the utility’s first full quarter in NEM 2.0 -- but PG&E has been the most resilient investor-owned utility in California, falling less compared to SDG&E and SCE both quarter-over-quarter and year-over-year.

If regulatory and policy constraints can’t paint a full picture of what’s happening in California, California’s weak Q1 can be partially explained by an unseasonably rainy January and February that undeniably resulted in the loss of build time across the state.

However, according to early permit data from OhmHome Solar Index, permits pulled in April were down to January levels. And while a down month for permits doesn’t necessarily negate the weather issue, permits have been trailing since Q1 2016, suggesting an underlying weakness unrelated to cyclical or seasonal issues.

Weather- and policy-related challenges, though material, don’t appear to fully answer the question of why California has experienced weakness as of late.

A look at the fortunes of top national installers paints a clearer picture of what is happening in California and, consequently, in the national market.

Sustainable growth of the Big Three paints a clearer picture

Though less exposed to the national installers than other major state markets, the top three solar players still account for a significant share of the market in California. And their efforts to prioritize profitability and pull back in less economically attractive markets has been noticeable. 

According to GTM Research's U.S. PV Leaderboard, the top three national installers have, in aggregate, accounted for a third of the state’s installations, as recently as Q1 2016. But as these players make a concerted effort to shift to a more sustainable growth strategy, their collective installations and overall market share have either declined or remained flat.

In California, SolarCity’s installation decline has been the most noticeable as the company has been more aggressively pursuing product diversification toward cash and loan sales. In addition, the share of third-party ownership has dropped from nearly 50 percent in Q1 2016 to less than 35 percent in Q1 2017.

Installers across the competitive landscape are facing issues of market saturation and customer fatigue, but national installers appear to be the most exposed to customer acquisition challenges, as low-cost sales channels (i.e., referrals) are difficult, if not impossible, to replicate at scale.

And while the long tail’s overall installations have fallen year-over-year, the quarterly rate of decline has been much less severe than in the case of the top three. The market is not without its structural challenges -- including the increasing difficulties of customer acquisition -- but much of the state’s recent downturn can be pegged to the performance of national players.

The market will rebound, but slowly

Looking forward to the rest of 2017, annual installations in California are expected to fall for the first time ever, while Northeast states are expected to be generally flat. GTM Research forecasts approximately 2 percent growth for the national residential solar market in 2017, which is down considerably from 20 percent annual growth in 2016.

Across the U.S., installers need to create demand for rooftop solar beyond the early adopters that have driven the market to date, whether through new customer demographics or expanding operations into emerging geographies that have a higher relative portion of early adopter customers.

For example, Utah, South Carolina and Texas all saw eye-popping installation growth in 2016, which is expected to continue in 2017. And as of last week, Nevada, which restored net metering, may help to partially offset major market decline going forward.

But California’s impact on the national market cannot be understated. Even at its lowest share of the market, the state accounts for over a third of national installations. What happens in California resonates throughout the country.

With other major markets just as susceptible to national installers pulling back in unprofitable regions and devoting more resources to emerging geographies, gone are the days of explosive double-digit growth.

Welcome to the era of sub-15 percent annual growth. This is the new normal for residential solar. 


Austin Perea is a solar market analyst at GTM Research.

Get access to all of GTM Research's solar data and reports with a research subscription. Learn more here.

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100% Renewables Plan Has ‘Significant Shortcomings,’ Say Climate and Energy Experts

June 19, 2017

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It's a common claim from advocates: We know we can create a 100 percent renewable grid, because Stanford Professor Mark Jacobson said we can.

Jacobson's peer-reviewed studies assert that it is possible to convert all energy use in the U.S. to wind, water and solar -- while maintaining grid reliability, saving money and creating jobs.

It will require a World War II-style mobilization, he notes. But it's possible.

But that conclusion is now being questioned in a big way.

On Monday, a battalion of fellow energy researchers published a rebuttal to Jacobson's plan in the same prestigious journal where his study first appeared. The 21 authors include some of the most prominent climate change and clean energy experts in the country, like Ken Caldeira of Stanford, Daniel Kammen of U.C. Berkeley, and Varun Sivaram of the Council on Foreign Relations.

