Community Microgrids – Can Capital Innovations Accelerate their Adoption?

Andy Zetlan, a consulting director at SGL Partners, is the guest author of this interesting article about community microgrids and financing options.

The microgrid era has begun worldwide, and investment is now creating showcase examples that enable evaluation of their economics and operational value. Most US investment has been around office campuses, including businesses and universities, and contribute to experiences with energy storage and other equipment that is continuing to progress in maturity. Financing is usually some level of public/private partnership, with funds being spent to ensure that energy for businesses, schools and other organizations is more resilient in the face of service interruptions caused by issues such as the devastating storms that have taken down utility infrastructure in recent years.

Microgrids are installed for different reasons, but in general, benefit users in the following ways:

  1. Provide reliable, continuous power supply
  2. Reduce power cost, which can remain relatively level over a long period of time (e.g. decades)
  3. Enhance use of renewable energy sources to help meet or exceed environmental objectives
  4. Provide high quality power for those processes that require it

Despite their newfound popularity, there are many impediments to microgrid deployments. In some regions, regulatory issues are prominent, with utilities and commissions working towards approaches that make sense to both, even if initial steps may run counter to current business models. Other impediments include the capital cost to transition and the level of knowledge and cost to operate. Yet others are limited by lack of adoption of more “transactive” rates, which are optional today, but are critical to enabling the growth of microgrids.

While communities have been showcased in some projects, many communities haven’t considered the use of microgrid technology. Yet cities and towns may have the most to gain. Installation of microgrids can ensure the availability of communications with emergency and other remote personnel, the consistent operation of police, fire and EMT services, and the ongoing operation of centers reserved for those impacted by lost utility infrastructure.

Communities also can apply microgrids to ensure the least disruption to other utility services like water and wastewater. While many have some backup power, microgrids could enable cities to utilize renewable energy instead of emergency fossil fuel generation in place today. This could also enable communities to address renewable energy requirements.

The major issue always on the table is financing – and I believe that microgrids are about to turn a corner on this issue soon. Typically, microgrids are financed through debt and grant financing, with both state and federal programs supporting their development. Going forward, we are seeing a new approach that may help move the microgrid business forward. Private investment is entering this market.

With private investment, the owner of the community or facility will no longer need finance and operate the microgrid with its related energy production and storage devices. Instead, the community or facility owner will contract with a firm to build and operate the microgrid. This new type of firm will fund the project in return for flat energy payments over many years at payment levels that are lower than today’s costs. The model is similar to that of an Independent Power Producer (IPP) who owns and operates a power plant, and receives payment for energy produced through contracts to supply. In the case of microgrids, the payment stream is usually the result of a single contract with the community, business, school, or other entity.

Contracts will include a Service Level Agreement (SLA) that outlines the minimum performance parameters for the microgrid, and any penalties for unsatisfactory performance. In essence, this new microgrid arrangement is similar to IPP contracts to provide power, except for the parameters that are expected from a microgrid.

Is this happening now? Not quite yet, but the opportunity is around the corner. In fact, Investor-owned utilities might want to be in the business of owning and operating microgrids, if regulatory hurdles can be overcome, but in general, the private sector is poised to move.

The opportunities to move critical energy demand onto microgrids may happen sooner than you think!


ADS TownHall Covers the Good, the Bad, and the Ugly

Chris Kotting is this week’s guest author with some laser-focused feedback on a recent industry conference on Demand Response (DR).

Last week I attended the Association for Demand Response & Smart Grid (ADS) TownHall meeting. Since this was my first time at that particular event, a few things struck me as noteworthy:

  • Demand Response as a resource. All too often utilities think of Demand Response as what I call “Direct Load Control on Steroids” or the ability to turn stuff off at system peak, covering more equipment. Here Demand Response was explicitly part of the Distributed Energy Resources conversation, not merely as a way to help with stabilizing intermittent generation, but as a resource in its own right. The vendors were definitely leading the way in the discussion, but there was remarkably little “pooh-poo-ing” from the utilities.
  • There is innovation outside California. It was nice to see the discussion deal with the structural elements and issues in states other than California. Certainly, California is still a big part of the conversation, but there’s a heck of a lot happening in “flyover country” as well.
  • As is often the case, the sidebar conversations are more interesting than the presentations. Not knocking the presentations, the ones I saw were very useful. However, it’s always interesting to talk to the presenters later and hear what they wish they could have said.

