Category: Blogs

How the deal came together: Convergent CEO Johannes Ritterhausen

Following on from our look at some of the takeovers of promising or already-prolific energy storage companies in the last edition of PV Tech Power, which included Wartsila’s acquisition of Greensmith Energy, Aggreko’s purchase of Younicos and Shell’s swoop for Sonnen, here’s an exclusive interview with Convergent Energy + Power CEO Johannes Ritterhausen.

We reported last week that the developer, active across North America, has been acquired by private equity and credit investor Energy Capital Partners. ECP has some US$19 billion of assets in its portfolio across everything from oil and gas platforms to residential solar companies like Sungevity and Sunnova, the latter of which has incidentally just filed for its own forthcoming IPO.

Convergent meanwhile, finds its sweet spot in the ‘mid-market’, CEO Ritterhausen said, developing energy storage projects in the commercial space worth around US$2 million to US$25 million each, with around 50% in Ontario’s booming commercial and industry and the rest in various territories of the US. 

In terms of individual projects, Convergent may not be the biggest (although the company has deployed Ontario’s largest C&I ESS to date, at 20MWh), but there have been many announcements of new projects and financing. How is Convergent getting its projects into the ground and getting customers signed up?

Johannes Ritterhausen, CEO, Convergent Energy + Power: While we would consider some of those big huge projects that are about 6% cost of capital and [require] enormous synergies and very high development cost on land and interconnection, we can’t compete with the NextEras and First Solars of this world, that’s not our game.

We offer our projects primarily as a contract, we put in the upfront capital and sign a long-term agreement, everything from five to 20-year customer contracts in our portfolio.

What’s the value of acquiring Convergent going to be for ECP? With US$70 million put into more than 120MW / 240MWh of energy storage assets so far (70MW operational), what are some of the higher value applications for that and what were your investors most interested in?

JR: We do large industrial systems and smaller distribution connected systems for utilities. The primary applications are demand charge and electricity procurement costs savings that are based on higher peak rates, for large loads and for utilities, its infrastructure [spending] deferral. So, we’re seeing quite a large market on the industrial side, obviously in Ontario but also now in regions throughout the States.

There’s an enormous amount of customers that pay high demand charges, have large loads, and the growth potential is huge here, especially if the costs continue to go down rapidly. We’re seeing there are opportunities in all of those opening up in North America.

On the utility side, pretty much all of them have some non-wires alternatives (NWAs), it’s just a matter of how far along in their thought processes they are in using distributed energy resources (DERs) to address those problems.

The unique thing we bring to the table is really around managing the whole development cycle. You’re understanding a customer’s particular needs, their particular demand charges. You can have customers in the same utility area, right next to each other, that are paying different rates.

There’s a lot of customisation in the lead generation and customer engagement process. Then, obviously you have to design a solution with the customer effectively, be very responsive to that customer’s need and then we offer financing – it’s a shared savings type contract so the customer doesn’t take the risk.

When they sign that contract with us, we’re still there on the other side. We’re not flipping that project to a bank, or selling that project – we’re still there, it’s our equity, our risk. They will be working with us for a long time and we manage the asset.

A lot of the value of energy storage technology is just beginning to be realised, while we wouldn’t expect you to reveal numbers at this stage, can you give us an idea of the expectations that ECP might have?

JR: As you know, energy storage is a dispatched asset, if you don’t turn it on and off at the right time, it’s a paperweight. So, we’re there, managing the operations and the assets and that’s value for the long term. So that integrated value proposition is what ECP is investing in. We put the deal on the board and then we stay there for the process, creating value for the long term.

We think that’s the right model in this early stage. Five to 10 years from now, pieces of that will get commoditised, just like in solar or anything else. But right now, to be integrated is extremely important to project success.

What I can tell you on the numbers front is that this is a relatively small transaction for ECP. They’re a multi-billion dollar fund. Last year they took Calpine private. Buying a 70MW operating pipeline and then a bunch of future prospects, is not their typical sized transaction but the reason they did it and spent so much time working on us – this deal took a while to put together – we got engaged with them early last year.

They see exactly what you’re saying, they see that growth, they see the potential to put hundreds of millions of dollars into this company in the next three to five years or whatever the time period is. That’s why they’re investing, because they believe in the growth and they believe they’ll have a place to put that money.

