Navigant Research Blog

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.

 

Do Microgrids Disrupt Traditional Utility Business Models?

— June 2, 2016

GeneratorThe classic storyline surrounding microgrids is that they challenge electric utility monopolies in multiple ways. Up until recently, the vast majority of these systems deployed in North America, currently a global hotspot for microgrids, were developed by third parties. Not only that, they were designed primarily to offer economic and resiliency benefits to consumers, with the interests of the incumbent utilities almost an afterthought.

That simpleminded view of the world is being challenged by the utility distribution microgrid (UDM), a concept first put forward by Navigant Research in 2012. Since that time, the number of utilities exploring opportunities in the microgrid space has grown dramatically.

Microgrids and the Utility

One could argue that microgrids sprung up as a response to customers not getting what they needed from traditional utility service. UDMs turn this premise on its head. They can help utilities manage recent distributed energy resources (DER) employment trends to their advantage. Microgrids owned or operated by utilities can first and foremost serve the distribution, as well as be a platform for new services for customers.

In terms of architecture, UDMs tend to be on the utility side of the meter; the classic prototypes are the installations is being proposed by Commonwealth Edison in Illinois. Yet there are many hybrids under development, some of which aggregate and optimize customer-owned assets that are located behind the meter. Among the examples of the latter are projects by utilities such as Oncor and the Sacramento Municipal Utility District (SMUD).

Perhaps one of the most interesting trends when it comes to UDMs is how the roles of investor-owned utilities (IOU) and publicly-owned utilities (POU) flip-flop over the next decade, especially in the United States. As the chart below illustrates, IOU projects are expected to lead the market until 2021. This is largely because of larger projects; the classic example is San Diego Gas and Electric’s (SDG&E) Borrego Springs microgrid, which now represents 31 MW peak capacity. If measured by sheer numbers, I believe public power microgrids will outnumber their IOU counterparts much sooner.

Fewer Obstacles but a Smaller Scale

Municipal utilities have fewer regulatory obstacles and internal conflicts in pursuing microgrids than IOUs. That said, the scale of their projects will tend to be smaller. Take the case of Alameda Municipal Power, which is in the process designing a microgrid at an abandoned Navy facility located within its service territory and whose initial capacity will likely fall in the 5 to 7 MW range.

Annual UDM Capacity and Revenue, United States: 2015-2024

Peter Microgrid Blog Graph

(Source: Navigant Research)

Keeping pace with the fast and continuously growing microgrid market is no small task. As of April 2016, the Microgrid Deployment Tracker has identified 1,568 projects across the globe representing a cumulative 15,599.7 MW of capacity. These numbers represent microgrids from 119 countries across all seven continents. North America represents over half of the new projects entered, while the utility distribution and remote segments account for almost three-quarters of the new capacity.

Whether examining remote or grid tied microgrids, the role of utility in their deployments and operation will only continue to grow the next decade.

 

 

The Growing Role of Energy Storage in Microgrids

— May 23, 2016

GeneratorEnergy storage systems (ESSs) have an important and diverse role in microgrids. Solar PV and other renewable distributed generation (DG) technologies require a voltage source in order to synchronize. This has typically been done with a backup generator; an ESS provides a similar voltage source but without the emissions of a diesel generator. Recent advances in microgrid automation systems, however, have made ESSs less of a necessity in partially renewable-based microgrids. According to industry leader ABB, microgrids with as much as 50% of load coming from renewable sources do not need an ESS. This is 10% higher than previously believed. Despite this, microgrids without some form of storage are not likely to become the norm, as ESSs provide a number of other advantages aside from being a voltage source. Peak shaving, smoothing power flow, and volt ampere reactive (VAR) support are just a few of the supplemental functions an ESS frequently serves. Islanding and black-start assistance further support the case for storage use in renewable DG microgrid systems.

The most recent update of Navigant Research’s Microgrid Deployment Tracker investigated the use of ESSs in microgrids across the globe. According to the report, of the greater than 15 GW of microgrid capacity accounted for in the Tracker worldwide, almost 25% utilized ESS in some form, up from a reported 17.5% of projects in the previous Tracker update in 4Q 2015. This is a result of ESSs being present in over 40% of new project capacity from the most recent update.

