Category: Blogs

US solar feeling ‘invincible’ after navigating treacherous year

There’s nearly always a positive vibe at a trade show. A combination of the organisers’ best efforts and the virtuous circle of talking to like-minded people all day, which is great for your brain chemistry, leaves you feeling lighter than you may on an average day in the trenches. It doesn’t necessarily mean what’s happening beyond the showfloor warrants the smiles and backslapping taking place on it.

With that caveat at the forefront of my own mind, I have to say that Solar Power International 2018 felt extremely positive. I’m a dour, sceptical Scotsman. Provoking enthusiastic positivity for anything can be a slog.

Context could be king in this instance. The industry has dealt with steel tariffs, the Section 201 trade barriers, the drop in demand for tax credits and, just before the show began, 25% tariffs on Chinese inverters. Having ridden out all that and having conversations about new solar States opening up to deployment, module prices falling and trackers carrying on their march to higher latitudes, is fairly remarkable. New projects, new technologies and new opportunities.

“In general, there’s a really positive feeling of invincibility to the market,” says Steve Daniel, VP of sales and marketing at mounting and tracker manufacturer Solar FlexRack. “Back in March, I didn’t think we were going to feel this way in September. It’s been very difficult with the tariffs, we’ve just had to work through them but we haven’t seen much drop off because of module or steel tariffs.”

That’s not to say that there hasn’t been some pain but as Daniel describes it, this is being shared.

“Everyone has lowered their margins a little bit and their expectations, but the projects are still moving. There’s been a few delays, but there are always delays in solar projects. Anything can happen and I’ve seen everything. It doesn’t feel that different. It’s just another set of issues to work through,” he adds.

What’s next in the US calendar? Solar & Storage Finance USA returns to New York for its 5th time later this month and will be looking at raising capital for solar, storage and collocated solar and storage projects in the USA. The conference aims to help delegates understand how debt providers are evolving propositions for storage and how they can access projects for standalone and co-located projects. Meet debt providers, funders, utilities, corporate off takers and blue chip energy firms with capital to invest.

There is lots of talk about some of the lumpiest boom and bust markets (think Europe) heading towards a period of growth that is more sustainable. The testing year that the US has just ridden out is another example.

“I think there is a resiliency in the industry that people have built up. I’ve been doing this for eleven years now and every year there is something new and we just figure out a way to keep going,” says Daniel adding that the end demand for solar is contributing factor now the “economics are fantastic” and “undeniable”.

Joe Song, VP of project operations at the developer and investor Sol Systems is reluctant to make a prediction for the coming year. He sees one outside factor contributing to some of the positivity.

“The only that has ever been true is that whatever we expect to happen, will definitely not happen! We went into 2017 thinking all these projects were going to progress and then 201 came around and it paralysed the industry. Everyone went into this year thinking no projects were going to happen. Come May the China market pivoted and it opened up a whole lot of opportunities.”

In addition to the scope for using high-efficiency modules, off the back of those price reductions sparked by China’s policy shift, trackers, emerging US markets and an increasingly hard line on soft costs offer plenty of reason to cheer. Even for a dour Scotsman.

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The outlook for Energy Storage in New York is bright – here’s why

2018 promises to be an exciting year for energy storage in New York State. The year began with a major announcement by Governor Andrew Cuomo who, in his annual State of the State address, announced a new energy storage initiative and set an unprecedented 1.5GW target for energy storage deployment in the state by 2025. Governor Cuomo also announced the investment of more than US$260 million in funding to accelerate the growth of the industry. The initiative is intended to spur the widespread deployment of energy storage systems in the state and grow 30,000 jobs in the state’s energy storage industry.

Governor Cuomo’s announcement came on the heels of his approval of energy storage deployment legislation at the end of 2017. The new law, which requires the Public Service Commission to establish an energy storage goal and deployment policy for 2030, was passed unanimously, with bi-partisan support, by the NYS Legislature.

These combined actions are a clear signal that New York is serious about energy storage.

Mapping the way forward

The key question however, is how New York will achieve the level of energy storage called for by the Governor. For the answers, the industry is looking primarily to the soon-to-be released New York State Energy Storage Roadmap. In March 2017, the NYS Public Service Commission required the New York State Energy Research and Development Authority (NYSERDA) and the NYS Department of Public Service staff to develop an Energy Storage Roadmap to identify current and anticipated electric system needs that storage is uniquely suited to address and the levels of energy storage that will provide net benefits to ratepayers in New York State. The Roadmap must also include “market-backed” policy and regulatory recommendations, that are consistent with the State’s Reforming the Energy Vision (REV) initiative, to spur energy storage deployment in New York.

The Draft Roadmap is expected to be submitted to the NYS Public Service Commission in the second quarter of 2018 and, at that time, it will become the subject of extensive public review and comment. Final action on the Roadmap by the Public Service Commission is expected in late 2018.

While there undoubtedly will be considerable and justifiable attention given to the levels of storage called for the Roadmap, the policy and regulatory mechanisms proposed to achieve the target levels will also receive a great deal of scrutiny and are essential to the success of the energy storage initiative.

A collective effort is required

NY-BEST and our members have long actively advocated for policy and regulatory changes, as part of New York’s on-going REV process, to monetise the benefits that energy storage provides to the electric grid. From providing flexible resources to enable widespread deployment of renewable energy resources, to improving grid resiliency and efficiency, to shifting peak loads and reducing harmful emissions, storage brings a multitude of benefits to the grid that are not being fully valued in our electric system today. NY-BEST has been coordinating industry input into the Roadmap and a range of policy and regulatory options have been raised by our, including: long term contracting mechanisms, new tariff and rate structures, financial incentives as well as other innovative ideas, such as a clean peak standard.

The Energy Storage Roadmap process being undertaken in New York presents a significant opportunity for the storage industry to help craft and implement new mechanisms that will provide value for the services energy storage provides. As it is often said, “the devil is in the details,” and in the case of New York’s Energy Storage Roadmap, the details of the policy recommendations will be critically important for the energy storage industry.

