The demand response (DR) market is evolving from curtailing electrical demand during peak periods (typically only a handful of hours per year) to continuously balancing supply and demand for power on the grid.  Some observers refer to this new development as DR 2.0, while others are calling it “fast DR” or “grid balance.”  One of the major drivers is the need for ongoing adjustment to adapt to small, frequent changes in the power system on a second-by-second basis.  This becomes more imperative as more and more utilities have to incorporate intermittent renewables like wind and solar power into the grid, typically by adding ancillary or frequency regulation services that match total generation on the system with total demand on a second-by-second basis.

The major stakeholders, such as the Federal Energy Regulatory Commission (FERC), grid operators, and aggregators, are paying heed and are updating their policies and procedures to support the increased use of grid balancing.  For example, Ontario’s Independent Electricity System Operator (IESO) issued an RFP in August 2012 for non-generation suppliers to provide grid balancing.  It sought proposals from multiple vendors to procure 10 megawatts (MW) of regulation services from alternative sources, such as dispatchable and aggregated DR and storage technologies, including batteries and flywheels.  Similarly, New York ISO (NYISO) provides retail customers that are able to meet telemetry and other qualifications with an opportunity to bid their load curtailment capability into the market through regulation services.  These efforts have been given a boost by FERC, which released a new rule in October 2011 that requires grid operators in organized markets to compensate frequency regulation services based on actual services they provide.

Inherently Flexible

Several vendors have stepped forward to champion grid balance, including ENBALA Power Networks, which won IESO’s RFP and has been operating and delivering regulation services to the market served by the regional transmission operator, PJM Interconnection, for over a year.  ENBALA’s intelligent platform captures storage that already exists in the power system by aggregating available demand-side storage, by making small automated adjustments in the electricity use of equipment at commercial, institutional, and industrial sites, to deliver real-time flexibility back to the grid.  Another vendor, Calico Energy Services, recently announced that it’s licensing a set of technologies from Battelle called Grid Command Active Demand Management (ADM).  With this enhanced software capability added to its Energy Intelligence Suite (EIS), a hosted energy management platform, Calico will help utilities execute DR automatically, using two-way communications.

Undoubtedly, other vendors will emerge to provide fast DR as they begin to realize that many electrical loads, such as aerators, pumps, and chillers, have the inherent ability to be flexible without adversely affecting operating processes or changing the overall energy consumption of the system.  Fast DR represents not only a significant market opportunity, but also the next frontier of demand-side management.

Surprisingly, only a handful of utilities have combined demand response and energy efficiency into a unified program.  Some examples of combined programs include: Georgia Power, Sacramento Municipal Utility District (SMUD), Austin Energy, Kansas City Power & Light, and Long Island Power Authority.   

However, efforts to merge DR with energy efficiency are rising as utilities realize the benefits of achieving synergy between them.  Better coordination and tighter integration of DR and energy efficiency would lead to greater cost effectiveness, mainly because of more efficient allocation of resources among program providers.  Consumers would likely welcome a packaged approach to manage their energy use, so they don’t have to deal with two different programs.  An integrated program with a coordinated marketing and education effort could also increase DR market penetration.  In fact, when DR is coupled with behavioral-based energy efficiency programs to raise customers’ awareness of energy use, participation in DR programs tends to improve.  Similarly, by blending DR with efficiency utilities can deepen their energy efficiency initiatives.

That’s why the recent announcement by Honeywell and Opower that they will team up to provide an integrated Energy Management platform is worth noting.   This platform combines Honeywell’s two-way communicating, Wi-Fi-enabled thermostat (built on the VisionPRO platform) with Akuacom’s demand response automation server (DRAS), embedded with a demand response management system (DRMS), and Opower’s interactive, cloud-based software tool to help consumers manage their energy use via the Web or a smartphone.   Jeremy Eaton, vice president and general manager of Honeywell Smart Grid Solutions, explained in a statement:  “We’re bridging the gap by providing mobility, relatable energy information, precise control, and other features customers want so utilities can reach deeper levels of connectivity and participation.”

The platform is designed to enable automated DR (ADR), using the OpenADR 2.0a specification, for almost all residential heating and cooling systems through Honeywell’s Wi-Fi-enabled thermostat.  All thermostats are fully programmed upon installation according to the consumer’s preferred temperature set points and schedules, driving energy conservation and reduced air conditioning or heating use.  In addition, the platform uses measurement techniques to demonstrate ongoing energy savings that utilities can use in meeting their required annual efficiency goals.   Five utilities are piloting the platform, including Pacific Gas & Electric (PG&E), which is currently testing it with about 500 residential consumers.  Its success could help blur the sharp lines between DR and energy efficiency.

