Navigant Research Blog

Hydrogen in Microgrids: Diverse Business Models Begin to Emerge

— September 7, 2017

Hydrogen has long held promise as an energy carrier, though electrolyzer and fuel cell technologies have so far not broken into the mass market—largely due to high costs and infrastructure challenges. As those technologies continue to get cheaper and more efficient, they present intriguing possibilities for hydrogen in one unexpected application: microgrids.

Microgrids, whether grid-tied or remote, rely on local power generation. While solar PV, wind, and other renewables capture many headlines, fossil-fueled distributed generation (DG) accounts for more capacity than any other—40% of the total—among the microgrids tracked in Navigant Research’s Microgrid Deployment Tracker 2Q17. Fossil-fueled DG is often selected since it can provide dispatchable power for long periods and can generally store energy-dense fuel onsite. These facts also hold true for hydrogen. For longer duration storage, hydrogen often outperforms batteries by a significant margin without the emissions associated with fossil fuels.

Emerging business models are setting the stage for hydrogen to play multiple and significant roles in microgrids. Some of these business models are briefly described below.

Remote Microgrids: Hydrogen Displacing Diesel

A new Chilean microgrid developed by Enel, with support from Electro Power Systems (EPS), is showing that hydrogen can fill the same role as diesel, but without the emissions associated with the latter. Remote microgrids have historically depended on diesel gensets, often because many days’ worth of fuel can be stored onsite. While batteries are generally too expensive for multiday storage durations, hydrogen tanks can be easily scaled, independent of the peak power demand.

According to EPS, this type of model is quickly becoming commercially viable. Some reasons include capital and operating cost declines, tighter emissions regulations across the globe, and an eagerness to bypass the diesel value chain across hazardous terrain in remote areas.

Microgrids Exporting Hydrogen

The developers of the Stone Edge Farm microgrid in California had a challenge: despite having excess onsite electricity production from PV and other sources, they faced hurdles in exporting that power in an economically viable way. For example, some of the hurdles to exporting into the California Independent System Operator (CAISO) market include reaching the minimum threshold of 0.5 MW and meeting the ISO’s resource implementation requirements, which include building an onsite meteorological station and control platform. Since these presented significant barriers, the developer looked to another product to export from the microgrid: hydrogen. A bank of onsite electrolyzers turns excess electricity into hydrogen, which then fuels the onsite Toyota Mirai fuel cell vehicles and can also feed the microgrid’s fuel cell bank to generate power.

Islands: Hydrogen as Local Energy Commodity

Many islands are dependent on diesel fuel for both transport and electricity, since it has historically been the cheapest large-scale energy carrier available. However, in places like Hawaii, the appeal of hydrogen is growing thanks to concern over climate change and a growing need to store the high output of intermittent renewables—often using power-to-gas schemes (for more information, see Navigant Research’s Power-to-Gas for Renewables Integration report). In addition, the captive nature of the vehicles helps alleviate the infrastructure problem since relatively few stations are needed. ENGIE, a member of the Hydrogen Council, has been bullish on hydrogen as a future fuel. The company is helping to build an island microgrid based around hydrogen technologies near Singapore. More projects are sure to be announced as the technologies continue to improve.

Thanks to cheap renewables and improving electrolysis technology, hydrogen’s outlook is getting better. Due to the challenges with major fueling infrastructure rollouts, Navigant Research anticipates that hydrogen development will be focused in small geographic areas through 2020. Fitting, then, that hydrogen should find a foothold on the small scale of microgrids.

 

Taking VPPs to the Next Level

— June 20, 2017

The primary goal of a virtual power plant (VPP) is to achieve the greatest possible profit for asset owners—such as a resident with rooftop solar PV coupled with batteries—while maintaining the proper balance of the electricity grid at the lowest possible economic and environmental cost.

The purpose is clear, but getting to this nirvana is not easy. Nevertheless, there are clear signs that the VPP market is maturing. New partnerships are pointing the way for control software platforms that can manage distributed energy resources (DER) in creative ways.