There were a couple of really interesting new business models and adaptations of existing models, including:

  • Fleetcarma, taking the old-school idea of fleet management services into the age of electric vehicles.
  • Gridmates, building a cloud service, to enable customers to donate their energy savings (or income from customer-owned generation) to people and organizations in need.

I also heard some really cringeworthy statements:

  • Residential Demand Response. “Customers have to want to buy it, and have the app on their phone.” I’m sorry, but we’re talking about appliances here. This is worthy of a blog post in and of itself, but here’s a brief rebuttal:
    • Nobody really cares enough about what their pool pump is doing to want to track it.
    • If the customer needs a phone app to control whether there’s hot water when they need it, you’ve misunderstood or lost sight of your mission.
    • Appliances by definition are things that you don’t pay attention to as long as they’re working the way you want. Any appliance that interferes with that concept will faceplant.
  • Doing everything with a smart phone. “Hey look, a thermostat that goes into “away” mode when it detects that your phone is (a) outside a predetermined area based on the GPS on the phone, or (b) it no longer has contact with the phone via Wi-Fi! Isn’t that great!” For you, maybe. Smart phones make developing a user interface as easy as a few lines of code, and you can have a really pretty gadget on the wall. Increasingly, people (yours truly included) turn their phones OFF at the end of the business day, so that they can interact with the rest of the family without interruption. These people don’t want to have to turn their phones back on just so that the furnace keeps working, or so they can change the thermostat.

Overall, the noteworthy content overruled the cringeworthy content. If you haven’t hung out with the ADS folks, I would suggest doing so. There are some really good ideas being presented and socialized.


The OpenADR Standard Enables Diverse Demand Response Programs

This week’s guest author is Barry Haaser, Managing Director of the OpenADR Alliance.  His article clarifies the role that this standard plays in a range of applications.

The OpenADR standard for automated demand response is often misunderstood as just a standard for demand response. In fact, it is a powerful standard capable of supporting a broad spectrum of applications that fall under the demand response umbrella. As the only global standard for demand response, OpenADR is uniquely positioned to address a multitude of load control and load management applications.

In an effort to help utilities and system operators create more demand response programs and further product development, the OpenADR Alliance created an OpenADR 2.0 Program Guide.  This draft document defines typical automated demand response (ADR) programs and explains how they are implemented using OpenADR 2.0. The OpenADR Program Guide expands the range of demand response (DR) deployment scenarios available to energy providers, while giving equipment manufacturers additional information on typical DR Program usage models so they can support a full range of DR programs in their products.

The program guide provides utilities with examples of typical DR programs so that they can model their own DR program implementations, and equipment suppliers can understand typical DR Program usage models to help validate interoperability. The program guide provides templates for popular DR programs. These templates include:

  1. Critical Peak Pricing: This rate and/or price structure is designed to encourage reduced consumption during periods of high wholesale market prices or system contingencies by imposing a pre-set high price for a specific time period (such as 3pm – 6pm on a hot summer weekday).
  2. Capacity Bidding Program: This program is used by Independent System Operators (ISOs) and utilities to obtain pre-committed load shed capacity from aggregators or self-aggregated customers when they anticipate high wholesale market prices, power system emergency conditions, or as part of normal energy resource utilization by calling DR events during a specified time period.
  3. Residential Thermostat Program/Direct Load Control: This demand response program describes utility or other energy service provider communications with smart thermostats or remotely controls enrolled customer loads, such as air conditioners. These programs are primarily offered to residential or light commercial customers.
  4. Fast DR Dispatch/Ancillary Services Program: Fast DR is used by ISOs and utilities to obtain pre-committed load response in “realtime.”  Resources are typically dispatched with a latency ranging from 10 minutes for resources that are used as reserves to 2 seconds for resources that are used for regulation purposes.
  5. Electric Vehicle (EV) DR Program: This demand response activity modifies the cost of charging electric vehicles to cause consumers to shift consumption patterns.
  6. Distributed Energy Resources (DER) DR Program: This demand response activity smooths the integration of distribute energy resources into the Smart Grid.