NY-BEST and our members look forward to continuing to participate in this important process and we invite the energy storage industry to join us. 

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Distributed energy technologies challenge conventional thinking around grid planning, Part 2.

In part 2 of a technical paper first published in PV Tech Power Vol.13, Alex Eller of Navigant Research continues his look at how one of the most significant expenses for electric utilities, maintaining and upgrading transmission and distribution (T&D) networks, could be undercut using non-wires alternatives – including energy storage.

Risk aversion hinders widespread adoption

Despite the advantages and growing popularity of NWA (non-wires alternatives) programmes, significant barriers remain to more widespread adoption. As with many new electrical grid technologies, the level of confidence utilities have in the new programmes is crucial. Although early results have been promising, many utilities do not yet have enough faith in NWA programmes to overcome the traditional preference and expertise with T&D investments. This lack of faith is the result of both an institutional resistance to change within many organisations and the fact that prevailing rate recovery mechanisms for utilities typically do not encourage alternatives and innovation. If there is no regulatory pressure in place, there are few reasons why a utility would pursue an NWA. There is a higher perceived risk associated with these types of short measure life projects compared to a traditional equipment upgrade that is built to last 20 years or more. In addition, a T&D upgrade aligns with the historical experience of a utility. Thus, they may be more comfortable implementing a poles and wires upgrade.

Much of the hesitation to embrace NWAs stems from the challenges with engaging customers and being able to effectively guarantee a necessary amount of load reduction. Investments in energy efficiency, DR and solar PV have proven effective at reducing load in select areas; however, they do not guarantee the level of reliability and control that utilities demand. Although customers may typically respond to a DR signal to reduce demand, they often can override that signal and continue their normal operations. Due to this inherent unreliability, new technologies such as distributed generation and energy storage have emerged as more expensive but advantageous components of an NWA portfolio.

The increasing popularity of energy storage in NWA programmes and as a single-technology alternative to conventional T&D investments stems from the reliability and flexibility of storage systems on the grid. Utilities prefer direct control over critical assets that are used to serve peak demand and ensure the capacity of grid infrastructure is not exceeded. As a result, energy storage is typically seen as a more reliable form of load reduction compared to NWAs composed of customer-side DER. Centralised, utility-scale energy storage systems (ESSs) in particular fit more with traditional utility investment models and technical expertise. ESSs provide added flexibility with the variety of services they can provide when not needed to support T&D infrastructure, including frequency regulation, voltage support, spinning reserves, outage mitigation and effectively integrating renewable generation.

Another advantage of energy storage is that the technology can be sized appropriately to meet grid needs and can be sited in numerous locations to deliver maximum benefits—either in front of customers’ meters on the T&D grid or behind-the-meter (BTM).

Transmission-level ESSs designed to relieve congestion have been relatively rare to date due to the large storage capacity required to alleviate these issues. Distribution-level ESSs have been the most common type of T&D deferral projects to date. These systems are frequently built at substations or specific points of congestion on the distribution grid to defer investments and improve reliability by isolating outages. Many distribution-level systems have been relatively small pilot projects initially, but utilise modular designs allowing for storage capacity to be expanded over time.

BTM energy storage to defer T&D investments is more complex and dynamic than transmission or distribution-level systems, although it has the potential to be far more disruptive to the industry. BTM energy storage for T&D deferral includes systems located in both C&I and residential buildings that utilise advanced software and virtual aggregation to provide targeted congestion relief for grid operators. The primary advantages of BTM storage providing T&D deferral are potentially lower costs to utilities and the ability to offer more visibility and control at the edges of the grid.

BTM storage for these applications is currently a nascent market, with several key challenges including:

•           Relatively high upfront costs for customer acquisition in some situations

•           Small amount of storage capacity per system

•           Concerns regarding the reliability of load reduction with customer or third-party owned systems.

Momentum evident, despite barriers

As with NWA programmes in general, there are several barriers standing in the way of energy storage being widely used to defer T&D investments. Despite recent advances, the technology and market remain quite new and immature, resulting in a conservative approach from often risk-averse utilities. Fully understanding and analysing the value of these energy storage projects is also challenging as the complex nature of the technology –including its ability to provide multiple services at different times – is not captured in many grid modelling and simulation systems. Furthermore, there is a major variation in the costs to upgrade T&D infrastructure. Energy storage and NWAs are typically only a cost-effective alternative when T&D projects face high costs due to challenging terrain, population density, real estate costs, weather constraints and other issues.

While barriers to widespread growth remain, both NWAs and storage-specific projects to defer T&D investments are gaining significant momentum with a variety of new projects being developed around the world. In addition to the NWA projects already discussed, energy storage projects for T&D deferral are growing in popularity and have recently been announced in Arizona, California, Massachusetts and Australia. These new projects are utilising several different business models to match the necessary technical and financial solutions with a customer’s needs and available resources. The innovations happening in this market are helping drive the overall transition to a more intelligent, dynamic and distributed energy system the promises to improve efficiency, empower customers, and reduce environmental impact.

Read Part 1. of this technical paper on the site here.

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Distributed energy technologies challenge conventional thinking around grid planning

Innovations in new distributed energy technologies are challenging conventional thinking around the most effective ways to serve electricity customers and utilise grid infrastructure. These innovations in hardware, software and business models are helping to drive the overall transition to a more resilient and intelligent energy system that aims to deliver cleaner and more efficient electricity to an increasingly engaged customer base.

Maintaining and upgrading transmission and distribution (T&D) networks represents one of the most significant expenses for electric utilities and traditionally there were few alternatives to costly investments in expanded capacity. The new generation of less expensive and more intelligent distributed energy resources (DER) and energy storage technologies located on both the T&D grid and customers’ properties has opened the door to a compelling array of new options for how to best utilise existing infrastructure.

These technologies will disrupt the conventional T&D industry by maximising the value and efficiency of existing grid assets while empowering customers to participate in the management of the grid. This article will explore the overall drivers of T&D upgrades and the challenges facing these projects as well as new alternatives, with a focus on diverse non-wire alternative (NWA) projects, their benefits and challenges and the emerging trend of using purely energy storage to defer costly upgrades.