The chart below shows the percentage of ESS utilization by microgrid segment for both the 4Q 2015 and the 2Q 2016 Tracker. While ESS utilization grew across all categories, the commercial and industrial (C&I) and utility distribution segments saw the most significant increase, growing 40% and 23%, respectively. C&I microgrids have traditionally been led by diesel combined heat and power (CHP) systems in the past. The jump in energy storage use among microgrids in this segment likely signals a shift to solar PV and other renewable energy use that has a higher need for ESSs.

ESS Utilization by Microgrid Segment, World Markets: 4Q 2015 and 2Q 2016

Adam Wilson Blog

 (Source: Navigant Research)

This is further supported by the fact that solar PV capacity in microgrids grew by almost 840 MW since the last update of the Tracker, an increase more than 5 times greater than CHP capacity growth. The combination of solar PV and ESS is expected to grow in popularity across most segments and regions of the microgrid market. The declining price points of energy storage and solar PV technologies and an increasing focus on renewable sources are largely responsible for this shift. It has also been suggested that the combination of CHP, solar PV, and lithium ion energy storage represents the ideal mix of technologies for microgrids, particularly in the United States.

The high functionality of storage systems along with the growing presence of renewable generation in the microgrid market bode well for the future of ESS. These systems are expected to remain a core technology in the microgrid industry for the foreseeable future.

 

Why Even Have Meters?

— May 17, 2016

MeterFor as long as utilities have existed, they have created ways to have their customers pay for what they use.  The meter has traditionally been that tool, and many have looked to the newer iteration, the smart meter, as the nexus to enable the next evolution in the way utilities perform. Smart meters have been deployed for water utilities and gas utilities with recent fanfare. Most significantly, smart meters have been deployed by electric utilities, which are using advanced metering infrastructure as a pillar for new programs for a cleaner grid with more efficient use of power. The electric submeter is a part of that plan, enabling a finer grain look at who uses power with a tenant-by-tenant view. But is it time for us to rethink meters? Are they going to be a part of our digital future?  Certainly, we have to keep measuring use—having customers pay for the resources they use is critical, regardless of how low the cost. But with Internet of Things (IoT)-enabled devices, we need to rethink how resource use is reported, whether it be gas, water, or electricity.

A Clearer Picture through IoT

IoT-enabled devices—think cable boxes, commercial HVAC units, large factory machines, and data centers–are already deployed in the marketplace. To date, most of the IoT buzz has been associated with control or information flow, like a building automation system controlling an HVAC unit or a cable company sending over the latest prime time drama. With little modification, IoT-enabled devices can share how much power, gas, or water they are using at the place and time of their use. If all new devices were shipped with this technology, it would be possible to have a clearer picture of how those resources are being used than by using the aggregation tool that is the meter.

Utilities would not want meters to go away. They are a key cornerstone of how they work and, in some cases, are required by law. But as utilities strive to keep pace of the fourth industrial revolution, they may need to rethink how they want to provide better services for their customers. Approaches like circuit-level or plug-level energy reporting are not new, but if the entire electric, gas, or water system was reporting on how much it used in real time, it would provide a much clearer picture of the state of the system. This reporting could also shine a light into how much waste is present due to things like vampire loads or leaking pipes.

We’d need to have permissions and payment mechanisms resolved, and prototypes are already in development for microgrids. We’d need to have assurances that device reporting is reliable and secure, something that has already been proposed though the use of blockchain. The biggest obstacle is our existing infrastructure. At this point, it may not make economic sense to remove or even turn off meters and submeters, even as IoT devices are shipping. But there will be a time in the not-to-distant future where the meter will be viewed as redundant. It may be in a microgrid, or on a university campus.  There will be a tipping point where, for some new commercial, residential, or industrial facility, it will be cheaper to have no meters at all. On that day, we stop using the end of the buggy whip as the prototypical example of obsolesces, and we will instead recall the era of the meter.

 

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