Navigant Research Blog

Has Hitachi Zeroed In On the Most Viable Microgrid Business Model Today?

— September 22, 2016

Energy CloudI had the pleasure of participating in an afternoon workshop at the VERGE conference in Santa Clara, California this week. The workshop covered a lot of ground, including offering two different perspectives on microgrids from two leading players: Spirae, a controls and software innovator, and Hitachi, the only company in the world that has declared it has a 100-year-plan for  “social innovation businesses,” a broad category of solutions that includes microgrids in North America and Asia.

While the workshop covered a lot of ground, perhaps the most noteworthy portion of the program was a presentation by Urs Gisiger, director of project finance for Hitachi Energy Solutions. Gisiger directly addressed questions that seem to be a hot topic of conversation at nearly every event focusing on the hype and promise surrounding microgrids and a distributed energy future: How do we finance such projects at a time of great market uncertainty? In other words, what is the best microgrid business model?

Gisiger set the stage by referring to some recent research performed by Navigant Research, looking at which business models have been deployed in systems in North America in 2015 and 2016. Note from the chart below that if we exclude both remote microgrids and military microgrids—systems with unique investment needs—the overall favorite in terms of business model structure is the power purchase agreement (PPA), representing 45% of total capacity.

Grid-Tied Non-Military Microgrids by Business Model Capacity, North America: 2015-2016

Microgrids Blog

 (Source: Navigant Research)

Of course, a PPA can be financed in several different ways, and this is where Hitachi has really done its homework. In the process, it is shedding light on the part of the microgrid finance supply chain that up until this point in time has largely been in the shadows.

Project Financing

For example, Gisiger revealed 20 banks that will do project finance for energy infrastructure today, including microgrids. In addition, he provided a much longer list of 60 banks, the majority of which are selective in their power project financing, that conceivably also loan money for microgrid projects in North America. “In addition, debt funds and insurance companies are also entering the microgrid market,” he said. He also noted that unregulated arms of utilities are also entering the microgrid financing space in North America, a small group creeping up toward 10 at present.

Despite this good news, Gisiger also offered a sobering portrait of financing options, with the majority—including individual project finance and corporate loans—not leading to satisfactory results for either project developer or project owner (or both) today due to high transaction costs. A revolving line of credit for a fleet of projects looks much more promising, since it allows for greater scale.

As an intermediate step to move forward as financiers become more comfortable with the risk profile of microgrids, Gisiger singled out a lease facility arrangement based on full recourse financing on a corporate balance sheet; a line of credit is taken out so no upfront equity is required. The bundling of projects into a portfolio is key to achieve critical mass. This approach results in better overall project economics since portfolio sale proceeds stay with the developer, while significantly trimming overall bank, legal, and advisor fees.

Needless to say, microgrids will never be a one-size-fits-all solution. While utility deployments of microgrids are increasing, it is still third-party microgrids that are plowing new ground, especially in terms of financial innovation, with Hitachi among the leaders.

 

Plug-and-Play Microgrids, Here and Now

— September 22, 2016

Power Line Test EquipmentOne of the primary challenges facing the microgrid market today is the perception that each project is unique and therefore requires significant customized engineering. In fact, dozens of microgrids never seem to make it past the feasibility analysis phase due in part to this predicament.

While it is true that very few microgrids are exactly alike and therefore the idea of cookie-cutter configurations seems next to impossible, there are vendors now offering products and services that are moving the market much closer to a plug-and-play paradigm.

Case in point: Tecogen. The company manufacturers the InVerde, a small natural gas engine often deployed as a modular 100 kW combined heat and power (CHP) unit that comes embedded with the Consortium for Electric Reliability Technology Solutions (CERTS) islanding software. String a few of these CHP units together (as the Sacramento Municipal Utility District has done) and presto—you now have a simple microgrid. The inverter that comes with the InVerde technology enables islanding and can support multiple generators on the same microgrid, each one acting autonomously to maintain power quality by responding to load changes, managing voltage sag, and regulating current.