What technologies go into your projects?

JR: We’re a technology-neutral developer. We have everything in our portfolio from six-minute flywheels to six-hour, lead-acid batteries. We didn’t do that, just for that tax break by the way, that’s just how that ended up.

The primary stuff that we’re building now are two- to four-hour lithium-ion batteries, and we typically buy those through large integrators. So we’re not an integrator ourselves, we’ll contract with a GE, an IHI, a Lockheed Martin or Mitsubishi or, whomever the integrator is to put together the AC-DC system and we’re purposing that from the integrator.

We manage the construction typically, so in the EPC equation… we do the C and purchase the E and the P! 

We’re the largest owner-operator of flywheels in the world, by far, we’ve 45MW of flywheels in our portfolio, so we’re very comfortable with that technology.

Do you see a lot of flywheels happening these days? We’ve not reported on many in the past couple of years at all, although we’re aware that the technology has again advanced, with Ambri touting a four-hour duration flywheel recently.

JR: I will never say, no, or claim it would never happen again but I think it’s pretty clear now if you’re building an asset now it’ll be lithium-ion to do frequency regulation. Then again, if you had asked me a couple of years if we would be owning flywheels in our portfolio we’d say no, but here we are, and we love them, they’re great. 

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Corporate takeover: commitment or compromise? Part 2

The growth potential of energy storage has drawn interest from some of the biggest names in the power business and beyond. With the trend set to continue, Andy Colthorpe explores how three recent acquisition targets are faring under new ownership. Taken from the pages of PV Tech Power Vol.19, Part 1 of this article was published on the site last week.

Business models and scalability

Taken at face value, these are acquisitions in the truest sense. Large companies have spotted that rather than force their way up a steep learning curve by trying to do it all themselves in-house, it is better in some cases to acquire expertise and technol­ogy that fits into their plans. Whether that’s today’s plans in the case of Wartsila and Aggreko, or from a longer-term play perspective in the case of Shell and Sonnen. Big players are seeking not only expertise and technology, but those things have to fit into scalable and viable business models.

Aggreko’s Dan Ibbetson, says that post-acquisition, it wants to use Younicos’ decade of experience with battery systems to deliver complete bundled solutions, in this case for commercial and industrial (C&I) customers. He also cites the mining sector, data centres and cheap LNG-powered Caribbean Islands as huge segments of market potential perhaps previously not readily accessible to Younicos. Aggreko’s business model of renting equipment and solutions to customers is a perfect fit for the ‘energy storage as-a-service’ offerings that Younicos was already delivering to its customers, Ibbetson says. It has also enabled Aggreko to tout new product lines including mobile containerised solar-plus-storage, also for rent.

“You come to us, you want energy, we’ll have a discussion about the right mix of solar and thermal and then the kind of batteries that you need to integrate those two and then it’s all in one contract. You don’t have three different suppliers. Then all the kit is designed in a way that it fits really well together.”

The all-in-one rental model can poten­tially work well for both energy system provider and customer. The customer is no longer burdened with a high Capex, while what was formerly known as Younicos is able to leverage the balance sheet of its new parent to execute projects on an ongoing and presumably increasingly ambitious basis. Apricum consultant Florian Mayr cites the example of an energy inten­sive but temporary mining site which might be in operation for less than 10 years. The owners of that site need power, but they don’t need to buy a system.

“Having a storage solution which is more energy as a service and not being sold and needs to be amortised over 20 years but can also be moved to a different mining location, that could help a lot [in persuad­ing customers to try it],” Mayr says.

The role technology plays

A couple of years ago, as the importance of battery and energy management and control software became clear, Younicos, Greensmith and others were selling their software platforms as a kind of side-line to their more complete system integration businesses. For both companies, this has changed, not inspired by their respective takeovers but coinciding with a wider market shift. That shift being a recognition that the system integrators’ core expertise is in delivering a complete, working system.

“I don’t believe that in this industry, there’s a strong case for a software-only business model,” Greensmith alumnus and now Wartsila’s Andy Tang says.

