Maybe it was the pandemic or maybe it was the law of accelerating returns. Whatever the case, 2020 brought rapid change for microgrids. Where the technology was solidly for the few in 2019, it suddenly looked quite possibly for the many in 2020. That’s why Microgrid Knowledge is naming the home microgrid, as its 2020 ‘Person of the Year.’

To explain, let me jump back 18 months to our annual conference in May 2019. There were many intriguing discussions at the event, but one session in particular now strikes me as pivotal. John Westerman, then with Dynamic Energy Networks and now with Schneider Electric, gave a presentation on how he built his own home microgrid, what some would call a nanogrid.

At the time, home microgrids were an oddity, and his presentation did little to make me think that would change anytime soon. Westerman’s microgrid was affordable because he did the engineering and labor himself. Unfortunately, few of us know skilled microgrid engineers willing to do pro bono work for us.

So home microgrids, while found here and there, still appeared far down the road as an accessible product. At that point, most microgrids were being built for businesses, colleges, hospitals, and the like.  But three things happened to shorten the road a lot.

The first was the public safety power shutoff, the term California’s utilities use to describe the practice they began of shutting off power to customers to avoid sparking wildfires with their electrical equipment. 

Outages humiliating for California

California first felt the brunt of the practice in October 2019, an experience the Los Angeles Times described as “humiliating.” More outages were to come, leaving millions of Californians in the dark over the wildfire seasons of 2019 and 2020. The bitter cherry on the top for California was an unusual rolling blackout in August 2020, brought about not by wildfires but a lack of adequate electric supply in the face of extreme heat. After that, as one microgrid developer told Microgrid Knowledge, “Demand was through the roof before and now it’s through the chimney.

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In light of the global COVID-19 pandemic, this year was one for the books for almost every industry. But the energy industry was also responding to other unique occurrences, such as significant wildfires in California and multiple hurricanes on the Gulf Coast. In light of these challenges, many in the industry turned to expert advice and strategies from industry leaders. One of the outlets for such information is the full library of microgrid white papers. 

Microgrid Knowledge’s top 10 microgrid white papers of 2020 came from energy leaders such as Ameresco, Bloom Energy, Eaton, Enchanted Rock, Instant ON, NRG, S&C Electric, Schneider Electric and Siemens.

The most popular microgrid white papers, as well as much of the energy news stemming from 2020, make clear that more and more energy customers better understand the value of energy resiliency. For example, critical facilities, such as hospitals and data centers, were stressed during 2020 because of impacts from the coronavirus, and resiliency is now a top priority.

Below you will find the top 10 most downloaded white papers on Microgrid Knowledge in 2020, covering everything from how microgrids are changing to how energy-as-a-service models are opening the door to microgrids for more facilities.

1. Nanogrids: A New Opportunity for the Solar Industry
Instant ON

Solar energy has the ability to provide immense benefit to society and the grid. But solar’s full potential isn’t being fully realized. This report is designed to help boost awareness and understanding of solar nanogrids, courtesy of Instant ON.

2. How Microgrids are Changing the Paradigm on Data Center Power Delivery, Uptime and Efficiency
Enchanted Rock

Uptime and performance are critical for data centers, but they cannot continue to rely on diesel generators for reliable backup power, especially as they respond to price pressure and environmental sensibilities. Explore why microgrid use is on the rise and how microgrids improve resiliency, uptime and a data center’s environmental profile.

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If you think research scientists sit around in white lab coats tossing theories around without any practical engineering experience, think again. The National Renewable Energy Laboratory (NREL) recently launched its Advanced Research on Integrated Energy Systems (ARIES) platform, a computing environment designed to model today’s complex electric grid and support the development of new energy generation technologies and resilient microgrids. About two months into ARIES’ tenure, NREL’s Flatirons Campus—a facility that tests renewable energy systems—experienced a power outage caused by a utility transformer explosion. Because the damage occurred near the Flatiron connection to the main grid, the utility told NREL to expect several weeks without power. 

Faced with the prospect of delaying their research, NREL administrators wondered whether the facility could go into self-sustaining mode until the transformer could be replaced. The lab-coat crowd replied, “Challenge accepted.”

Pulling Itself Up by Its Own Bootstraps

The Flatirons Campus microgrid is designed to be grid-tied with the ability to go into “islanding” mode (disconnecting from the grid and running independently) when necessary. So, NREL engineers isolated the microgrid and used its 1 MW / 1 MWh battery to power the control center. Once that was up and running, they used ARIES’ digital twin to see how the microgrid would respond to each power source. After simulating and validating a black start procedure, they connected the 430 kW solar array and the 1.5 MW wind turbine to keep the battery charged. Other systems were brought online until the facility—which draws about 200 kW—was fully capable of resuming its work and remained so until the transformer was finally replaced, and the campus reconnected to the grid. ARIES helped engineers turn a crisis into a case study in energy resiliency.  