Energy Ecosystem

Navigant Research does not consider a single InVerde unit a microgrid, since it is powering up a single building and is only 100 kW in size. We would instead categorize such systems as nanogrids. However, even multiple InVerde units are not considered microgrids by some entities, among them the New York State Smart Grid Consortium. Regardless of what one calls such systems, nanogrid, microgrid, or whatever else, they do represent part of a new Energy Cloud 2.0 distributed energy resource (DER) ecosystem.

The argument that Tecogen is not a microgrid market maker is being challenged by a new product offering, the InVerde e+, which allows for the integration of both energy storage and solar PV (or small wind) into a single controllable entity by virtue of direct current (DC) bus. With this recent upgrade, Tecogen’s claim to enabling truly plug-and-play microgrids seems quite valid—and even more compelling.

In the United States, CHP (and the ability to create thermal energy) is key to the economic value proposition for microgrids. In fact, the ideal resource mix for a microgrid in the United States today is CHP, solar PV, and a lithium ion battery. If sized strategically, this microgrid configuration can be cheaper than utility costs in California and much of the East Coast today.

Tecogen’s InVerde units boast an impressive list of features, among them emissions equivalent to that of a fuel cell, 33% electrical efficiency (and 81% total energy efficiency), and the lowest installation costs of any comparable technology in its class. The biggest surprise? The cost of microgrid controls—embedded in each CHP unit—is zero.

Marketplace Gains

Even before the recent new offering, Tecogen had made impressive gains in the marketplace. It ranked fourth in terms of total installed microgrid projects globally in the latest version of Navigant Research’s Microgrid Deployment Tracker. In last year’s Leaderboard report ranking microgrid developers/integrators that offered their own controls platform, the company ranked fifth.

Tecogen is not the only vendor moving the market toward plug-and-play and interoperability. Spirae and Blue Pillar have made important strides in this direction from an independent controls perspective. In addition, Duke Energy’s Coalition of the Willing is also moving forward to develop a common interoperability framework for microgrids, focused on so-called Open Field Message Bus (Open FMB) communication standards.

 

Energy Cloud 2.0: Orchestrating Power Networks via Virtual Power Plants

— August 30, 2016

AnalyticsThe evolution of energy markets is accelerating in the direction of a greater reliance upon distributed energy resources (DER), whether those resources generate, consume, or store electricity. The new frameworks necessary to manage this increasing two-way complexity are quickly evolving. Nevertheless, strategies are being deployed today all over the globe.

One such strategy is a virtual power plant (VPP), the concept that intelligent aggregation of DER can provide the same essential services as a traditional 24/7 centralized power plant. The definition of a VPP is fuzzy. In short, it is based on the idea that the value of DER must not only provide value to the prosumer, but must also be enabled (through technology and regulation) in order to migrate value upstream to utilities and even transmission grid operators. In other words, they need to rely upon a network orchestrator, a concept that is articulated in a new white paper entitled Navigating the Energy Transformation.

Gaining Acceptance

Navigant Research published its first VPP report in 2010. Since that time, what was once seen as a futuristic scenario fed by a number of experimental pilot projects in Germany, Denmark, and the rest of Europe is emerging into a real market that draws upon analogies with companies such as Uber. The network orchestrator driving value for the VPP may not own all of the assets; value is created by organizing these assets in a way that creates real-time physical benefits to the power grid (or in the case of Uber, to people seeking near-immediate transportation services).

VPPs represent an Internet of Things (IoT) approach to energy management, tapping existing grid networks to tailor electricity supply and demand services for a customer, utility, or grid operator. VPPs maximize value for both the end user/asset owner and the distribution utility through software and IT innovations. The primary goal of a VPP is to achieve the greatest possible profit (or savings) for asset owners, while at the same time maintaining the proper balance of the electricity grid at the lowest possible economic and environmental cost. From the outside, the VPP looks like a single power production facility that publishes one schedule of operation and can be optimized from a single remote site. From the inside, the VPP can combine a rich diversity of independent resources into a network via sophisticated planning, scheduling, and bidding of DER-based services.