The lead author is Christopher Clack, a former research scientist at the University of Colorado and current CEO of the grid modeling consultancy Vibrant Clean Energy.

The sheer number of co-authors suggests this is not a battle of egos. Their accumulated expertise has advanced the understanding of climate change and the system impacts of high amounts of renewable energy. They are not industry shills trying to undermine the advance of wind and solar; they are scientists who want to use evidence-based reasoning to optimize it.

And they deliver some pointed academic smack talk.

"The scenarios of [the Jacobson study] can, at best, be described as a poorly executed exploration of an interesting hypothesis," the authors assert.

The broader conflict is over the best way to achieve a low-carbon grid.

Jacobson opted for a constrained system that excludes all but a handful sources of energy. His work shows what could be technologically possible if society prioritizes the "right" things. However, because decarbonization is so hard, it requires a more diversified approach for success, say the group of researchers.

Jacobson's study has already encouraged some lawmakers to propose 100% renewable energy plans. The authors of the rebuttal say those policies are based on flawed science.

"If one reaches a new conclusion by not addressing factors considered by others, making a large set of unsupported assumptions, using simpler models that do not consider important features, and then performing an analysis that contains critical mistakes, the anomalous conclusion cannot be heralded as a new discovery," the authors write.

Jacobson remains unshaken.

"Virtually every sentence in the Clack article is false as evidenced by [my] line-by-line response," he wrote in an email Saturday, referring to a counter-rebuttal he had written. "There is not a single error in our paper."

Supersized hydropower

The Jacobson model uses wind and solar power as the primary energy providers for the U.S., supplemented by hydropower, pumped hydro storage, a few other storage technologies, and flexible load as needed to match total grid supply with demand.

If renewable generation exceeds load, the surplus goes into storage or hydrogen production. If renewable generation doesn't meet instantaneous demand, flexible loads get deferred for up to 8 hours. If generation can't satisfy inflexible load, the system draws on stored electricity and then from hydropower, "which is used only as a last resort."

The article, published in the Proceedings of the National Academy of Sciences in December 2015, says that, in the fully renewable system, "supply exactly matches load plus losses and changes in storage at all times." The modeling covers every 30-second increment from 2050 to 2055.

Data in the article contradicts the role that Jacobson says hydropower will play, the Clack study contends.

The authors point to supporting information from the Jacobson study that shows maximum output from hydroelectric facilities won't exceed 145.26 gigawatts, which itself is about 50 percent more than the existing hydro capacity today. That's actually the sum of hydro storage and hydropower, which operate differently.

In the Jacobson study, though, a chart covering several days of grid operation in January 2055 shows hydroelectric output exceeding 1,300 gigawatts. The method of last resort for grid balancing would have to perform at a capacity nearly 10 times greater than its stated maximum capacity -- more like 15 times, given that this is referring to hydropower and not storage.

(Image credit: Jacobson et al.)

The 1,300 gigawatts of hydro isn't an error; it's an assumption, Jacobson said in an interview.

His model maintains the same amount of hydro energy in a year, because that's tied to the volume of water available. In his vision, though, hydropower would be pulled off daily energy duty to store up large amounts of water for massive discharge on a few peaks each year. He assumes retrofits of higher capacity turbines on existing dams could make this possible.

The 100 percent model succeeds or fails based on its ability to meet power demand even when wind and solar can't supply it all. As currently constructed, hydropower backstops the whole system in moments when even stored electricity does not suffice. The feasibility of this roadmap hinges on how likely it is to massively increase the instantaneous discharge rate of U.S. hydro assets.

"There's no realistic scenario whereby you can expand the output of the U.S. hydropower system by a factor of 10," said David Victor, one of the 21 co-authors and director of the International Law and Regulation Laboratory at U.C. San Diego.

New hydro capacity has stalled out for the last 20 years or so, mostly due to regulations. The Department of Energy calculated that hydro and pumped storage could feasibly grow to 150 gigawatts by 2050, including upgrades to existing plants.

"Anything we have to do has to be done on a large scale," Jacobson said. "We’re talking about changing the entire energy infrastructure of the United States."

Grid reliability without grid modeling

Operating the grid requires more than producing enough power to meet demand in a given moment; it also has to be delivered. Transmission and distribution constraints play a significant role in determining whether generation can reach load centers, especially in the cases of wind and solar, which are often constructed far from dense load pockets.