“The biggest challenge you run into as a software-only business is that the solution the customer is looking at is a system: it’s the total thing that’s working and any time there’s any problem, whether it be a hardware or software problem, it’s on the software vendor. A hardware problem shouldn’t be, but because it’s viewed as a system, the hardware problem becomes the responsibility of the software vendor. You don’t really have control over having specified the equipment and if you don’t have control over having the commercial relationship with the hardware equipment provider, you have no leverage to help fix the situation.”

Not only that but with Greensmith’s GEMS software platform, and those made by rivals, if deployed to manage energy storage’s operation and performance at the heart of the energy system, it is better for the software platform to run the overall system itself.

De-emphasising certain aspects of their existing strategies and in Younicos’ case making several pivots over time have been key to the survival of all of the companies pre-acquisition. Tang says that in addition to the decisions around software, Greensmith also had to know not to get too hungry for new projects during the early ‘mini-boom’ in energy storage projects from 2013 to 2015, although the company’s software ended up in around 30% of projects deployed the US that year.

In the meantime Sonnen is given scope to expand the existing base of sales of its systems and subscriptions to its services in Germany, as well as the US and particularly Australia, where the company just prior to acquisition announced the construction of a local factory to enter domestic content eligibility for South Australia’s Home Battery Scheme.

The appeal of the Australian market is something of a no-brainer at the moment, with Sonnen’s German domestic rival Senec also launching its Australian division (with Senec also in post-takeover mode after a 2018 buyout by utility EnBW) this year. But in terms of manufacturing, does the backing of a fossil fuel supermajor give Sonnen aspirations to fully vertically integrate into battery manufacturing as well? While Ostermann says system assembly and manufacturing could continue to be integrated, he is highly doubtful on the latter point.

The core focus is on the battery and energy management and control software and hardware in terms of creating a self-contained home energy system. Then, as the company has shown in becoming the first home storage participant in Germany’s Primary Control Reserve (PCR) ancillary services market, turning that into something that can become part of an orchestra of virtual power plants (VPPs) and communities of energy sharers and traders on the grid. That’s not to say the choice of battery is not important.

“Sonnen decided in the beginning of the company history in 2010 to focus on lithium iron phosphate (LFP) chemistry for two simple reasons: the first is that being a residential player, safety was extremely important for us and LFP is the safest cell chemistry you can find within the lithium-ion cell family, regarding thermal runaway – no smoke, no fire, no explosions, no crazy stuff like that, and that was key for us,” Ostermann says.

“Secondly, lithium iron phosphate has the highest cycle life. Always given that you use a decent quality [cell] of course. This choice has set us a little bit apart from other players in this industry, whereas now we recognise that more and more of our competitors, laughing at us in the past about this choice, are now also orienting themselves toward LFP, which I find interesting!”

Ostermann also says that not using higher energy density nickel manganese cobalt (NMC) cells also frees Sonnen from some of the supply chain issues which struck energy storage companies reliant on the same cells used in electric vehicles last year.

All roads lead to home

There’s an understandable excitement at these previously almost ‘alien’ and futuristic companies being taken over by such significant names, but why these three? And why now? And can being part of a much larger ‘mothership’, as one interviewee described it, bring the scale and reach our industry needs – that our planet needs – to truly play a key role in effecting the global energy transition?

Sonnen’s Christoph Ostermann certainly thinks so. Back when Shell led an invest­ment round in the Bavaria-headquartered start-up in mid-2018, Ostermann told me that the involvement of the world’s major energy companies was a positive for the “clean energy future”, a view that he stands behind even more emphatically since the company became a part of the Royal Dutch Shell Group.

It’s a little surreal to think of a company many of whose employees still live in a renewable energy-powered village in the remote southern German countryside, that touted energy independence from the big utilities as its selling point to many of its customers, is now dependent – in the long-term at least – on the utility ambitions of an oil company. As Ostermann reels off a list of geographies that could open beyond the company’s core territories in Europe, the US and Australia in the near future, it might almost be easier to compile a much shorter list of territories, which the Sonnen CEO does not think will have a residential energy storage market before long.