A need for upgrades

The electric T&D system is a constantly evolving machine that requires continual monitoring, maintenance and upgrades. Traditionally, the required upgrades to the T&D system were relatively easy to predict and could utilise a consistent and standard set of grid equipment and infrastructure to meet growing electricity demand. Rapidly evolving technologies and evolving customer demands have made predicting and performing grid upgrades much more complex in recent years.

There are three primary issues driving the need for T&D upgrades:

  • Congestion and generation curtailment: The growing amounts of variable renewable generation have exacerbated congestion challenges in many areas, leading to the curtailment of energy. Actual rates of curtailment vary considerably in markets around the world. The highest average curtailment rates have been seen in China, where some provinces have wasted nearly 39% of wind generation due in part to limited transmission capacity.
  • Load and peak demand growth: Typically, increasing demand for electricity and load growth has closely followed overall economic development. However, load growth rates have decreased or remained flat in many developed economies in recent years, while the dynamics of peak demand periods on the grid continue to evolve. Some utilities are experiencing decreasing overall load growth rates, yet increasing growth in their peak demand. New sources of load, notably EVs, are expected to reverse the trend toward decreasing electricity demand growth over the coming years. This new load growth will be variable and often concentrated in specific areas, providing an advantage for more flexible NWA-type solutions.   
  • Reliability: Improving reliability is a particular concern for commercial and industrial (C&I) customers, which often place a premium on reliability as they risk significant financial losses from an outage. Utilities are increasingly focused on improving reliability in the face of competition from third-party energy service providers targeting C&I customers. Furthermore, the overall resilience of the grid is becoming a greater focal point for governments and regulators in the face of both natural disasters and physical and cyber security threats. The diversification and expansion of the grid can reduce the potential effects of these events.

Building new T&D infrastructure has been the default solution to issues facing the electricity grid for decades. However, there are many challenges to upgrading grid infrastructure, particularly large-scale transmission projects. These challenges include concerns from local communities, the time required to develop and build projects, uncertainty around future load growth and demand patterns, and the rising costs to build new infrastructure in both urban and remote areas. Given these challenges, the falling costs of energy storage and DER technologies are presenting an increasingly economical alternative to conventional T&D projects.

Innovations in grid management and DER technologies have presented a new set of possibilities to maximise the use of existing grid infrastructure and defer or entirely avoid costly upgrades. At the same time, many utilities are seeking to engage customers and provide more value-added services in response to growing competition. Creative solutions to address infrastructure needs at a lower cost with greater customer and environmental benefits, known as NWAs, are being tested around the world.

Navigant Research defines an NWA as:

“An electricity grid investment or project that uses non-traditional T&D solutions, such as distributed generation, energy storage, energy efficiency, demand response (DR), and grid software and controls, to defer or replace the need for specific equipment upgrades, such as T&D lines or transformers, by reducing load at a substation or circuit level.”

Overall, the major advantage is the greater flexibility provided by NWAs compared to traditional investments. A DER-based approach to meeting load growth can more closely match actual conditions on the grid without unnecessary investments. The graphic below illustrates how a DER approach can better match growing demand and defer a much larger investment.

Driving Growth

Although there is a wide range of specific factors leading to the development of NWA projects, there are five primary drivers in the market which also represent some of the fundamental changes underpinning the shifts in this industry and the challenges to the traditional utility business model. These drivers include:

  • Regulatory policies: Regulations and policies can provide incentives to utilities to implement more NWAs, such as allowing the sharing of economic benefits between customers and shareholders rather than all savings going to customers. Many of these policies are designed to reduce the environmental impact of electricity generation and usage by limiting the need for new power plants and T&D infrastructure.
  • Economics: By far the most significant economic benefit of an NWA is the deferral benefit of the large capital investment. Traditional T&D upgrades have risen in cost and complexity in recent years, while DER technologies and grid management software and communications have seen dramatic price decreases.
  • Utility customer engagement: Faced with competition from customer-owned DER technologies and third-party energy service providers, utilities are working to offer new solutions and improve customer engagement.
  • Load growth uncertainty: Short-term investments in NWAs can defer much larger infrastructure investments, giving a utility time to assess whether the infrastructure investment is truly required and to investigate other potential options.

To date, most NWA projects developed have been in the US and the list of projects is expected to grow quickly. New York utility Consolidated Edison (Con Edison) was one of the early pioneers of NWA strategies. The utility began geographically targeting energy efficiency investments in 2003 when growing demand caused several distribution networks to approach peak capacity. These efforts evolved into the well-known Brooklyn Queens Demand Management Programme (BQDM). This programme intends to use many forms of DER to defer or avoid costly T&D infrastructure projects, specifically a new US$1 billion substation for the Brooklyn/Queens area, a region expected to see significant demand growth. The BQDM programme is expected to spend US$200 million on demand-side load management (DSM) programmes to shed 52MW of load – 41MW from the customer side and 11MW from non-traditional, utility-side measures. Figure 2 illustrates the anticipated resource portfolio of the programme in 2018, highlighting the diversity of DER being utilised. 

On the West Coast of the US, two of the largest grid operators and electricity providers, Bonneville Power Administration (BPA) and Pacific Gas & Electric (PG&E), are also exploring NWAs. While BPA has been evaluating NWA options for many years, its first commercial project was announced in May 2017, aiming to avoid replacing a large and expensive transmission line in Oregon and Washington. After almost 10 years of planning the upgrade with strong public opposition and increasing project costs, BPA decided instead to implement various NWA options, including energy efficiency, DR, rooftop solar and possibly energy storage to avoid the large transmission system investment. PG&E in California has also been experimenting with NWAs for many years, with a focus on targeted DSM efforts. Using DSM to defer investments in T&D capacity frees up constrained capital to fund other, more valuable projects for its system. Furthermore, PG&E believes that engagement with a DSM programme significantly increases customer satisfaction.

Part 2 of this technical paper, originally published in ‘Storage & Smart Power’ – a dedicated, Energy-Storage.News-curated section of the quarterly journal PV Tech Power (Vol.13) – will feature on the site later this week.  