Jacobson's grid reliability study does not model the spatial dimensions of the transmission system.

"As a result, their analysis ignores transmission capacity expansion, power flow and the logistics of transmission constraints," Clack and company write. "Similarly, those authors do not account for operating reserves, a fundamental constraint necessary for the electric grid."

The model also ignores requirements for frequency regulation to ensure grid reliability.

In his line-by-line response to these points, Jacobson writes: "This critique is wrong in critical respects and fails to demonstrate any important errors in our economic analysis."

In an interview, Jacobson added that models require tradeoffs. He included 30-second time resolution but no spatial resolution; other models focus more on spatial resolution with less granular time resolution.

The study includes an estimate of the cost of additional high-voltage DC transmission lines, he noted. But that left the other researchers unsatisfied with the broader impact to grid management.

"If you’re not even modeling the transmission system in any way, how can you say you’ve got a reliable grid?" Clack said in an interview.

Experimental storage trumps commercially ready options

Energy storage plays a critical role in absorbing surplus generation and discharging it at times of need. The storage used in the Jacobson plan, though, will look unfamiliar to observers of today's storage industry.

The young energy storage market is growing fast: GTM Research expects the U.S. market to be 22 times larger in megawatt-hour terms by 2022. Lithium-ion technology has dominated deployments for the last 10 quarters, capturing 96.5 percent of the market in Q1 of this year.

Lithium-ion storage plays no role in Jacobson's fully renewable energy system, other than to power electric vehicles. 

"Batteries for stationary power storage work well in this system too," the Jacobson study explains. "However, because they currently cost more than the other storage technologies used, they are prioritized lower and are found not to be necessary for a reliable system."

In its place, the model uses six other types of storage. Underground thermal energy storage (UTES), modeled on a government-funded pilot project called Drake Landing in Canada, will handle all storage for building air and water heating. This dwarfs the other types of storage, with a maximum deliverable capacity of 514.6 terawatt-hours. Chilled water storage and ice storage will handle cooling. 

Phase-change materials in concentrating solar power plants will store up to 13.26 terawatt-hours of electricity, and pumped hydro will hold 0.808. Hydrogen storage will supply transportation and high temperature processes.

Of those six, only pumped hydro has achieved widespread commercial use on the grid, but it has a clear limit to its growth potential.

Chilled storage has seen commercial deployments by companies like Calmac, Ice Energy and Viking Cold Solutions. These solutions use electricity to precool a liquid, which can then chill buildings at times when electricity is more expensive.

The reliance on UTES requires the technology to quickly transition from pilot scale to nearly every building heating system in the United States. Jacobson says that he believes the technology can scale.

"UTES has been demonstrated at the scale it needs to be deployed -- neighborhood and complex scale, and it has been tested in more extreme conditions (Canada seasonally) than it would be needed for in the United States," he writes in his line-by-line rebuttal.

Jacobson stressed in an interview that the technology itself works and can grow.

"When something is so simple, and it's cheap already, it has tons of potential to be commercialized and used on a large scale, particularly in new communities," he said.

The phase-change materials he pairs with CSP, similarly, have not passed from demonstration phase to commercial deployment; that technology is meant to carry the brunt of the electrical (as opposed to the thermal) storage in this system. 

Along with the risks inherent in relying on new technologies that haven't scaled to mass distribution, this also delays the timeline for implementation.

"Thirty-three years away in terms of energy isn't very long for installing things," Clack said. "We need to be installing things today, and we need to be installing things today that we know will be around for a decent amount of time."

Wind and solar are getting deployed all the time, but there's no clear pathway for converting most American buildings to underground thermal storage. That requires a massive supply chain, and companies that are ready to sell and install the devices.

No optimization

The Clack paper critiques too many other aspects of the Jacobson model to include them all here. (One notable contender: In calculating lifecycle greenhouse gas and mortality emissions for civilian nuclear energy, Jacobson factors in the effects of nuclear war, which is assumed to occur on a regular 30-year cycle.)

It's worth reiterating, though, that Jacobson's renewable roadmap is not, nor does it claim to be, an optimization study.