A Transforming Field

Perhaps the most transformative example of a VPP is the aggregating up of residential rooftop solar PV systems with distributed energy storage, which can then deliver dispatchable demand response (DR) services to utilities. A great example of this VPP model comes from the Sacramento Municipal Utility District.

Navigant’s recently released white paper concludes that roughly $10 trillion can be attributed to the digital innovations necessary to integrate renewables, which will represent the vast majority of new power supplies supporting the grid by 2030. A report to be published this September will carve out how large the VPP market is expected to be over the next decade. Regardless of the precise figures included in these forecasts, revenue across the electricity value chain is shifting downstream toward the edge of the grid.

Without VPPs, this shift could result in chaos. With emerging business models such as VPPs, however, a balancing of the grid can occur that also balances costs and benefits, ideally in a way that serves a broad array of society’s stakeholders.

 

Resilience Movement Hits the West Coast

— August 1, 2016

GeneratorThe focus of state programs designed to boost resilience have been microgrid and nanogrid projects on the East Coast launched in response to extreme weather events such as Hurricanes Irene and Sandy. Since 2011, a parade of states have launched state-funded programs: Connecticut; Maryland, Massachusetts; New Jersey; New York, Rhode Island, and Washington, D.C., among others. A quick glance at some statistics underscores why governments see value in public investments to improve the resilience of regional power grids.

Since 1980, the United States has sustained more than 144 weather disasters with damages reaching or exceeding $1 billion each. The total cost of these 144 events exceeds $1 trillion, according to the U.S. Department of Commerce. According to the president’s U.S. Council of Economic Advisers and the U.S. Department of Energy (DOE), severe weather-related electricity outages cost the U.S. economy more than $336 billion dollars between 2003 and 2012.

Resilience in San Francisco

The perception that this resilience movement is an East Coast phenomenon is being challenged by a program launched in San Francisco. Rather than being focused on threats that can be anticipated via new weather forecasting techniques, the program is focused on a threat somewhat confined to the West Coast: earthquakes.

What would happen to the electricity and natural gas infrastructure of San Francisco if an earthquake equivalent to the 1906 event occurred today? A project developed by the City and County of San Francisco’s Department of the Environment looked into that question. Entitled the Solar+Storage for Resiliency project, the early results of modeling are quite sobering. While 96% of the city’s consumers could expect their electricity to be back online within 1 week, it would take as long as 6 months for the natural gas infrastructure to be fully operational. (To get back to full-scale provision of electricity would take 1 month.)

Reports from Connecticut showed that natural gas continued to flow through extreme weather, hence its focus on fuel cells and fossil fuel generation as the cornerstone of its efforts toward resilience. San Francisco is taking a different approach, focusing instead on distributed solar PV linked to advanced batteries while incorporating existing diesel generators into the solution mix.

After an extensive and interactive mapping exercise located critical facilities throughout San Francisco, sites were analyzed for available rooftop space for solar PV and the logistics of installing batteries. Projects that could be installed under existing regulatory restrictions were also prioritized. The end result is roughly a dozen projects scattered throughout the city that would offer resilience in the most sustainable manner possible using current technology. So far, funding for initial groundwork for this microgrid portfolio has come from a $1.2 million grant from the U.S. DOE’s SunShot initiative.

Emergency Response Programs Lead to Economic Opportunity

Though a common perception is that diesel generation is the most reliable backup power supply, reports from the field beg to differ, as failure rates can be extremely high. The vulnerability of San Francisco’s natural gas infrastructure also required a different approach. Given recent advances in smart inverters capable of safe islanding and the declining costs of energy storage, it appears that the San Francisco approach is not only uniquely qualified to address the unpredictability of earthquakes—but also represents a more sustainable and climate-friendly approach to community resilience.

So far, vendors such as SMA, Tesla, and Saft have been involved in the modeling of these systems to be installed in the coming years. While a program with the noble goal of emergency response, the community resilience microgrid market also represents an economic opportunity. Under a base scenario, the market is projected to reach $1.4 billion globally by 2024.

 

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