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Jigar Shah: On green money and the freedom to invest, Part 2.

We continue with the second part of our feature interview with clean energy entrepreneur and financier Jigar Shah of Generate Capital. We’ve just left off discussing the risk profile of various investors and how the industry is gradually drawing attention from more traditional sources of capital, from the early adopter-venture capital mentality we have seen to date.

‘Energy as infrastructure’

The point is that oil and gas, while risky, can make 25% returns; wind and solar typically create closer to 6% to 10% returns, on the proverbial good day. Investing in renewables, Shah says, is closer to infrastructure investing – “if they buy an airport, they might get a 6% to 10% return” – than it is to the traditional fossil fuel market gamble. The money institutional investors would put into wind, solar or latterly energy storage projects therefore would probably not therefore represent a divestment and would come from separate funds to those oil and gas holdings, Shah argues. As he showed through years of reinventing solar finance, however, it’s still all about scaling up.

“The big thing for these institutions is that they can’t dive in to deals unless it’s a large cheque. So if someone comes to them with a US$25 million opportunity in battery storage, they just can’t do a US$25m deal. They really need to put their money out the door in larger quantities. So if they’re going to do deals directly, they’ll do solar and wind where they might be able to do a US$100 million deal, so they’re not going to smaller deals directly. So I don’t think it’s about risk as much as it is about comfort, and size.”

Shah remains passionate about solar. He says Generate is one of very few financiers investing in community solar, a state of affairs that he says he finds “weird”.

“Every community solar deal today has been forced to find insti­tutional off-takers. Why don’t you get Walmart, or this local school district to actually buy the power? Well, because those guys are not the ones the community solar statute was written for. Something as simple as that was basically blacklisted by the entire finance industry, and it wasn’t until we started coming in and funding it that people started opening their eyes.”

While there is some risk associated with low income customers and residential renters who may not live in one place for the long haul, this calculable risk can be built into the business proposition. Of course, in energy storage, the long-term value of a deal can be harder to figure out.

“It’s about figuring out what we can charge for,” Shah explains. “It’s saying, ‘What benefits will the industrial customer, or commercial customer pay for?’ Will they pay for it as a fixed payment because they believe it’s real and will occur every month? Or are they paying for it on a performance basis, where they say, prove to me at the end of the month that you’ll save me demand charges and then I’ll pay you 80% of what you show me.

“Those are two different risk profiles. In one case they’ve agreed that it works and they’re just paying us a fixed payment every month. In another application, like if the software fails to operate correctly, then we don’t get paid.”

Separate to that risk, Shah says, is regulatory risk. Many markets do not yet value the services batteries can provide, meaning that even where the demand exists, the regulatory space is yet to catch up.

Modelling the risk

Evaluating and finding ways around these risks is tricky. UK transmis­sion network operator National Grid recently said developers should not bank on revenues from providing frequency regulation services and should find ways to ‘stack’ multiple revenues for providing differ­ent services, behind and in front of the meter.

“If someone calls us up now and says they’ve included X number of dollars for grid services, we’re going to say ‘wait a second, we don’t think you’re going to get them until 2019 or 2020, and when you do get them it’s going to be this amount, not that amount’. We’re not miracle workers. We can’t just assume that these revenues are going to magically appear.

“You have to be able to model it. You certainly can get frequency regulation revenues for two years and those are pretty lucrative and could give you almost half your money back, which is great, or more. But then the question is what do you do next? What markets do you participate in next? And you just have to keep revenue stacking and modelling it.

“The other alternative with battery storage is that you could also potentially afford to just pick it up and move it! You could say for two years I’ll get this revenue and then move it to another place. So I certainly believe there is a rational way to finance projects with short-term revenues – but then the returns have to be similar to independent power producer returns, which are more in the 20% range.”

2018: The year utilities break through?

Asked what next year might hold, Shah’s answer is perhaps surpris­ingly downbeat, although laced with his usual fighting spirit. Utilities are quickly becoming wise to the value of energy storage, Shah says. It took many North American utilities several years of the solar market boom to realise they could not ignore it and hope it would go away. Nowadays utilities are presenting a multitude of approach­es to encouraging, accommodating or in some cases even pushing aside PV. Some utilities are now keen to own solar assets. Jigar Shah is expecting to see a similar dynamic in energy storage next year.

“Energy storage has broken through such that utilities [in the US] admit that their value is very high, at least to a 3.5% penetration. The fight now is really about who owns the storage – I am inclined to believe that the utility companies will win that battle,” Shah says.

“They will make sure that private owners of batteries don’t get paid a fair return – similar to what has happened to the demand response markets.”

While Shah thinks utilities will not be able to achieve a takeover of the market in 2018, they will “all decide that is the strategy”, he says. Yet he is not defeatist. I ask if that means it will be harder for the likes of Generate to keep making plays for the projects and technologies it wants to.

“It means that we have to innovate on our side to be able to continue to put our money to work,” he says.

Read Part 1 of this interview, which was published earlier this week on Energy-Storage.News, here.

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Jigar Shah: On green money and the freedom to invest

At Energy-Storage.News, we have seen the industry rise and rise, driven on by specific geographies and higher-value applications. Analysts tracking energy storage, such as Mercom Capital, which issues quarterly reports on mergers and acquisitions and venture capital funding, have found significant sums of capital being put forward for new technologies and latterly for project financing, with increasing frequency.

As solar PV went through the learning curve of its boom years, capital first came mostly from private investors and risk-hungry VCs. Only as the market matured did longer-term, institutional investors start to get involved. While the likes of superstar clean-tech VC investor Nancy Pfund have told us that the energy storage space is getting ripe for big money, with institutional investors eyeing opportunities closely, hands have not yet gone into pockets on a grand scale.

In late October 2017, Generate Capital, led by an executive team that includes SunEdison founder Jigar Shah, raised about US$200 million in equity investment, with input from the Alaska Permanent Fund Corp (APFC). Both the sum of money and the fact that a large sum of it was sourced from an institutional investment group – APFC is a sovereign fund for the state of Alaska – are notable. Generate prides itself on finding opportunities across the whole spectrum of clean energy.