Flatirons Campus

At the center of NREL’s Flatirons microgrid sits the controllable grid interface (CGI), which tests the mechanical and electrical characteristics of renewable energy technologies both on and off the grid. It is capable of simulating various fault conditions and evaluating the microgrid’s response. The CGI controls grid support systems, such as voltage and frequency regulation, reactive power (VAR) compensation, and load balancing. In addition to battery storage, two solar arrays and various wind turbines, the campus is home to a water power instrumentation lab, a three-megawatt load bank and three dynamometers that help wind turbine manufacturers test their generators under controlled conditions. 

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The defining feature of any microgrid is the fact that it generates and consumes its power without having to rely on the support of the broader utility grid. According to Bloomberg New Energy Finance, solar is the least expensive form of new build power generation. The challenge with solar is that it is an intermittent resource, so relying on it solely will not be sufficient in building a viable microgrid. Of course, the solution to this deficiency is pairing solar with battery energy storage.

Thus far, most deployments of solar plus storage have utilized the AC coupled technique, whereby the solar and batteries are connected on the AC side of inverters connected to each resource. In the DC coupled approach, which, thus far, has been less frequently deployed because it is less understood, the solar and storage are connected on the DC side of the inverter by using DC:DC converters to marry the differential levels of voltage from the PV and battery, and they use a common DC bus to divert energy into either the battery or the ultimate load. 

When it comes to the goal of most microgrids, i.e., creating a reliable supply of energy to consistently feed loads, the DC coupled approach offers a number of benefits, which are explained below.

Benefit 1: Harvest more energy 

A typical technique when building a solar plant is to overbuild the DC capacity of the solar array relative to the inverter. Historically, the reason for doing this has been to maximize the utilization of the inverter’s AC nameplate rating over the course of an entire day, from sunrise to sunset. During midday hours, when a solar array is overproducing the nameplate rating of the inverter, the solar energy will be curtailed or “clipped” by the inverter to ensure the generation does not exceed the capacity of the inverter.  

While this technique makes sense for stand-alone, grid connected solar projects, it can be counterproductive for a microgrid that needs to capture every electron the solar array generates. With the DC coupled approach to combining solar and storage, excess generation coming from the solar may be diverted into a battery, instead of essentially being “thrown away’”when it is clipped by the inverter.

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California regulators are getting an ‘A’ for effort as they pursue pioneering rule changes to support microgrids, but beyond that, industry stakeholders diverge in their views as the proceeding nears a significant milestone (19-09-009).

At issue, is a proposed decision recently issued by an administrative law judge for Track 2 of the proceeding, instituted by the California Public Utilities Commission (CPUC) to help commercialize microgrids. The complex proposal would launch a range of changes, from creating microgrid tariffs to altering restrictive boundary rules. Track 2 awaits a commission vote that may occur as soon as January.

Allan Shurr, chief commercial officer at Enchanted Rock, described the proposed decision as a “mixed bag.”

He noted that while it advances multi-party microgrids, it also defers numerous key issues to a working group or Track 3 of the proceeding. Among issues deferred are standby charges, use of non-renewable resources in microgrids, microgrid definitions, and identification of microgrid policy issues not adequately addressed by existing state agencies.

Schurr praised its recommendation for a $200 million incentive program to support microgrids in disadvantaged communities and its recognition of “commercially available cleaner alternatives to expensive diesel and the proposed support for up to $350 million in near and medium term substation microgrids.” The recommendation would lead to lower emissions and eliminate public safety power shut offs at ‘safe to energize’ areas — a positive development, especially for those affected communities, he said.

What about customer microgrids?
Meanwhile, Samantha Reifer, director of special projects at Scale Microgrid Solutions, called the proposed decision “disappointing.” Reifer was particularly critical of its emphasis on utility and substation microgrids, as opposed to customer microgrids that are typically built for businesses, institutions or households.

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The PJM Interconnection is getting close to approving rules governing microgrids operated by distribution utilities or third parties on their behalf — what it calls public distribution microgrids.

After being approved by various stakeholder panels, the PJM’s Markets and Reliability Committee (MRC) is set to review the proposed rules at a December 17 meeting and potentially endorse them in January.

Once endorsed at the MRC the microgrid rules would be published in PJM’s Manual 14D and would become effective, according to Andrew Levitt, a senior market design specialist for the grid operator.

