Navigant Research Blog

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.

 

Australia Is Emerging as Ground Zero for Governments Seeking Microgrid Role Models

— July 29, 2016

BiofuelNavigant Research has long argued that North America—and especially the United States—is the global hotspot for microgrids. I’ve argued that if one includes remote microgrids into consideration, it could be said that Alaska is the microgrid capital of the world. However, recent trends point to explosive growth in microgrids of all sizes, shapes, and applications (including both grid-tied and remote) in the Asia Pacific region. And it appears Alaska has some stiff competition in Australia.

Most of the innovation in the Asia Pacific region has been focused on private sector business models. But what about carving out a new role for utilities owned by the government? Certainly, microgrids challenge and may disrupt typical utility business models within the context of systems that intentionally island in order to derive economic benefits within a distribution grid. But what about utilities that operate and manage off-grid, remote systems?

Horizon Power a Standout Model

This is a space in the microgrid market where few have ventured, with the single notable exception of Horizon Power in Western Australia. Horizon Power services the biggest area with the least amount of customers in the world—a service area of approximately 2.3 million square kilometers, or an average of one customer for every 53.5 square kilometers of terrain. Its microgrids are exposed to intense heat and cyclonic conditions in the north and severe storms in the south.

Australia has long been a leader in wind-diesel hybrid microgrids provided by vendors such as Powercorp (now ABB) and Optimal Power Solutions, the latter a company which ranked third in last year’s Navigant Research Leaderboard Report on microgrid developers/integrators offering their own controls platform.

Horizon Power is more focused on providing operational efficiencies and value creation for the much maligned government-owned utilities. Its creativity may well spill over into other Asia Pacific markets that also focus on how to bring an enterprise management acumen to remote systems. Such remote systems traditionally have suffered from poor operations and management systems, contributing to the eroding financial status of utilities.

Asia Pacific Innovation

Australia is, like Alaska, a unique setting in which to test drive new and innovative business models, as well as robust technologies that must withstand extreme weather and logistical challenges. Innovators in nearby New Zealand (such as Infratec, an entity that is a spin-off from a publicly owned electricity distribution company) are showing that not all good ideas come from the private sector. Infratec recently entered into a strategic alliance with Perth-based company EMC to bring a wider range of product offerings to New Zealand and the Pacific. Already, Infratec and EMC jointly deployed the country’s first grid-connected, commercial-scale battery energy storage system in South Canterbury.

As the most recent Microgrid Deployment Tracker shows, the Asia Pacific region is rapidly catching up to North America in terms of total identified microgrid capacity. One could argue today that Australia is today’s global leader in terms of exploring synergies possible with enterprise optimization of remote microgrids, a topic that has yet to be tackled in any comprehensive way anywhere else in the world. A decade from now, I wouldn’t be surprised to see Australia and New Zealand among the top countries in the world when it comes to microgrid innovation.

 

Breaking New Ground While Exploring Value of Energy Storage in Southern California

— June 7, 2016

Cloud ComputingThe closure of the 2,150 MW San Onofre Nuclear Generating Station (SONGS) has left a huge hole in the power supply portfolio that Southern California Edison (SCE) had traditionally relied upon to serve customers. On top of that, the massive leak of methane from the Aliso Canyon natural gas storage facility has further aggravated the electricity supply challenges facing Southern California.

The leak is the largest known leak of methane into the atmosphere in U.S. history. It continues to make headlines, but longer term impacts could still be felt this summer.

Filling the Gaps

“When full, Aliso Canyon has enough natural gas stored to supply fuel to 18 regional power plants located in the Los Angeles basin for 21 days. But it takes 2 to 3 days for that natural gas to get into the basin where it is needed. So when the sun goes down, we can’t get the gas fuel to power plants where it is needed in time,” said Susan Kennedy, CEO of Advanced Microgrid Solutions (AMS), a company that has won a contract with SCE to deploy up to 50 MW of distributed energy storage to help fill regional supply gaps via hybrid electric buildings such as those owned by the Irvine Company.

“One major heat wave this summer could have major impacts, leading to curtailment of electricity service,” a prospect recalling the power outages that plagued California in the 2000-2001 timeframe, when Kennedy, working on behalf of then-governor Gray Davis, had to resort to emergency measures seeking drastic demand reductions in order to keep the lights on. “Few people seem to make the connection between this natural gas supply and our reliable electricity system,” she noted. But Kennedy does. “What we clearly need to get through this summer and into the future is fully dispatchable demand response [DR], the ability to use customer load as a resource in the same way we use supply. Energy storage allows us to create such a resource that also provides economic value for customers, such as the Inland Empire Utility Agency [IEUA].”

Water-Energy Nexus

The agreement with IEUA is addressing the water-energy nexus in California, an issue that is also raising concerns in light of lingering droughts. IEUA has been leading on renewable energy since 2008, with solar, wind, and biogas resources already part of its electric resource portfolio. With the help of AMS and its partner Tesla, these energy storage devices will allow the agency to maximize value to reduce its energy costs by an estimated 10%, or as much as $230,000 annually.

IEUA did not have to pay any upfront capital costs under the terms of the unique contract with AMS. Yet the biggest surprise to emerge in this project was SCE’s flexibility in contracting. The investor-owned utility had to adjust the existing tariff with IEUA in order to bring the energy storage devices online. “There was no template of how to do this,” said Jesse Pompa, a senior engineer at IEUA. “Batteries had never been connected to a grid in this way before. This was indeed a risk for us, and the biggest surprise is that they accommodated us.”

“I have to say, SCE is the most open-minded of all California utilities in viewing energy storage as a grid resource,” added Audrey Lee, AMS’s VP of analytics and design. She noted that the artificial intelligence software that AMS provides enables the fleet of Tesla batteries to provide a firm, dispatchable DR resource to help SCE get through this summer.

 

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