While best known for his pioneering work in solar finance, Shah and the Generate board appear just as excited these days about the potential for other technologies too, from batteries to anaerobic digestion, fuel cells for forklifts, to low carbon solutions for purifying drinking water.

Speaking to Shah over the phone, it’s obvious that he relishes what he calls the “complete freedom” to invest where Generate thinks it can make the most impact, be it “water, agriculture, waste, battery storage” or other options.

It’s a question of being trusted to take calculated risks, Shah says, of negotiating a frontier that is littered not just with potentially ‘good’ deals and ‘bad’ deals but more commonly also includes “misunder­stood” technologies or business ideas. He explains that, for example, through the recent history of the energy storage industry, the thought of funding the technology had “traditional finance provid­ers very scared, initially”.

Generate, on the other hand, was experienced with renewables and clean tech and convinced of their potential. This has led to the company “providing a lot of capital” to a series of solar-plus-storage and behind-the-meter energy storage projects already.

For Generate Capital, there will always be a “frontier of deals that are misunderstood”, Shah says.

“That problem will never get solved. There will always be someone that has to go first, or second, or third, in helping a technology that has proven itself on a technology basis but has not proven itself on an institutional infrastructure basis.”

Gradually we have seen banks and other financiers starting to become comfortable with solar PV, especially in North America. Yet according to Shah that reluctance still exists when it comes to more advanced technologies and Generate Capital sees itself as a conduit for cashflow into less traditional areas of clean infrastructure invest­ment.

“Generate is really about serving the market, before sort of the commodity capital sources start streaming in,” he explains. “Once you feel you can get 5% money from Deutsche Bank, Generate is no longer as competitive. Right now, there are a lot of applications of storage that continue to be misunderstood by the broader finance community.”

Examples where the funder stepped in where banks feared to tread have included solar-plus-storage projects, behind-the-meter applications, or even energy storage projects in Ontario planned to mitigate the effects of the Canadian region’s Global Adjustment Charge, payable by electricity ratepayers to finance conservation and demand management programmes.

Institutionalised?

As for the advent of institutional investment in energy storage, there have only been one or two blips on the radar until now. Swiss group SUSI Partners created SUSI Energy Storage Fund, reaching its first closing in April this year at just over US$70 million, with backers including pension funds and insurance companies. While it’s obvious that just as with banks, institutional investors will start to get comfortable with energy storage, Generate’s opportunity to work with the Alaska Permanent Fund’s capital is one of only a handful of other examples.

There has been little pressure on pension funds and others to see energy storage, or even solar-plus-storage as a viable divestment option from fossil fuels. While it might seem also that institutional investors would err on the side of conservatism in deploying their capital, this isn’t necessarily the reason why many haven’t bought into the storage revolution yet.

“[Institutional investors] invest in hedge funds, private equity funds. They invest in a lot of things that you might privately think are risky. The hook at this point is that for many of these companies, or investors, they’re really focused on oil and gas investing. And you know, oil and gas investing has been quite volatile as of late,” Shah says.

Part 2 of this interview, which originally appeared in PV Tech Power, Volume 13, will be published on the site later this week.

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‘Decapitating the duck curve’: NEXTracker CEO Dan Shugar on energy storage

NEXTracker CEO Dan Shugar sat down to talk to Energy-Storage.News about developing – and selling – energy storage systems in lithium and flow battery ‘flavours’ alongside his company’s market-leading PV tracker systems.

So I guess the most obvious first question would be: Why buy energy storage from a PV tracker company?

Well, we’re a power systems company and a global manufacturer and we’re here to look into customer needs and problems and solve them, not push a product. The roots of NEXTracker go back years. Most of the executive staff has been with me for 15-18 years. We think about and understand utility rate structures, long-term warranties, service. So we’re really a systems company and so we have that DNA and we really understand EPCs and we understand service.

For us, it’s really just that the needs now have landed there foursquare [in the] mainstream for the market. It’s the confluence of two things: one has been the dramatically lowered costs for the technology with both our flow and lithium, secondly our spectacular success on the PV side, where we’ve really taken a bite out of the middle of the day power requirements in a lot of our core markets and the tracker is beautiful there. But then you need to keep going, that’s what the storage stuff is all about.

After launching the flow battery product a while back, what was the idea behind adding NX Drive, a lithium battery version, more recently?

The beautiful thing about having both the lithium and flow product is that we cover a very wide range of use cases. With the lithium, the technology favours incredible discharge capability, incredible power density, well-filled supply chain, multiple manufacturers, and it’s the ideal product for short to medium-term or medium duration storage applications.

The flow [battery system] is an extremely long-life product. We have at NEXTracker an outdoor test facility, the Solar Center of Excellence, it’s a three-acre facility and we’ve added a storage test facility there as well.

We ran a global RFP (Request for Proposal) several years ago called ‘Decapitating the Duck’. We were somewhat technology agnostic at that point, we just wanted to understand what was out there. With Avalon specifically we basically had both a baby unit and the production unit out in our field cycling many times every day, with the baby unit we’ve achieved over 9 years of cycling and we haven’t been able to measure any degradation within the measurement area of the equipment. It’s unbelievably stable. We brought a lot of customers out in the field that can look at all the components, look at the data and so forth.

The flow product takes more space than the lithium product but in these fields where we’re doing the solar, our architecture is that we put one at the end of every row with the solar tracker, it’s the natural place to [do that] and it’s DC-coupled, and that provides several advantages to AC-coupling, technically, so that’s a great application for that.

For flow, my view, having been in the energy business for 30 years, is the numbers have always pencilled out well, but it’s been slow to take off.

From your point of view, how have you been able to deliver economies of scale or production in developing these products? And how much of the products’ design has been in-house versus bought-in?

What’s also just very strategic is, between the NX Drive (lithium batteries) and NX Flow (flow battery) products, is that they share a common SCADA, monitoring and control system that’s also shared with our tracker platform. So we have designed and developed electronic control for the tracker and we have hundreds of thousands of them out in the world that are reliably communicating to us. It’s based on the backbone of the wireless mesh network, the same backbone used in utility smart metering. So that’s an extremely reliable platform.