It did not survey all the options and select the best portfolio on the basis of speed, cost or some other metric. It runs a program to balance energy supply with demand every 30 seconds for a given configuration of renewable and storage assets. As Jacobson writes in his rebuttal, "It is a trial and error model."

He came to this after growing frustrated with the limitations of optimization models. Those models took a long time and couldn't include all the details he wanted to include.

"It's not a least-cost solution that we’ve come up with; it’s a low-cost solution," he said. "Our low-cost solutions are lower than the current grid costs."

This may be useful in signaling to the world that the math checks out; renewables and storage can be deployed at levels that, on paper, meet the total energy needs of the U.S. But it does not show that this is the best path. That's concerning to researchers like Clack.

"If you have these goals and you don't achieve them, there tends to be a very strong backlash," Clack said.

That backlash could come from a state legally enforcing the Jacobson plan, only to discover real-world technologies can't make it work. Additionally, it could limit the pursuit of other energy technologies that are important for decarbonization.

The passion behind the arguments illustrates how high the stakes have become. There's limited time left to chart a low-carbon energy pathway. The 21 authors countering Jacobson want to make sure we're paying close attention to the details.

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Nevada Governor Kills Renewable Energy, Community Solar Bills With Deregulation Pending

June 19, 2017

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It looked like renewable energy advocates in Nevada were going to win the legislative Triple Crown last week, but two of the three clean energy bills in contention never made it across the finish line. 

Republican Governor Brian Sandoval vetoed the two bills on Friday, citing uncertainty amid Nevada’s pending shift to an open and competitive energy market. 

AB 206 would have increased the state’s renewable portfolio standard (RPS) to 40 percent by 2030, up from 25 percent in 2025, and created attractive new incentives for energy storage. The second bill, SB 392, would have established a 200-megawatt community solar program by 2023.

On Thursday last week, Sandoval signed a popular bill (AB 405) that restored net metering credits for rooftop solar customers in the Silver State, giving the distributed energy market an enormous boost. Following that win, supporters hoped the RPS and community solar bills would get approval too.

AB 405 appears to have complicated things for the community solar bill, however. In his veto message, Sandoval said he was concerned that SB 392 could conflict with the rooftop solar policy.

"SB 392 attempts to link itself to AB 405 by requiring the solar energy credits to be the same for both rooftop solar and community solar gardens,” Sandoval’s veto statement said. “Although I am confident that the system set up by AB 405 will be beneficial to Nevada and its solar energy economy, it is unclear whether these bills are compatible or conflicting.”

Sandoval said he was also concerned about passing new energy legislation in light of the state’s pending Energy Choice Initiative, which could dramatically restructure Nevada’s electricity market if voters give the initiative second approval in 2018. Solar advocates argued that rejecting the community solar program flies in the face of public opinion. 

“Governor Sandoval’s disappointing decision to veto community solar access is at odds with the more than 70 percent of Nevadan voters who supported energy choices in November’s election, and with the overwhelming support for community solar from national security experts, faith communities, small businesses, and clean energy advocates,” said Jessica Scott, Interior West director at Vote Solar. 

Sandoval also cited the Energy Choice Initiative as his reason for vetoing the ambitious new RPS target, despite his overall support for the expansion of clean energy in the state. 

On the path to an open and competitive market, "decisions must be responsibly informed with research, study and debate, particularly with the likelihood of the approval of energy choice in Nevada next year,” the governor wrote in his veto message, news website The Nevada Independent reports. “For these reasons, although the promise of AB 206 is commendable, its adoption is premature in the face of evolving energy policy in Nevada.”

Nevada’s powerful casino lobby group was a strong opponent of AB 206, because it would have required large gaming companies, which recently paid tens of millions of dollars in exit fees to purchase power on the open market, to also meet the higher renewable energy targets. In April, Virginia Valentine, president of the Nevada Resort Association, wrote a letter to lawmakers that said, "We are concerned that this bill may be too much and too soon."

Renewable energy advocates sought to reach a compromise with opponents by lowering the initially proposed RPS target from 50 percent to 40 percent by 2030, and by creating multiplier credits for energy storage. The law would have allowed storage to meet up to 10 percent of the overall RPS target. Sandoval’s veto kills Nevada’s novel energy storage targets.

