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.


Great Progress on Smart Grid and Smart City Predictions for 2020

How much can change in a year? When it comes to Smart Grid and Smart City topics, the answer is quite simply – a lot can change. Here’s progress report on my ten predictions about Smart Grid and Smart Cities activity by 2020. The first five are featured this week. You can review the complete predictions here and here, and judge for yourself the quality of my crystal ball.

  1. California hits and exceeds its RPS objective of 33% renewable sources of electricity by 2020 – the most ambitious of all states with this calendar deadline. As of October 2014, the state’s three investor-owned utilities (IOUs) obtained 22.7% of their electricity from renewables, and are on track to meet the 2016 25% milestone. The California Public Utilities Commission (CPUC) projects that solar alone will contribute 42% of the state’s total renewables generation. The state has about 245,000 rooftop solar PV installed now, and by 2017 the aggregated generation from these systems will approach 3,000 MW.
  2. Grid resiliency strategies take priority for investor-owned, municipal, and rural utilities. The Electric Power Research Institute (EPRI) has a number of initiatives in grid resiliency, and their clients are utilities. Governmental, commercial and residential interests build microgrids that are capable of delivering a limited degree of building self-sufficiency in energy. NYSERDA announced the first in the nation NY Prize, a $40 million competition to build microgrids and other local energy grids. New Jersey launched the Energy Resilience Bank – the first public infrastructure bank in the country focused on DER for energy resiliency. This bank is capitalized with $200 million for projects that harden critical infrastructure. Utility support for microgrids is growing as utilities like Con Ed see that the Reforming Energy Vision initiative presents an opportunity to redefine utility business models to accommodate new microgrid product and service offerings.
  3. As utilities consider grid hardening, cities redefine what being a smart city really means. Smart cities aren’t smart if their critical infrastructure relies on fragile transmission or distribution grids. Definitions abound for smart cities, but the lack of consistent standardized frameworks are serious obstacles to development of smart cities. For some states, notably New York, Connecticut, and New Jersey, (states hammered by Superstorm Sandy among other weather events) a city is smart if it upgrades critical infrastructure and deploys distributed energy resources and microgrids for select community buildings and systems.
  4. Consumer intermediation threats abound for utilities. Investor guidance reports released earlier this year pointed out a number of threats to the existing regulated utility business model, and noted the potential for confrontations between tech giants (notably Google and Apple) and utilities in value-added services (specifically energy management services) to consumers. Consumers are becoming increasingly savvy about solar generation, and companies like Solar City and Sungevity have capitalized on these trends to make it easy for consumers to build relationships with non-traditional energy companies.
  5. Standards that define how to integrate or grid-tie microgrids and other standalone generation and energy storage assets for bi-directional electricity flows to utility distribution grids are globally adopted. The existing IEEE 1547 standard currently used for DER such as solar PV requires that these assets must be de-energized if they are tied to the grid and it loses power. While necessary as a safety measure, it defeats the purpose of microgrids remaining up to power critical infrastructure or meaningfully contribute power back to the grid. The Smart Grid Interoperability Panel (SGIP) started Priority Action Plan (PAP) 24 for microgrid operational interfaces. This PAP focuses on information models and interoperability and consistency of signals used by microgrid controllers. Another group called PAP 25 will encourage standards that harmonize financial data, as well as forming a new group focused on Transactive Energy. These are all critical steps to develop the standards that will govern bi-directional electricity and realize the full promise of the Smart Grid, as well as power smart cities.


There’s been real progress for the first five predictions and they are well on their way to realization by 2020. Next week I will review progress on the final five predictions.


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.


The Answer is Location, Location, Location

If this was a game of Jeopardy! you might think the question was about the value of real estate.  You’d be close, but the winning question is what is the basis for the value of distributed energy resources?

This is one of the most important questions that must be answered as more distributed energy resources (DER) are deployed.  The Smart Grid Dictionary defines DER as Grid-connected or standalone generation, energy storage, or negawatt assets that are deployed in the distribution grid.  DER assets can substitute for or supplement grid-supplied power.  According to the Solar Energy Industries Association, the USA is deploying a new solar project every 4 minutes, and as the downward trend of solar project pricing converges with the upward trend of more and cheaper solar financing options, the numbers of solar installations will continue to grow.  The rapid advances made in energy storage technologies will likely follow the same trajectories as prosumers vote with their wallets to gain some degree of energy independence.

Location is an extremely important factor for a potential asset owner or investor to consider in assessing the value of an investment in DER.  It is also an important factor for any entity that functions as a distribution grid operator.  In both cases, it is not the only factor.  That means that one DER asset at a specific latitude and longitude may have very different value to a user, an owner, and a utility.  The use(s) that asset can fulfill will be other important variables in investment decisions.

The state of New York, with its Reforming the Energy Vision initiative is the first to consider changes to the operations of regulated utilities and their business models to address the realities of multiple classes of generation ownership and new expectations for resiliency in grid operations.  The state of California just announced a new proceeding with the end goal of requiring its three regulated electric utilities to create distributed resource plans that leverage distributed generation assets – the death knell for the old business model structured on total reliance on centralized generation.