We used that intrinsic platform for our control system and both these battery technologies, employ this control system. It’s backed up by (parent company) Flex’s IP system, the Connected Intelligence system, so that’s the backbone for data security and the integrity of data. But then we had also built a software team, we acquired a machine learning company a few years ago and that company can do predictive diagnostics and create signatures on preventative maintenance and things like that. So we have the whole package, mechanical, electrical, thermal management, fire suppression, the monitoring control and basically, predictive analytics.

We can incorporate the charging algorithms and control strategies, developed by others. There’s a lot of expertise in that, we work with other partners, that have that software for the charging and discharging, for control and tying it to the customer. That piece, we’re working with other partners.

What we have is basically, all of the mechanical, fire suppression, thermal management. We’re monitoring key aspects of the system, of the health of the battery system and those types of things.  

In terms of customer needs, how will they evaluate which solution of the two works best for them?

There’s three scenarios where the lithium thoroughly wins, one where the flow thoroughly wins and then one where it’s a toss-up and we give customers the option. Our focus is really to solve the need for the customer, most affordably – and not to push a product. So we’ll make options available. We have a proven product in both cases and of course we can tailor that product to specific needs, like if they really want battery A versus battery B. For the lithium, that’s fine, we can deal with that, but the nice thing is that you don’t want every project to be customer-engineered and you really want to be able to leverage the broad application and many customers across a single platform. That way you can invest in R&D, in reliability work and those types of things.

That was our strategy with the tracker and we’re doing the same thing with the battery. With the tracker, we were the first ones to introduce the self-powered tracker, independent rows and other features.

We’re just really focused on every single customer engagement to be successful for the customer. That’s all that matters and if you do that everything else takes care of itself. That’s been my operating philosophy throughout my career.

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Your most-read energy storage stories of 2017

Well, we seem to say it at the end of every year, but 2017 seemed a lot busier than 2016, 2016 was busier and more exciting than the year before that, and so on! There have been some hints already on what the industry and its observers expect to see in 2018 and we do not doubt energy storage will continue in its rise to become a flexible cornerstone of the world’s electricity infrastructure.

In the meantime, let’s reflect on the top news stories of last year, as reported by Energy-Storage.News and based on readership statistics from you:

1. Saltwater battery’ maker Aquion Energy back from dead under new ownership

Aquion Energy, one of energy storage’s more intriguing propositions, taking an award-winning, non-toxic, recyclable and novel battery chemistry based on saltwater, was in the early stages of market-seeding and made its first big deployments when it declared for Chapter 11 bankruptcy protection in March.

Somewhat unexpectedly, the company was snapped up by Juline-Titans, a mostly-unknown investment group described as a “majority-American joint venture (JV)”. Of course, lithium-ion and to a lesser extent flow batteries form the vast majority of the world’s stationary energy storage market, but interest in Aquion perhaps demonstrates that the space is constantly looking to move forward.

Published 24 July 2017

2. Tesla 48MWh battery eliminates need to build undersea cable in Massachusetts for up to 22 years

A pretty significant project for a very small community. Energy-Storage.News reported in early November that the island of Nantucket, off the coast of Massachusetts, could save itself the expense and pain of building an undersea cabling network for better connection to the US grid network using a 6MW / 48MWh energy storage system.

Published 8 November 2017

3. Multiple Indian ‘Gigafactories’ expected by 2019

Under the stewardship of prime minister Narendra Modi, India has raced ahead in its solar ambitions, as avid readers of PV Tech in particular will have noted. India Energy Storage Alliance chief Dr Rahul Walawalkar told Energy-Storage.News in July that there is likely to be more, much more, to come in energy storage and the combined solar-plus-storage sector. With the country aiming to support domestic manufacturing and enterprise as well as a clean energy transition, batteries could be churned out of one or more Gigawatt-scale factories before long, Walawalkar said.

Published 12 July 2017

4. Blockchain and batteries will assist German grid operator in integrating renewables

‘Blockchain’ was on everybody’s lips this year as the most-talked about concept in commerce – and steps have begun to bring the distributed ledger technology into energy. Our story on energy storage system provider Sonnen partnering with grid operator TenneT to ‘virtually’ store and share renewable energy across Germany therefore easily made it into the top five stories of the year.

You can read more in-depth about this trial from Sonnen’s head of e-services, Jean-Baptiste Cornefert, along with a discussion of blockchain and energy storage from Younicos CTO Carsten Reincke-Collon, in the latest volume of PV Tech Power, here.

Published 2 May 2017

5. Large-scale dispatchable solar-plus-storage costs could drop below 10 cents per kWh, Eos claims

Another of the non-lithium, non-flow contenders made it into the top 10 news last year, as Eos Energy Storage claimed radical cost-drops for its zinc hybrid cathode batteries when paired with solar PV at utility-scale. Eos said its grid-scale Aurora-branded 1MW / 4MWh systems could be delivered at as much as 40% lower cost than an equivalent lithium system with four hours’ energy storage duration.

Published 7 February 2017

6. Flow batteries leading the way in lithium-free niches

During the course of the year, we revisited this topic several times from different angles and with views from commentators across the industry. Just how bankable are flow batteries and will they – and other new technologies – start to eat into the +95% share of energy storage deployments held by lithium to date? This, the most-read story on the subject, looked at analysis by Navigant Research.

Published 18 September 2017

7. Giant 4,000MWh Li-ion battery storage facility proposed for 800MW PV farm in Queensland

On some level, it almost doesn’t seem relevant whether or not a project is the biggest such project in the world of its type, at any given time in an industry gathering pace and scale as quickly as energy storage is. But let’s face it, it’s often a quick way to ignite interest when the world sees how quickly the size and scale of projects increases – something we’ve seen time and again in solar PV. A report on a planned mammoth project in Australia, one of several announced this year, made it into our top 10 for 2017.

