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.

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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.

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The Animal Farm of Things

This week’s guest author is Chris Kotting, a Consulting Director at SGL Partners. His insightful compare and contrast of the Smart Grid and the Internet of Things raises important discussion points.

I’m prone to literary and cinematic allusions, sometimes those allusions are obscure, or at odd angles to the main topic, so for those of you who are confused already, bear with me.

I have been immersed increasingly in the Internet of Things discussion, and trying to understand how it relates to Smart Grid and specifically Demand Response. Since Demand Response requires information connectivity, it appears, on the surface at least, as though there is a natural convergence there. Appearances can be deceiving.

Most people, even those who have never read the book and don’t know the source of the statement, know at least one sentence from George Orwell’s Animal Farm:

All animals are equal, but some animals are more equal than others.

In the Internet of Things discussion, the same kind of reality has struck me in recent weeks:

In the Internet of Things, all things are equal, but some things are more equal than others.

What do I mean by that? Most of the things being discussed in the IoT world have some common characteristics:

  • They are generally small.
  • They are generally intended to be portable.
  • They are generally low-power draw.
  • They are generally relatively luxury items.
  • They have high “gee whiz” or “Oooooooh, Shiny” factor.
  • They have an entertainment orientation or angle.
  • They can tolerate (indeed, the business models often require) high turnover.
  • They are designed for constant interaction.
  • A lack of reliability is tolerable. (Grandma won’t die if the web browser on her tablet fails.)

This is where there is a disconnect between the worlds of the Internet of Things and Demand Response. What are the common factors in what makes a Thing a “Demand Response Thing.”

  • They are generally large.
  • They are generally stationary.
  • They are generally high-power draw.
  • They are generally in all households (or at least very many).
  • They have zero “gee whiz” or “Oooooooh, Shiny” factor.
  • They are utilitarian, with little or no entertainment value.
  • They can serve a single buyer for 15 – 25 years (and often more).
  • They are designed to be pretty much left alone once installed.
  • Reliability is more important. (If the A/C quits on a hot summer day, Grandma could well die.)

Let’s face it, we use the term “appliance” to mean something that you install and ignore.[1]

So, in nearly every way that matters, an “IoT Thing” is different from a “DR Thing.” So where is the convergence? The convergence comes where your “DR Things” need to coordinate with your “IoThings” and use the network that is common in the home, whatever that is. This is going to mean some commonality between the worlds of “things”.

However:

  • with the IoT world being “high turnover” and the DR world being “low turnover” there is a good chance that some upgrade somewhere along the way will break that coordination. You can do firmware upgrades, but if the fundamental communication platform changes, firmware won’t fix it.
  • Not everything in the IoT universe is using the same kind of network. Look at what Lowes has to go through to cobble together their Iris system. Note that they had to build a complete testing and certification capability for Iris, covering 3 completely different protocols. It reminds me of a line from the Nicholas Cage / Tommy Lee Jones flick Firebirds:[2]
    • Cage: I’m doing it!
    • Jones: But it’s ugly.

What is needed for the Internet of DR Things is a way to make a product that can sit there being ignored for 25 years, while communications technologies change, and still be able to communicate with whatever is in the home at the time.

A lot of people point to WiFi as a solution, since the WiFi Alliance has been careful about backward compatibility. There are problems with that backward compatibility, which I explain elsewhere. The hitch is that the backward compatibility comes at a price.

So, how does the manufacturer of a long-life device make sure that it can keep talking and listening in an IoT world of rapid turnover and changing technologies? Simple: Make it modular.

For those of you not old enough to remember when WiFi was a new thing and people kept computers more than a year or two, laptop computers all had a standard PCMCIA port. When you needed to connect to a network, you plugged in the right modular card, from any manufacturer, over any protocol, and off you went.

We can do the same thing for our long-lived DRThings. There’s a standard for that, you know….

 

 

[1]    I was discussing this article with someone at a conference as I was writing it, and he made a good point: The future of the Internet of Things may be less interaction. Rather than controlling everything with your phone, your home will pretty much know what you want without being told. Everything will act more like an appliance. (For you Star Trek: Next Generation fans, think of Jean-Luc saying “Tea” and the computer knowing that he wants “Earl Grey, Hot” rather than him having to specify it. Every. Single. Time.)

[2]    The big tension in this movie is that Cage’s character is right handed, but left-eye dominant, which makes his eyeballs incompatible with the HUD in an Apache helicopter, which shows all vital information in the right eye, making this a more apt analogy than it seems at first.

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Smartphones and Utility Consumer Engagement Strategies

This week, the Smart Grid Library features a guest writer, Bill Maikranz, Consulting Director of SGL Partners, the consulting group of the Smart Grid Library.