Creating a DERMS for Utilities

Case in point: the recent collaboration between Enbala Power Networks and ABB to create a DER management system (DERMS) platform for utilities. Underpinning this foray into smarter DER controls is the following statistic: more distributed generation (DG) will be coming online in 2017 than traditional centralized generation (coal, natural gas, and nuclear power plants). By 2026, 3 times as much DG will be coming online and sending power into the grid than these traditional centralized power plants. That gap will only widen more over time.

Annual Installed Centralized vs. Distributed Power Capacity, World Markets: 2017-2026

(Source: Navigant Research)

The entire ecosystem of DER, including DG, will need to be managed in new ways if value is to be shared between diverse asset owners and the incumbent utility grid. Utilities are slowly coming to see this as an opportunity rather than a threat. Consider these survey results from January of this year, with over 100 utilities responding. 18% of respondents indicated that they already had a DERMS in place, while 77% said they planned to implement their own DERMS program within the next 36 months. These responses show a majority of utilities today anticipate needing to implement DER control solutions in the near future.

There are many innovators in the VPP space, including Enbala. Along with its new partnership with Swiss industrial grid powerhouse ABB, the company’s recent expansion of its controls and optimization architecture leveraging recent advances in machine learning are helping to push the VPP platform into the mainstream. In the process, Enbala is providing metrics that suggest a promising ROI for VPPs.

Cost of Traditional Power Plants versus VPPs

Here’s a quick comparison. According to the US Energy Information Administration, the cost of building a new coal power plant is approximately $3 million/MW. This capital outlay does not consider the risk of future environmental regulation that may occur over the 20- to 30-year life of the project. While the cost of a new natural gas-fired power plant is much less—approximately $900/MW—that cost still represents a potential future liability. In comparison, the cost per megawatt for a VPP that takes advantage of the diverse set of existing DER assets is approximately $80/MW. Furthermore, the investment in the software and supporting IT infrastructure that creates the VPP does not carry either environmental liability or the risk of stranded investment. The VPP value can only increase over time as new markets emerge for grid services.

In the final analysis, VPPs optimized by smart software controls and new innovative business models such as transactive energy are key to realizing a vision of the future that Navigant has deemed as the Energy Cloud. To learn more, check out the new white paper developed by Navigant Research for Enbala and look for details about the forthcoming webinar on August 15.

 

Military Microgrids Could Be a Winner under New Trump Administration

— February 6, 2017

President Donald Trump’s preference for traditional energy fuels such as oil and natural gas—as well as large centralized coal plants—is clear. Yet, recent trends point to rapid growth in small, distributed energy resources (DER). These DER technologies range from rooftop solar PV panels to new kinds of batteries and from wind turbines to fuel cells. They become optimized by IT and software into smart networks such as microgrids and virtual power plants.

Navigant Research estimates that between 2014 and 2023, different forms of distributed generation (DG) will displace the need for more than 320 GW of new large-scale power plants globally. New DG capacity additions are expected to exceed new centralized generation capacity additions by as early as 2018. Nearly $2 billion is forecast to flow into the global market for DER over the next 10 years.

A Revival?

Despite what might seem to be a collision course between shifting US energy priorities and technology trends, there is a market where DER and other Trump priorities align: military microgrids. Don’t forget Trump is also focused on bolstering the US military as part of a strategy to address the threat of terrorism, so funding levels for the federal Department of Defense (DOD) may increase.

Interestingly enough, the nation’s new Secretary of Defense James Mattis has revealed that he is a big fan of microgrids, particularly those that integrate solar PV. Mattis’ point of reference is combat conditions, where high mortality revolved around supplying fossil fuels to combat missions in Iraq and Afghanistan. Also a factor is the value of reducing necessary fuel transport for forward operating bases and portable tactical microgrids. These perspectives could help revive a microgrid segment that has been lagging lately.