Published 20 April 2017

8. Tesla launches first aggregated ‘virtual power plant’ in US

If blockchain was this year’s big buzzword in technology, the ‘virtual power plant’ is another big concept not long ago thought to be well ahead of its time, too. Technology providers have been touting their ability to aggregate the capabilities of behind-the-meter energy storage systems to create larger network assets, for some time. This was the first instance Tesla Powerwalls were interconnected by a Vermont utility to create a “single resource of shared energy”.

Published 16 May 2017

9. SDG&E and Sumitomo unveil largest vanadium redox flow battery in the US

Sumitomo Electric, a division of the Japanese conglomerate Sumitomo, which has already installed a 60MWh flow battery system for renewable energy integration in its homeland also executed the largest US redox flow energy storage system to date this year. Delivered for California utility San Diego Gas and Electric (SDG&E), which will trial the voltage frequency control, power outage support and the shifting energy demand capabilities of the battery. At ‘just’ 2MW / 8MWh it is perhaps a drop in the ocean in the long run, but for now, it’s the biggest known system of its type in the US.

Published 17 March 2017

10. PJM’s frequency regulation rule changes causing ‘significant and detrimental harm’

Your final selection for the top 10 sounded a cautionary note. US regional transmission network operator PJM Interconnection, which was one of the first such organisations in the world to allow fast-acting batteries to compete with conventional assets to provide frequency regulation to the grid, changed its rules for participation.

The changes are a little complicated, so we’d recommend you read the story in full but in a nutshell, the national Energy Storage Association argued that storage resources are now being ordered to draw power from the grid for prolonged periods of time, which ESA argues is inconsistent with the resources’ original design and operational parameters.

Published 18 April 2017

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Navigant on energy storage as ‘non-wires’ alternative for utilities and grid operators

One of the ‘value of energy storage’ questions that was being asked a lot two or three years ago was around the use of batteries and decentralised system architecture instead of traditional “poles and wires” grid networks.

It has been said for some time that spending huge sums of money on transmission and distribution (T&D) architecture buildout and upgrades could, in some cases, be deferred by the use of strategically-located energy storage systems, coupled with distributed energy resources like solar and wind.

However, aside from a handful of case studies and real-world examples, this potentially game-changing rethink of grid network planning has largely been less of a priority as a driver for energy storage deployments than might have been expected. Navigant Research’s recent ‘Energy Storage for Transmission and Distribution Deferral’ report sought to fill the knowledge gap.

Andy Colthorpe took the opportunity to ask the report’s lead author Alex Eller, a research analyst interested in areas including energy storage, distributed renewables and microgrids, three of the most burning questions he could think of.

The use of energy storage in T&D spending referral has been long talked about – but until now it has been rare to see figures put on it, or accurate cost-benefit comparisons made. Why is that and is this now changing?

Much of the challenge when considering T&D deferral projects is that the specific economics of each project can be very different. The costs and time required to build new T&D systems, peak to average demand ratios, projected load growth, and availability of capital are all key considerations for new T&D projects or using storage to defer them. Due to the multitude of different factors involved, it has been very time consuming for storage developers to evaluate individual opportunities to defer T&D investments. 

Now that storage costs have come down and the industry is maturing, utilities are much more familiar with the technology and are identifying opportunities to defer upgrades using storage themselves. Furthermore, developers have gained sufficient experience to be able to streamline their process for working with utilities to evaluate these opportunities and propose solutions.

Could you offer examples of why a regulator, utility, transmission or distribution grid operator might recognise energy storage as a cheaper alternative from a technical standpoint – and explain what the drivers might be for doing so?

[Broadly speaking] there are seven main criteria that we identified in the report that will determine the viability of energy storage to defer T&D investments:

  1. High T&D upgrade costs
  2. High peak-to-average demand ratio; a shorter peak demand period only needs a shorter duration ESS, which may have considerably lower costs
  3. Modest projected load growth rate over the coming years – a relatively small storage system could be used to meet peak demand rather than a large capacity increase through traditional T&D.
  4. Uncertainty regarding the timing or likelihood of major load additions. [Energy] storage can be added incrementally as needed, unlike large infrastructure upgrades.
  5. Delays in T&D construction or construction resource constraints. There can also be local community opposition to new power lines and infrastructure.
  6. Limited capital available for T&D projects that must compete with other important investments
  7. An energy storage system (ESS) used for T&D deferral will be able to provide additional benefits or avoided costs, such as frequency regulation, renewable energy ramping/smoothing or energy shifting.

Will we see examples of behind-the-meter assets being used to provide what are more traditionally considered front-of-meter services, to benefit networks and reduce the required spend on T&D infrastructure?

Yes, we expect to see more projects utilising behind-the-meter (BTM) assets as part of “non-wires alternative” projects for utilities and/or grid operators. 

However, there are challenges in coordinating the operation and ensuring the reliability when using a network of hundreds or even thousands of BTM assets. As aggregation and management software continue to improve, this will become a more reliable form of load reduction and will be utilised more by utilities. 

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How Tesla and Vivint are taking different paths to the ‘one stop shop’ destination

What does it mean to be all things to all people? Does it overstretch resources to breaking point, or does it give you a chance to cast a wider net and capture market share, if your core offering gradually expands to encompass almost every available product and service in your chosen sector?

When Tesla ‘merged’ with (i.e. bought out) SolarCity in late 2016, consensus was that it created a clean energy behemoth of the likes never seen before. The longstanding close relationship between the two entities was obviously already in evidence, from the makeup of the executive board including Elon Musk in top roles at both (CEO and chairman of the board respectively), to SolarCity’s immediate enthusiasm for Tesla’s Powerwalls on their launch in May 2015.

Having now taken ownership of the US’ biggest residential solar PV installer and begun the softly-softly launch of its solar roof tiles, not to mention expectations placed on the PV module Gigafactory 2 in Buffalo, New York, it could be argued that Tesla’s not-so-subtle play for market domination now encompasses so much of the distributed energy system architecture that the company is a “one-stop-shop” for home clean energy solutions.