For example, a rural residential customer at the end of a line that is often disrupted by fallen trees would place very high value in an investment in grid-connected solar generation coupled with storage or some sort of backup generation powered by a fossil fuel.  Today, a utility treats that as a net metering arrangement.  However, if the utility’s grid service to that residence is disrupted, guess what happens to the grid-connected generation?  Complying with IEEE standard 1547*, it is de-energized too, robbing that home of a local renewable source of generation and forcing reliance on that backup generator, an action resulting in increased CO2 emissions.  There’s a very good safety reason for doing this, but it doesn’t make sense from a resiliency perspective. There are calls within the industry to revise this standard to accommodate opportunities for building resiliency into grids, and that would certainly go a long way to achieving the resiliency goals that many states are now developing.

Location will be an exceedingly important decision criteria in the future utility distributed resource planning processes.  In a new DER planning construct, encouraging self sufficiency through utility, third-party or prosumer-owned and operated assets might be an interesting play for a utility.  It would ensure a continued level of service and help in prioritization of restoration services.  It would also factor into resiliency plans, as would utility programs that offered the triple play of generation, storage, and EV described here.  Placement of generation and energy storage at local libraries could enable these buildings to perform as critical infrastructure in disaster situations for cooling, warming, or temporary shelter.  In other situations, utilities might develop DER plans that seek to avoid costly grid capacity upgrades through selective placement of cost-effective DER assets.

The bottom line is that the value of a location will sometimes have very different interpretations for different stakeholders.  The proceedings from New York and California will be interesting information sources to get a good sense of how the Smart Grid will evolve to accommodate and manage vastly more DER assets.


Will US Utilities Offer an Electricity Triple Play?

Recent reports released by UBS, the largest private bank in the world and Citi Research, a division of Citigroup offer compelling investment guidance based on Smart Grid innovation trends that have been described in many previous articles from the Smart Grid Library.  The ongoing trends of decreasing costs for innovative technologies such as solar generation and energy storage; decreasing costs of manufacturing these technologies; and increasing effectiveness/efficiency of these technologies form the basis for many of their observations and recommendations regarding the future of the electric utility ecosystem.  Financial analysts aren’t known for wild proclamations.  That makes it even more noteworthy that UBS writes:  “Large-scale power generation, however, will be the dinosaur of the future energy system:  Too big, too inflexible, not even relevant for backup power in the long run.”  While the UBS report focuses on Europe, it’s reasoning and conclusions have equal applicability to North American markets given the similarities in supply chains as well as technology innovations, and to a lesser extent, policy drivers.  The report mentions that these trends create opportunities for utilities that are given the regulatory frameworks to deliver new services in end customer supply and distributed power generation.

There’s an implied threat in the UBS report – if utilities cannot or do not change their business models, their direct relationships with consumers will be intermediated by new entrants coupled with reductions in electricity revenues.  The Citi Research report spells out that potential for confrontations between tech giants (notably Google and Apple) and utilities in value-added services (specifically energy management services) to consumers.

In North America, these trends enable the emergence of a new class of consumer – the prosumer.  As noted in our previous articles, prosumer actions challenge existing regulated utility constructs by democratizing generation of both kilowatts and negawatts.   Progressive regulatory agencies are taking notice of this erosion of the monopoly position – the New York Department of Public Service published The Reforming the Energy Vision document that starts discussion about how regulators can help utilities adapt to changing technologies and market expectations, and the California PUC is requiring its three regulated utilities to present plans for distributed energy resources and appropriate valuation of DER assets by mid 2015.

Utilities can no longer count on revenue growth based on centralized generation – Citi Research indicates that demand for utility-provided power will flatten or even decrease as a result of energy management technologies, improved energy efficiency and prosumer activity.  The strategy for utilities is to create new services that deliver new revenue.  Taking a page from the communications service providers’ playbooks and experiences, could utilities create a value-added service that combines solar with fixed energy storage (both individual and community) and electric vehicles (EV) into an energy triple play?  It’s an idea floated in the UBS report.  This combination of technologies leverages solar power to “fill the tanks” of the fixed and mobile batteries.  The EV gets charged with solar power creating another potentially-recognizable carbon reduction benefit for utilities.

Many consumers would like to add solar panels and energy storage, but without the hassle of sourcing, financing, deploying, managing, and maintaining the equipment.  A triple play electricity service certainly offers possibilities to address the Smart Grid benefits gap experienced by consumers in multi-family residential and rental situations.  Utilities would be well-positioned to organize and manage these types of services to ensure grid reliability and safety.   Many of them are already experienced in working with contracted third parties who deliver energy efficiency and other demand reduction services.  An extension to generation wouldn’t be a huge stretch.  However, it will take regulatory revisions to create the playing field that allows this type of development.  The good news is that the first regulatory agencies are starting that investigatory process.  Which utility will be the first to make a move into an electricity triple play?