Today the principle model of interactions between consumers and utilities is one of ordering service connection or disconnection, payment questions or arrangements (current and past due), and outage reporting. This is accomplished almost entirely by phone either with agents or automated through Interactive Voice Response (IVR) systems. Everyone has to pay their bills, so these channels are good for bill payments, which sometimes require interactive and realtime negotiations. The IVR is also a good tool for utilities to find out where outages are occurring through the location identification of callers reporting power losses and calls to obtain status information.

Current Smart Grid technologies enable consumers to participate in demand response (DR) programs to modulate electricity usage. For instance, some Smart technologies can automatically control heating and cooling in buildings based on real-time remote or previously programmed controls. These products are gaining acceptance in residential and commercial markets across the USA.  DR programs will trigger increased opportunities for consumer interactions for ad-hoc and planned participation requests.

Beyond that, some utilities are exploring or deploying smartphone applications for residential consumers to check and pay balances. There are several good reasons to offer ease of access solutions: younger bill payers want mobile convenience to suit their lifestyles; not every is in front of a PC every day but everyone uses their mobile phone each day; and any communication that keeps a record of activity on mobile devices means it is easy to track activity.

The common thread of today’s interaction technologies and business processes is based on historical planning and customers reducing costs or assuring that utilities get paid. What will be the business driver or drivers that motivate utilities to encourage more channels of communication with consumers? Will the motivations remain cost reduction and timely payment of bills, or will competition offer new solutions to entice consumers to change providers? What are the drivers or interests of the consumers in these technologies: Convenience? Ease of use? Ubiquity? Or something that engages them in their time and cost of usage?

There is always the financial driver – to either save or receive more money on the part of both utilities and consumers. The other is the more intangible force of doing something because it’s the right thing to do (reduce CO2 emissions, for example) or in general because it’s needed. To make or save money most consumers will do whatever they can to reduce their utility bills. But consumer engagement to do the right thing has to be easy for the consumer. If it’s too hard to engage it can have the opposite effects and result in lower customer satisfaction scores.

With over one billion smartphones deployed in the world today the technology platform answer to all of the above questions is a mobile phone app or channels for communication with utilities other than phone calls. These apps must send information and requests to utilities and receive information back with full consideration of data security and privacy. It’s a key underpinning for utilities to transform their existing customer operations from reactive to proactive consumer engagement strategies.

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Want Green Power? Try Community Choice Aggregation

The recent Business of Local Energy Symposium in Petaluma, California had a rare degree of fervor that isn’t typically experienced at Smart Grid industry conferences about electricity.  Community Choice Aggregation (CCA) or municipal aggregation, is defined in the Smart Grid Dictionary as an energy policy that can promote distributed and/or renewables generation through community-based contracts with electricity suppliers. The community acts as an aggregator, and residents within it are automatically part of that CCA unless they opt-out, which serve to continue the customer/supplier relationship with the regional IOU (investor-owned utilities). The IOU is still responsible for delivering power to the CCA members. This policy is available in several states, including California, New Jersey, Massachusetts, Ohio, and Rhode Island.

Two neighboring counties in Northern California – Marin and Sonoma – have CCAs operating on a county-wide basis. That’s one distinction of how a CCA is different from a municipal utility, which typically operates in conjunction with a political jurisdiction that provides other governmental services such as police, fire, and the collection of taxes to support those services. There are a couple other key distinctions.

First, the CCA essentially “rents” the wires from the utility that owns and operates the distribution grid. The CCA sources its own power, and for CCAs in California, the emphasis is on finding clean renewable sources of power. The distribution utility is still responsible for customer service, billing, service restoration, and all grid operations. In other words, the CCA becomes the default, not-for-profit provider of the sources of electricity.

Second, the CCA is hyperlocal. Common success factors identified by Sonoma Clean Power and Marin Clean Energy – the two CCAs most discussed at the conference (although other states were also included) put an emphasis on local. The power is local whenever possible. The financing to get the CCA off the ground is provided by local community banks. The jobs to develop and maintain local power remain in the community. Even the energy efficiency programs can be tailored to specific zipcodes or neighborhoods, achieving levels of granularity that often elude larger IOU-sponsored programs.

CCAs have traditionally been viewed with trepidation or outright hostility by IOUs. Certainly, the erosion of the customer base has a downside to utility revenues. However, CCAs have some intriguing possibilities – with the assistance of innovations in technology, policy, and finance – for utilities. States are the laboratories for democracy and utility business model revolutions. California is requiring their IOUs to develop Distribution Resources Plan (DRP) proposals that incorporate distributed energy resources (DER) into their plans and grid operations. New York is boldly exploring complete revisions to the existing regulated utility business model. CCAs are interesting models to consider to determine the locational value of DER assets like generation and energy storage, and develop formulas for the monetization of DER assets within distribution grids.