Hurricane Sandy, which brought devastation to New York, New Jersey, and large sections of the East Coast, resulted in significant losses to businesses in the area that are home to 85 Fortune 500 headquarters experiencing power outages for many days, if not weeks.  The total number of business establishments was nearly 750,000.  With more severe storms, flooding, and droughts predicted, companies are taking steps to reduce their own carbon emissions.

According to a recent supply chain study by Accenture in collaboration with the Carbon Disclosure Project (CDP), about 51% of the respondents in the study of 2,415 companies stated that extreme weather is already having an adverse effect on their business or is expected to in the next 5 years.  Nearly three-quarters (73%) of the companies that have implemented carbon emissions programs believe that climate change presents a risk to their operations.  This sense of business risk is a major catalyst for businesses to take action to mitigate their carbon footprint –a much stronger driver for carbon emission reduction than any government policy and regulation.

What’s most disturbing about the findings of this research, which focuses on corporate supply chains, is the significantly lower level of commitment among suppliers to reduce emissions compared to their clients or purchasing companies.  For example, only 38% of the suppliers have adopted carbon emission reduction targets, compared to 92% of their purchasing organizations.  Although 69% of their clients have taken action to reduce their carbon footprint, only 27% of the suppliers  have done so.  Similarly, only 29% of the suppliers versus 63% of their clients have been able to achieve year-over-year carbon reduction results.

This chasm between companies and their suppliers highlights the challenge of being able to manage climate risk in the global supply chain.  Unless businesses can influence their suppliers to follow their example, they will not be able to achieve their overall emission reduction goals.  As Accenture points out in this report, it’s essential for businesses – like Starbucks and DuPont, which have already embarked on programs to reduce carbon emissions across their products’ full lifecycles –  to actively engage suppliers in a discussion about climate change and the potential risks it entails. With increased awareness and understanding of these risks, suppliers are more likely to implement carbon reduction.

According to the latest 2012 report on Demand Response and Advanced Metering from the Federal Energy Regulatory Commission (FERC), based on survey data from almost 2,000 U.S. utilities, grid operators, power marketers, state and federal agencies, and other demand response (DR) providers, the DR market continues to grow at a solid pace.  Examining both potential and actual peak load reduction, the FERC finds that the reported potential peak reduction is 66.4 megawatts (MW), or about 9.2% of U.S. peak demand and an increase of 25% since the same survey was conducted in 2010.  In terms of actual peak reduction, the FERC reports a total of 20.3 MW, an increase of about 27% from the 2010 survey.

Every customer category reported an increase of peak reduction from 2010, but given the amount of load that commercial and industrial (C&I) customers are able to curtail during a DR peak event, C&I is by far the largest – it’s 3 to 4 times larger than the residential sector – and the fastest growing customer segment (31% since 2010).  For example, the Oklahoma Gas and Electric (OG&E) time-of-use (TOU) program has expanded considerably during the last 2 years, adding nearly 900 MW of DR capability from its C&I customers between 2010 and 2012.

Of the total reported potential peak reduction, 80% can be attributed to four major DR programs:

• Load as a capacity resource (mostly C&I customers) – 29%
• Interruptible load (mostly C&I customers) – 24%
• Direct load control (mostly residential customers) – 15%
• Time-of-use  (mostly residential customers) – 12%

With the exception of TOU, which has been in existence for many decades in the United States, the newer price-based DR programs, such as critical peak pricing (CPP), real-time pricing (RTP), and peak time rebate (PTR), have not yet achieved a significant penetration in the market.  According to the report, these three schemes only account for 3.8% of reported potential peak reduction.  It is also noteworthy that a very small percentage of the study respondents (about 2%) are reporting peak load reduction from the most advanced types of DR, such as ancillary (e.g. spinning reserves) and regulation services.

This report indicates that the U.S. DR market continues to be led by more conventional programs that focus on peak load reduction.  The market appears to be shifting very slowly toward more sophisticated programs, such as dynamic pricing schemes or even ancillary and regulation services, that focus primarily on load balancing when the grid is experiencing stress from either too little or too much power ‑ from intermittent renewables, for instance.