This program guide just scratches the surface of the many programs that can be supported by the OpenADR standard. You can download the draft program guide and provide us with your feedback prior to publication this summer.


Can Community Microgrids Cost-effectively Integrate Local Renewable Energy?

This week’s guest writer is John Bernhardt, Outreach & Communications Director, Clean Coalition, discussing the rapid evolution of microgrid models in the USA.

The United States is transitioning from a centralized power system towards a more decentralized system. As greater amounts of distributed energy resources (DER) – such as local renewables, advanced inverters, and energy storage – come online, it is vital to establish an approach that optimizes the integration of these solutions in a manner that secures the most value to the grid at the least cost. The Clean Coalition’s Community Microgrid Initiative is providing such a pathway.

A Community Microgrid is a coordinated local grid area served by one or more distribution substations and supported by high penetrations of distributed generation (DG) and other DER. Community Microgrids reflect a new approach for grid operations that achieve a more sustainable, secure, and cost-effective energy system while enabling long-term power backup for prioritized loads.  The substation-level foundation of a Community Microgrid facilitates cost-effective replication for optimizing grid operations and customer satisfaction across utility service territories.

In collaboration with leading utilities, the Clean Coalition is developing Community Microgrids to demonstrate their technical and economic viability. The objective of this work is three-fold:

  • Achieve high penetrations of local renewable energy generation
  • Enhance grid resilience by providing long-term back-up power for critical loads
  • Establish a replicable model that enables scale and cost-effectiveness for any target grid area

The Clean Coalition has established a standardized four-step process to design and deploy these microgrids.

First, a DG survey assesses the potential for local generation within the target grid area. Tailored to the specific distribution grid area, the DG Survey takes into account the characteristics of actual prospective sites for local renewable generation. DG potential is quantified, which also helps define potential needs for other DER.

Second is the creation of a DER optimization model. The DER optimization model defines the ideal portfolios of DER across a target grid area. This step uses utility-validated advanced grid modeling techniques that consider local grid characteristics such as power flow, connected feeder capacity, and customer load shapes. This methodology became a key component of California’s recent ruling that requires the state’s investor-owned utilities to plan for high penetrations of DER, leveraging existing distribution grid capacity to accelerate deployment.

Third, a DER financial analysis highlights the costs and benefits of the optimal DER portfolios, including the value of reduced transmission and distribution investments, transmission access charges, and line losses. This analysis takes into account the use of efficient markets based on streamlined procurement and interconnection of DER.

The final step is to create a design and deployment plan for the Community Microgrid. Working in collaboration with local utilities, the Clean Coalition’s system design and operational plan includes technology vendor recommendations relevant to the design criteria and grid requirements.

The Clean Coalition is actively pushing forward two Community Microgrids. In collaboration with Pacific Gas & Electric, the Hunters Point Community Microgrid Project is bringing 50 megawatts of local solar PV to one substation area in San Francisco. In New York, two utilities – PSEG Long Island and the Long Island Power Authority – are deploying a combination of solar and storage in the Long Island Community Microgrid Project. This project was recently awarded NY Prize funding.


How Utilities Can Bridge the Gap Between Technology and Customer Education

This week’s guest author is Juliet Shavit, President and CEO of SmartMark Communications and SmartEnergy IP™. There’s an important link between Smart Grid technologies and customers, and more utilities are catching on to its value as a long-term, sustainable model.

What role does the customer play in a technology deployment? That is the question the utilities industry has been tackling over the last decade as the crusade to upgrade the country’s electrical infrastructure has developed into a reality.

Early AMI deployments had utilities focused largely on technology installations. If they could get the meters installed and create an optimized two-way communications network that included smart meters, sensors, etc., there was seemingly no room or need to think about the customer …

Until the first unexpectedly high bills began to hit customers after the initial smart meter deployment.

Until the first deployment caused such an uproar in the industry that the need arose to re-examine a utility’s strategy around AMI customer engagement.

Until regulators started requiring a customer education plan to be filed with the business case for Smart Grid investments before utilities could start installing a single meter.

Then the major shift in the industry occurred. I call it the “point of no return” when the customer became an integral part of the industry conversation.