The appeal of the “affordable” Model 3, new strategies for selling stationary energy storage including virtual power plants and no-money-down options, not to mention the pair’s large-scale dispatchable solar-plus-storage projects in Hawaii and American Samoa mean that, as predicted by analysts at the time of the merger, Tesla-SolarCity is well-placed to address individuals’ and businesses’ distributed energy needs across a plethora of technologies.

Meanwhile Vivint, also in the top three of residential solar installers in the US, launched its first ever “Fully Integrated Solar” solution in September. Following tie-ups with smart meter and thermostat makers, Vivint’s rooftop solar projects can now be sold alongside EV chargers from ChargePoint and home batteries, for which Vivint is partnered with Mercedes-Benz Energy. CEO David Bywater claimed this made Vivint the first residential solar “one stop shop” for customers.    

Both of these providers have created “one-stop-shop” or “all-in-one” solutions. So, which is likely to prove the more successful strategy? Will it be the extended value proposition of bundling products and services from all the partnerships taken on by Vivint, or do the acquisitions and new product lines coming from in-house at Tesla-SolarCity represent the simplest and quickest way to scale up an all-in-one offering?

“It makes sense to compare this [Vivint’s launch] to the Tesla-SolarCity merger because it’s pretty clear that Tesla’s long-term strategy is to become a “one-stop energy shop”. So an ideal customer for them would be someone who would buy EV, solar and also energy storage,” Brett Simon, energy storage analyst at GTM Research, says.

“It looks to be that Vivint is pursuing a similar strategy. The advantage there is that you [can] either a) have a customer who loves everything, buys everything and you get a big sale upfront, or b) they buy one thing and you can create an existing customer relationship and down the road potentially upsell them on an additional product.”

Partnerships versus in-house vertical integration

“The advantage of vertical integration is that you can have much more certainty in supply and whatnot, but on Vivint’s side the advantage of not necessarily having a specific house model and in-house manufacturing for storage is that they could really go with anyone as the market matures,” Simon says.

According to Simon, the selection of Mercedes-Benz as Vivint’s partner is an interesting one. The luxury car brand enjoys unparalleled brand recognition – albeit for its (non-electric) cars rather than for clean energy. The German company’s “reputation for making high-end products that perform reliably” is an important cornerstone to the installer’s strategy, giving Vivint credibility in a new and unfamiliar market.

“One of the big challenges for Tesla is that they are betting very heavily on some newer products that haven’t necessarily made as big a splash in the market, whereas for someone like Vivint to come at it the way they are – they are trying to think strategically about how they want to move into this market, how they want to add storage as a piece of their overall solar offering.”

Solar as a gateway to DERs

Part of the advantage of selling a holistic solution could be that while the value proposition for solar remains excellent in many parts of the US for homeowners, energy storage, despite rapidly falling costs, remains one of the more expensive distributed energy resources (DERs) available on the market.

Ditto EV chargers, but perhaps less so for thermostats, smart meters and other small components. So are Vivint and Tesla-SolarCity using solar as a “Trojan horse”, to get all of these other technologies deployed, so the industry can start building scale on an unprecedented… scale? How much customer ‘pull’ does each component have? According to Simon, it is without doubt that solar will remain the primary focus of each company’s offerings.

“Things like EV chargers and storage are more of an add-on. So the ideal customer would purchase everything, but I would say that most customers that they’re getting are still, for the foreseeable future, drawn by the solar piece of the equation and then might be saying, ‘Hey, I’m also planning to get an EV, so why don’t I add the EV charger’, or ‘I’m in an area where there are time-of-use rates so maybe I want to add the storage on as well’. But I still see solar being the main thrust of this piece and the other parts of this equation as add-ons.”

As for the appeal of solar cross-subsidising more expensive items like batteries, Brett Simon said it is hard to tell to what extent Vivint might be doing this, as pricing has not been disclosed publicly.

“[Whether] some of these companies might try to undercut the cost a little bit to gain market share – I would say that certainly, especially in a market like storage that’s trying to get off the ground, to get their name out there, I wouldn’t be surprised if some of the initial system pricing for storage is lower than it should be – from what things like the economics of a full system price would bear out.”

Starting the energy storage market off from a small wedge

Vivint, Tesla and rivals like Sunrun are aggressively pushing residential energy storage forward into the regional markets where it makes the most economic sense. In Sunrun’s case this means a head-on focus on California and Hawaii, two states which combine incentive and support programmes with utility business models that value the benefits of energy storage to integrate solar and shift peaks to match supply with demand.

“With the residential storage market today, it’s still quite small in the US. So even being targeted on Hawaii and California is probably sufficient for the near term, given that those are the two hottest residential storage markets.”

Brett Simon believes that those full-service package offerings will eventually span the US, as battery prices continue to fall and markets and regulation are reconfigured to better accommodate energy storage and other cleantech. Part of this could be the creation of subscription plans, third-party ownership or energy storage-as-a-service business models to match the success of such offerings in the solar PV market.

“I would think that, as there is this shift going on in the solar market, that there would also be this shift overall for the package to have some kind of a monthly payment where at the end of the whole arrangement, the customer would own the system, even if they’re paying in some sort of instalment plan.”

Parallel lines

So two parallel strategies for delivering an “all-in-one” solution. It sounds like a neat way to get energy storage in houses that hadn’t perhaps thought about it before, or a great way for vendors to bundle up their products and those from partners at scale. It could also be a great proposition for their customers. One company in Germany, Beegy, actually offers heat and electricity packages for homeowners on a monthly subscription basis, including PV, batteries and heat pumps, all for less than the price of utility power. Making things easier for the customer and putting the customer experience at the forefront needs to be a key part of this type of ‘holistic’ value proposition.

“When you go shopping, if you have a clothing store you like, you’ll buy your shirt, pants and shoes all from the same store,” GTM’s Brett Simon says.

“You might go to multiple stores to get a better deal, but if you can make as few trips as possible, that’s ideal and companies across the world do this. Again I think this integrated strategy has that advantage that you can build these customer relationships and long-term, continue to sell them products and services – assuming that you can demonstrate value.” 

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