“Distributed generation landed an important win from the net metering restoration bill. But what is unfortunate is that Nevada had a chance to be on the forefront of the next wave of RPS legislation,” said Cory Honeyman, associate director for U.S. solar at GTM Research. “Nevada's bill had an important and forward-thinking plan to explicitly credit storage deployment in future RPS obligations. And as more and more corporates continue to procure large-scale solar in the state, on top of a reboot in rooftop solar, what's now missing is a state-level policy framework to pair all of that solar deployment with storage to support higher levels of solar penetration on the grid.”

To address the energy market concerns raised in his veto messages, Sandoval tasked his Committee on Energy Choice to study the ramifications of a higher renewable portfolio standard, as well as a community solar program, and issue a set of recommendations ahead of the 2019 session -- the next time lawmakers in Nevada will meet. 

Renewable energy advocates are already positioning to override Sandoval’s vetoes in the next session. Assemblyman Chris Brooks, who sponsored the RPS bill, said he plans to work with corporate and clean energy stakeholders to bring back the measure in 2019. AB 206 was backed by Apple, Tesla, Unilever and several other prominent businesses, including MGM Resorts -- which broke with the casino lobby group in choosing to support the RPS proposal.

“Our goal this session was to shift Nevada away from a boom-and-bust cycle economy and towards a more prosperous future,” said Brooks. “AB 206 would have made Nevada not just a national leader, but a world leader, in the next generation of clean and renewable energy sources that would have diversified our economy and created good-paying, high-quality jobs.”

Nevada electric utilities currently spend around $700 million each year importing fossil fuels, according to the Natural Resources Defense Council. Meanwhile, the cost of procuring electricity from large-scale solar farms has fallen by 80 percent since Nevada last changed its RPS target in 2009. In a recent report, NRDC found that AB 206 would have added thousands of megawatts of clean power to Nevada’s grid, while attracting billions of dollars in capital investment and economic development, and creating thousands of jobs. 

“Governor Sandoval was persuaded by the fringe elements of his party, instead of listening to science and the people of Nevada,” said Dylan Sullivan, senior scientist at NRDC. “In a place as sunny as Nevada, it makes no sense to rely primarily on out-of-state fossil fuels for electricity.”

While many expressed disappointment that AB 206 did not get approved, the clean energy industry group Advanced Energy Economy highlighted several other legislative wins. In the last week of session, four significant energy bills were signed by Governor Sandoval: SB 150, which instructs the Public Utility Commission of Nevada (PUCN) to establish annual energy savings targets; AB 223, which directs 5 percent of efficiency program spending to programs in low income communities; SB 204, which requires the public utilities to investigate the need for an energy storage procurement requirement; and Senate Bill 65 that allows the PUCN to prioritize energy resources that reduce energy cost and demand. 

“By signing these bills, the Governor has taken an important step in his attempt to establish a new Nevada advanced energy market,” said J.R. Tolbert, vice president of state policy for Advanced Energy Economy. “While the energy legislation that was signed by the Governor is a great starting point, our attention now turns to implementation to ensure that Nevada fully capitalizes on this opportunity.”

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Lightning, Ice Baths and Sandblasting: Inside the Quest for World’s Most Reliable String Inverter

June 19, 2017

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Huawei is obsessed with failure.

Or, to put it more precisely, the Chinese string inverter manufacturer is focused on pinpointing any possible source of failure in its products that need to endure at least 25 years in some of the world’s harshest conditions. It uses that information to ensure that its inverters achieve industry-leading reliability.

Not far from its corporate headquarters in Shenzhen, China, Huawei has a sprawling Global Compliance & Testing Center. The GCTC can mimic, and even exceed, the harsh conditions Huawei’s string inverters may encounter when they are deployed in large-scale solar power plants.

Huawei is the largest inverter manufacturer in the world. The company expects global shipments to reach between 30 and 35 gigawatts this year. The testing center ensures that those inverters are top quality.

“The GCTC is something that only a very few big companies could attempt to do in-house,” said Bates Marshall, vice president and general manager for North America Smart PV Plant Solutions at Huawei. “The reason we have this type of capability is because reliability is the single most important attribute of our products. It’s part of our DNA.”