But the role of the customer around education and communication is not just to get meters in homes and avoid backlash against the utility around AMI. The real need to invite the customer into the conversation is around behavior change. Unless customers do their part to reduce energy use, balancing the load on the grid will not be a sustainable reality. Knowledge is power, they say. An educated customer is more effective than any digital device. When customers understand the benefits of AMI and are exposed to customer-facing tools that help them manage their energy use, the control shifts to them and the message is then about customer empowerment.

The Smart Grid Customer Education Symposium on June 11 in Chicago invites utilities across the country to talk about their experiences in communicating and engaging with customers about the benefits of the Smart Grid. But, equally important, the event invites regulators and stakeholders to share their perspectives on the benefits of Smart Grid customer education.

The only way to achieve lasting success of the Smart Grid is to bridge the gap between technology and education, and talk about how advanced analytics and usage behavior will help change the way customers understand and manage their energy use.

This is the long-term sustainable model for utilities. The advanced technology is already in place to revolutionize the delivery of energy into every home and business in the country. For the continued successful transformation of the electrical grid of the past to the Smart Grid, educating customers must be as primary of an objective as the technology installation.

This is the real goal of Smart Grid customer education.


Creative Partnerships Help Build Critical Infrastructure Resiliency with Microgrids

This week’s guest authors are Christina Briggs, Economic Development Manager for the City of Fremont, California, and Vipul Gore, President and CEO of Gridscape Solutions. The microgrid solution described here points to the benefits of collaborative planning and development to build resiliency for critical infrastructure and contribute to the goals of a truly Smart City.

Cities have a significant opportunity to lead by example when it comes to innovative energy solutions. But the pot sweetens even more when sustainable energy decisions also contribute to a City’s economic development strategy. In the case of Fremont, where clean technology is considered one of its largest industry clusters, public-private partnerships can promote the testing of new technology, help its local companies scale, and identify potential sustainability measures for City operations. Here’s how Fremont and Gridscape Solutions are crafting win-win scenarios.

The City of Fremont and Gridscape Solutions are teaming up to pursue a California Energy Commission (CEC) Electric Program Investment Charge (EPIC) opportunity. This state program funds technology demonstrations of reliably integrating energy efficient demand-side resources, distributed clean energy generation and smart grid components to protect and enable energy-smart critical facilities. This follows on a previously successful collaborative effort where Gridscape Solutions assembled a consortium of partners for a city EV charging infrastructure project, including the Fremont Chamber of Commerce, Prologis, Delta Products, and the City of Fremont.

The proposed project consists of deploying a microgrid at three fire stations within the City of Fremont. The close proximity of Hayward Fault line to these Fire Stations, the maximum load capacity on the transmission line, and the need to reduce grid dependency satisfy the most important grant requirements of providing energy savings, increasing electrical infrastructure resiliency, reducing carbon dioxide emissions and demonstrating islanding from the grid for up to three hours. Using the combination of renewable generation and battery technologies, the microgrid project could save the City of Fremont approximately $10,440 per each fire station and reduce CO2 emissions by 22,176 pounds per station per year.

The proposed microgrid design will provide at least three hours a day of power to the fire station in the event of a utility outage. The microgrid is also capable of responding to signals to proactively and seamlessly disconnect from the grid by using state-of-the-art microgrid controls, and advanced load controls. The implementation of the microgrid also serves to balance PV generation supply, efficient energy storage and campus loads to achieve the City of Fremont’s net zero energy goals by maximizing PV electrical energy usage behind the meter. During a utility outage, the power distribution may be isolated from the utility at the point of service by a microgrid inter-tie protection relay.

The primary goals of the project are:

  • Island for up to three hours by disconnecting from grid
  • Reduce energy costs and CO2 emissions
  • Improve resiliency and reliability of fire station infrastructure using microgrid
  • Deliver the highest value to ratepayers and the utility by optimal configuration
  • Demonstrate innovation and environmental stewardship through the deployment of energy usage dashboards to the City of Fremont or CEC systems.

The priority status cities place on these facilities, combined with the tremendous innovation and market opportunity for companies in this space creates a win-win scenario. When cities leverage industry expertise in their own backyards, society stands to benefit.