“Japan is a market we will look into closely in the near future. We’re also looking at other geographies in Asia, such as the Philippines, which we will look at more intensively in the future. There are a couple of countries in Africa, so, just to give some examples, there’s Nigeria or South Africa, where we have preliminary plans to enter these markets. Then you have new markets in Latin America, where we’re looking at the moment. At the end of the day, due to the fact that renewable energy generation is already price competitive all over the world, and storage prices come down more and more, I deeply believe that we will see a lot more geographies in the future that turn out to be residential storage markets.”

Greensmith Energy’s systems on the other hand have been supplied in eight countries to date (80 systems) and Andy Tang predicts that in a year’s time the number of countries will have more than doubled.

“The growth we’re seeing because of Wartsila’s sales organisation selling our energy storage, we expect that to really, really, grow incredibly. Energy storage I think is still in its infancy as a market but I think now is the time to enter these new geographic markets that are opening up,” Tang says.

It isn’t just the geographies; it’s also the range of projects and systems the company is now integrating batteries with that’s increasing. In tandem with that, the number of different applications the systems perform increases and so too does the complexity of managing the entire energy system that is created.

“If you think about how people are beginning to use energy storage, there’s a lot of single-application deployments around the world, where energy storage is thought of as one or two things: peak shifting or smoothing out renewables. A lot of our customers are applying four or five different applications out of our software to get the maximum outcome. Not just from storage, but from software,” Tang says.

Commitments not compromises

Whether their takeovers are judged a success will all come down to the value each of these companies can provide to their new owners, although obviously they will be judged on other metrics too, such as their contribution to decarbonisa­tion. Apricum’s Florian Mayr says that with US$1-2 billion invested per year through Shell’s New Energy Ventures VC wing the company’s “magnitude of investment is too much to be considered ‘greenwash’”. However, to put it in context, Shell is nonetheless spending perhaps tenfold that amount on oil exploration activities still and is “definitely not exiting the oil business today”, Mayr says.

The flexibility energy storage can bring to the renewable energy transition is critical on both an environment and long-term economically sustainable level. Whether that means the continued acquisition of smart new companies or the development of their own products, big players are swooping.

As Mayr says, it’s likely that for costs associated with residential storage to continue falling and “a widespread, globally applied business model” to be feasible a mass market is needed and big balance sheets and a recognition of the need to change will play a big part in that. As the examples of Aggreko and Wartsila also show, albeit from other angles, non-residential storage is also in the sights of those big players. Let’s hope it’s not too bumpy a road.

CASE STUDY: What big players are looking for

Centrica, the global energy giant behind British Gas, launched an innovation fund two years ago, seeking to plough some £100 million in tech start-ups that could help it navigate the energy transition.

In its first two years it has backed the likes of New York-based blockchain start-up LO3, Israeli EV software firm Driivz and a host of other companies operating at the grid edge.

Sam Salisbury, director at Centrica Innovations Labs, says the division starts by being led by a need, indicating that two of Centrica’s present themes are driven by societal issues, namely mobility and ‘active ageing’, or making people feel more comfortable in their homes.

“We try to have a bigger vision of what we’re trying to achieve and then look at who can contribute to that vision and who we can assemble together to create a big solution for our customers,” he says.

Plugging capability gaps with a well-timed, strategic investment stands to be significantly cheaper than ploughing resource into an in-house R&D department like other industries can, and is often the only option in an energy retail sector famed for its slim margins.

But Centrica’s activity is becoming increasingly consumer-led, a notion backed by the company’s work in establishing a peer-to-peer renewable trading network in Cornwall, one of the UK’s most sun-drenched areas, which is to feature a heady mix of solar, various storage technologies and blockchain.

“Certainly my view is we need to find out how to make the homes more self-sufficient… as an energy supplier we have to be developing more solutions for our customers,” Salisbury says.

This section by Liam Stoker, Solar Media’s UK Editor

Part 1 of this article was published on the site last week, here. This article has just appeared in PV Tech Power Vol.19, Solar Media’s quarterly tech journal for the downstream global PV industry, as part of ‘Storage & Smart Power’, a dedicated section commissioned and brought to you by the team here at Download the whole 119-page magazine for free (subscription required).

COVER IMAGE: Aggreko’s history of powering major events and industrial operations around the world using containerised solutions includes sports and stadiums: the LA 2024 Olympic Games are pledged to be carbon neutral. Image: Credit: Flickr/Tony Webster

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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.


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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