Huawei’s roots are in the telecommunications industry, and it is currently the third-largest smartphone company in the world. The GCTC is one of 16 Huawei R&D centers across the globe. One of the reasons Huawei entered the inverter business was because it saw an enormous gap in the market, and therefore an opportunity to leverage its research prowess to improve the reliability of string inverters.

“We saw that the reliability outcomes in the PV market were very poor,” said Marshall, who pointed to Huawei’s long history of producing sturdy telecommunications infrastructure, like 4G LTE base stations. “We knew that we could bring this reliability expertise into PV and make a big impact. And we deliver that quality by leveraging this GCTC capability that already existed.”

Finding the weak points

String inverters that find their way into the Huawei GCTC are essentially subjected to torture. For example, because string inverters could very well be hit by lightning over the course of their decades of outdoor operation, the GCTC literally creates lightning with gold.

Huawei takes an inverter and places it on a tower outside. “From that tower, we launch a rocket into the cloudy sky that trails a gold thread,” said Marshall. “We will actively seek to trigger lightning, and that lightning bolt will strike the rocket and the gold wire and go down into the inverter, and we will look at the effect.”

When they’re not being shocked by lightning, Huawei’s string inverters undergo a range of other tests meant to mimic the worst possible stresses and conditions they might encounter.

One test involves a week in a chamber that can reach temperatures as low as -40 degrees Celsius. But over the course of the test, the inverters aren’t simply left to chill. They’re doused with water, left to freeze and then warmed up to thaw out. All the while, Huawei powers the inverters on and off and connects and disconnects them from loads in order to gauge their resilience and reliability.

Other tests involve sandblasting inverters and mimicking the low-pressure environment they would encounter in high-altitude environments. All of these experiments are done in addition to the battery of mandatory standards testing that all inverters are required to comply with in different regions of the globe, such as the UL 1741 inverter standard and National Electric Code requirements in the U.S.

But satisfying standards is just the very beginning. The GCTC also looks to always push the envelope, given Huawei’s obsession with reliability. That means constantly developing new tests, some of which have resulted in design changes, such as ditching the external fans usually found in inverters.

“In our [string inverter], one of the characteristics that is unique is that it’s passively cooled. Instead of forced air fans like most of the competitors use, our design relies on a patented heat sink on the back to remove heat,” said Marshall.

“We have to think of things like, what would happen if a customer plants trees next to the inverter and it’s dropping leaves on it over the next 25 years?” added Marshall. To test for that scenario, the researchers at the GCTC fill the inverter heat sink up with leaves and then run an array of experiments to ensure the inverter will still function properly.

More reliable, by design

The wide range of tests that are done at GCTC have positively impacted projects in the field that face trying conditions. According to a study conducted by international engineering firm TUV, Huawei’s string inverters installed at a major 220-megawatt site have an availability of at least 99.99 percent across the board. This compares very favorably to industry norms of around 99.5 percent availability.

Huawei’s inverters installed around the world are seeing stable performance in trying conditions, from being doused with salt mist in the Philippines to baking in extremely high-temperature project sites in Jordan and Delhi. Customers report to Huawei that energy yields for projects are consistently higher than they would be for central inverters.

Many of the tests Huawei conducts at the GCTC simply could not be applied to central inverters. Why? String inverters are much smaller than central inverters, which are so big that they are often transported on an oversized flatbed trailer -- as opposed to string inverters, which can be carried around by two people.

The size of central inverters makes it impractical to run them through the litany of rigorous tests that Huawei can do with its string inverters. “If you think about subjecting them to the same environmental conditions, it’s an impossibly different task for the central inverter,” said Marshall. “It’s one of the reasons that the reliability outcomes of the central inverters are so much worse.”

For Huawei, reliability is also enhanced by the architecture of its string inverters. Put simply, some of the components most likely to fail on a central inverter just don’t exist on Huawei’s string inverters -- think of it as addition by subtraction.

“One of the fundamental things we have done is remove those elements that fail in competitors' devices,” said Marshall, whether it’s fans, the filters for the fans, or DC fuses on the inputs. “For example, our devices don’t have unnecessary LCD screens because there are no LCD screens that will last out in the sun for more than 10 years.”

When it comes to inverters, less really can be more. 

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