The rules remove a few PJM-side barriers to the development of a particular type of public microgrid on the distribution system, Levitt said.

The planned rules only apply to distribution-level microgrids, according to a December 3 presentation by the grid operator’s staff. The microgrids may not include any bulk electric system components or transmission facilities.

PJM defines public distribution microgrids

Under the planned rules, public distribution microgrids, or PDMs, must include load, one or more generators, one or more switches for isolating from and connecting to the broader grid, and a microgrid controller.

A PDM generator must sell its power to PJM, which operates the grid and power markets in 13 Mid-Atlantic and Midwest states and the District of Columbia.

When in island mode, the electric distribution company can operate the microgrid at the wholesale or retail level, according to the presentation.

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In another sign that the US government is making energy resilience a priority, the Department of Energy (DOE) is incorporating microgrids as part of a program to spur $440 million in energy improvements for 16 federal projects.

Announced late last week, the effort is meant to bring energy efficiency and resilience to a range of facilities from ports to military bases to building campuses.

The DOE will provide $11 million to leverage an expected $440 million in performance contracting for the projects.

Several of the federal projects including microgrids, among them a General Services Administration Region 7 facility in Oklahoma, which plans to install a campus microgrid that incorporates four courthouses and a parking garage, operated under a utility energy services contract. The project includes solar, batteries and microgrid controls, along with a range of energy conservation measures. 

Military microgrids dominate

Several of the other microgrid projects are at military facilities. 

Scott Air Force Base in St. Clair County, Illinois, south of St. Louis, intends to improve the resilience and energy efficiency of its data centers and control and command centers. The project will include solar PV, a 100 kW battery energy storage system (BESS) and microgrid controls, which will operated under a energy performance contract.

In Fairfax, Virginia, Fort Belvoir plans to undertake a range of energy efficiency and resilience measures, which include solar PV combined with a battery system with microgrid capabilities, backed up by natural gas engine generators.

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History shows us that an injection of government funding often boosts new and promising energy technologies. But is the same true for microgrids?

In the US, few government incentives exist that are solely for microgrids. If that should change — and how it should change — were topics addressed in a recent Microgrid Knowledge audience survey, as well as in a discussion at last month’s Microgrid 2020 Global, a virtual event hosted by Microgrid Knowledge, which drew more than 4,300 registrants.

The bottom line? The microgrid community appears to have mixed attitudes about the importance of grants, loans and tax credits — at least when they are stacked up against other possible regulatory and legislative actions to support the technology.

“The money is nice, yes, but I think most people within the industry know that there’s a ton of capital in the marketplace that wants to be deployed on clean energy and microgrids. The problem is the policies and regulations don’t necessarily allow enough of the projects to proceed,” said Benjamin Parvey, CEO of Blue Sky Power, speaking during a policy workshop at the virtual conference.

What’s needed more, said Parvey, are fewer regulatory barriers that inhibit competition and impede customer access to the microgrids.

Regulatory blockage
Other industry representatives at the policy workshop — Brian Levite, regulatory affairs director at S&C and Mona Sheth, senior director, federal government affairs, Schneider Electric — concurred with Parvey that more incentives are not the top priority.

“It is a regulatory and business model blockage here that is, in my opinion, stopping up the works,” said Levite, in an opinion that was also supported by the Microgrid Knowledge Advisory Board during their discussion at the conference, where they issued a call to action for the industry.

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Western Australia state utility Horizon Power is to demonstrate the country’s first renewable hydrogen microgrid.

The microgrid to be constructed at the rural resort town of Denham 800km to the north of Perth is aimed to test the technical capability of hydrogen as a dispatchable power source in remote microgrids in anticipation of the technology becoming cost competitive in the future.

Horizon Power is one of Western Australia’s three state electricity enterprises with responsibility for its large rural area. As such the company has been a pioneer in the development of microgrids, with almost 40 installations over the past 15 years.

Stephanie Unwin, the CEO of Horizon Power says the Denham Hydrogen Demonstration Plant will extend the utility’s knowledge and technical capability of hydrogen operating systems and test how to integrate and deploy this technology into remote diesel microgrids, common across regional Western Australia.

“This plant will demonstrate how hydrogen can reliably produce dispatchable power for our towns currently dependent on diesel fuel power systems and allow us to transition our network away from higher emission generating sources and meet our target of no new diesel generation systems from 2025,” said Unwin.

“This technology has the potential to be an environmental game changer for many remote towns in Western Australia and other similar locations around Australia, and allow greater uptake of reliable cleaner, greener renewable energy sources in the future.”

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