Challenges Remain

The combination of tight federal DOD budgets, complicated and bureaucratic procurement protocols, and a market closed to many microgrid innovators all combined to stain what was once seen as one of the best opportunities for microgrid development in the United States. As a result, many leading microgrid vendors that focused on the military segment 5 or 6 years ago turned their sights elsewhere, frustrated by the slow pace of development, complex contracting challenges, and the failure to integrate renewable energy purchasing with onsite base resilience priorities.

Other microgrid market segments, including community resilience and utility distribution microgrids, have received far more attention. Prime reasons being new state programs offering funding (such as in Connecticut) and a growing list of utilities investigating the microgrid opportunity, among them ComEd, Oncor, Duke Energy, and Con Ed. While high profile efforts to reinvent utilities such as New York’s Reforming the Energy Vision (REV) have achieved much attention, they have also been bogged down due to the challenge of negotiating new business models while delivering new kinds of grid services. (The departure of Audrey Zibelman, current chair of the New York Public Service Commission, for a new position as CEO of the Australia Energy Market Operator now raises questions about the prospects of such community-utility microgrid partnerships, as well.)

The Promise of Increased Efficiency

A study released earlier this month by Pew Charitable Trusts claimed that the US military could save $1 billion through the incorporation of microgrids, shifting away from a reliance on standby diesel generators. A good portion of these savings are based on increased efficiency through the better system management possible with a microgrid. Substituting natural gas for diesel and incorporation of solar PV are also part of the savings equation. Look for a renewed push on military microgrids over the next 4 years, both in the United States and abroad.

 

New Cummins and Tangent Joint Venture Enters the Heart of the Energy Cloud

— November 14, 2016

PipelineA joint venture has entered the Energy Cloud, pioneering new value propositions for stakeholders across the energy value chain. Dubbed edgeGEN, this offering allows energy retailers and commercial and industrial (C&I) facilities to capitalize on real-time economic opportunities on the grid.

edgeGEN consists of Cummins’ natural gas generator sets (gensets) equipped with Tangent Energy’s Tangent AMP distributed energy resource management system (DERMS). The system’s key focus is predicting (and reacting to) customer coincident peak demand, a rare occurrence that can nonetheless represent a significant portion of an electric bill. By focusing on these high-value instances, edgeGEN has the potential to provide high economic value to the grid with a small amount of fuel.

The business case for the product includes value propositions on both sides of the meter. Municipal utilities and energy retailers, the exclusive channel partners for the offering, save costs by incentivizing customers toward desired behavior like cutting demand during peak hours. C&I customers can be rewarded monetarily while in some cases also realizing the benefits of resilient power to ride through outages. Bringing it all together is a financing structure that typically requires no money down from the host facility.

Established Technology in a New Skin

Gensets remain the de facto backbone of many onsite generation systems for several reasons. They are dispatchable quickly any time of day, can have the cheapest levelized cost of energy of any distributed generation (DG) source, and can reliably deliver 1,000 times or more annual energy per square meter than solar PV. They account for 40% of the average microgrid generation capacity in Navigant Research’s Microgrid Deployment Trackermore than any other technology.

Though some argue that the dramatic cost declines in developing technologies like solar plus storage will lead to the displacement of gensets, we see this convergence as a key opportunity. As intermittent renewables grow, there will be increasing demand for fast-ramping gas generation, as noted in recent reports about California by the National Renewable Energy Laboratory (NREL) and the Union of Concerned Scientists. Additionally, according to a report funded by the German government, distributed natural gas generation must play a growing role in thermal energy storage. Both on- and off-grid, growing access to cheap natural gas is only accelerating this trend.

Offerings like edgeGEN have room to grow. Other DER and demand response can be integrated on the same platform, one that has flexibility to evolve alongside the coming growth in transactive energy. Municipal utilities and energy retailers, especially in areas with high capacity and transmission tags, should consider the value of incorporating smart gensets and complementary DER. Facility owners should consider the offering while also considering the true value of resilient power as a potential bonus. With growing renewables penetration, persistently cheap natural gas, and regulatory bodies recognizing the value of dispatchable DG, the opportunities in this space are promising.

 

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