In the future, CCAs could function as autonomous nodes of distribution grids. The CCA acts as the manager of its own node on the distribution grid, and the utility negotiates with the CCA to meet defined performance targets. This arrangement addresses a significant challenge of embedding distributed intelligence and control in distribution grids. By leveraging the local control provided by a CCA, specifically the support of its political and community leadership, the distribution grid operator could gain more predictability about consumer behaviors and asset activity than less organized geographic territories.

CCAs could also morph into autonomous microgrids or include autonomous microgrids within their boundaries. Microgrids that contain combined heat and power (CHP) assets, energy storage, and distributed generation in the form of renewables, electric vehicles (EVs), and demand response (DR) could contribute kilowatts and negawatts to the distribution grid.

CCAs could also be leveraged by distribution grid operators for more intensive energy efficiency (EE) activities that address grid problem areas. Since CCAs have the advantage of local control, they may deliver better results than existing EE programs. New regulatory policies that reward negawatt production on the part of CCAs might encourage more activities here, including recognition (carbon credits) for reductions in CO2 emissions. After all, the cleanest watt is the watt that is never consumed.

These possibilities would require policies that allowed for entities other than existing utilities to have some level of control for selected portions of the distribution grid. CCAs, as managers of DER assets, would also benefit from revised standards that enable bi-directional electricity flows while still maintaining safe grid operations. New technologies and services are also needed. A couple of speakers noted that turnkey arrangements would definitely make it easier for more communities to consider adoption of CCA models.   And finally, the finance community has to be educated on the benefits of CCAs.

CCAs are one interesting way to add more clean renewables or green power to the grid and accelerate as well as supplement existing renewable portfolio standards in every state. Let’s see which state step up to make that happen.

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The Evolution of “Just-in-time” for Utilities

The electric utility sector has been quite successful at managing power on a just-in-time basis. It had to be just-in-time, because since the days of Thomas Edison and Nikola Tesla, there were very few cost-effective ways to store energy, and those options were mostly limited to solutions like pumped hydro. The investments were substantial, and could only be deployed where the ideal geographical and hydrological conditions existed. The workaround was to build more generation that remained in a stand-by capacity until needed for power, voltage, or frequency regulation – a just-in-time scheduling practice. It’s still the workaround today. It has been effective, but it is also relatively crude and expensive, as some generation capacity may only be activated for a few hours per year to address peak electricity usage.

Over time, progressive utilities and regional independent system operators (ISOs) developed policies and practices to schedule the just-in-time production of negawatts – a reduction in electricity usage – in the form of demand response (DR) programs. Negawatts should have equal financial value to kilowatts from a wholesale market perspective, and realistically, the avoided kilowatt (the one you never use) is not only the cheapest form of energy, it is also the cleanest. This was the first evolution in the definition of just-in-time scheduling and generation sources.

There are three Smart Grid technologies that will force another evolution in the just-in-time scheduling concepts and sources of electricity. Clean renewable energy technologies – at utility scale as well as small to large residential and commercial are rapidly proliferating on the grid. Renewables like wind and solar are freely available and carbon-free too, which makes them very attractive for electricity generation sources.

The continued downward slide in solar PV prices and the increase in new market entrants offering affordable rooftop solar means grid parity and the rise of the prosumer in residential and commercial customer categories. The market potential is estimated to be 16 million homes across 20 states in the USA, and year over year growth projections are as high as 22%.

The intermittency of these sources, however, triggered concerns and objections on the part of grid operators. Just-in-time electricity sourced from intermittent renewables is harder to reliably schedule and ensure steady grid voltages and frequency.

There are two complementary technology answers to the intermittency challenge of renewables. One is the deployment of existing solutions that deliver dynamic voltage support on a broader scale and further down and across the distribution grid to manage additional generation sources. The other technology category energy storage that complements or “firms” renewable energy sources. In five years, solutions like the combination of Tesla battery storage with Solar City renewables generation will be matter-of-course, and perhaps even required in certain circumstances.

When you factor in energy storage, the challenge of just-in-time scheduling of renewables across the grid becomes an additive issue – scaling up existing grid management systems to address scheduling of energy storage devices with predictable levels of power for local or grid use. Without energy storage, just-in-time scheduling is instead approached as a predictability issue solved through creation of extremely complicated algorithms that predict solar and wind generation in every possible combination and permutation, and places greater reliance on more generation or DR.

For grid operators, the adoption of one or all of these technologies will force another evolution in their thinking and management practices for just-in-time electricity delivery. It’s just one of many shifts triggered by Smart Grid technologies in the power sector.

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