Demand response programs to date have largely relied on a labor-intensive approach that has required operators in different customer sites to manually turn off lights, HVAC equipment, and other energy consuming systems to control peak demand and balance loads on the grid.  Automated demand response (Auto-DR) systems have become an important alternative to conventional DR by automating the communication and dispatch systems to respond to event and price signals from a utility, grid operator, or a curtailment services provider (CSP) – often in minutes or even seconds.  Although it has already been used by the utility industry for many years, it has not been widely deployed. However, with the upcoming launch of a non-proprietary, open communications standard for Auto-DR, referred to as OpenADR, this situation is likely to change.

Developed by the Demand Response Research Center (DRRC) of Lawrence Berkeley National Laboratory (LBNL), OpenADR is designed to be a low-cost, speedy, and reliable communications infrastructure that would allow utilities and grid operators to send DR signals directly to building automation and control systems on customers’ sites, using a common language and existing communications technology, such as the Internet.  It was successfully piloted in 2005 by Pacific Gas & Electric (PG&E), and in 2007, the California Public Utility Commission mandated its commercial use by the state’s three main investor-owned utilities (IOUs).  In 2009, OpenADR 1.0 was donated to the standards organization, Organization for the Advancement of Structured Information Standards (OASIS) to be developed into a formal specification, i.e. OpenADR 2.0.

The standard, says Lawrence Berkeley’s Girish Ghatikar, the secretary for the OASIS technical committee that finalized version 2.0, “will enable scaled deployments and interoperability within Smart Grid technologies, thus reducing the cost of DR technology enablement and customer adoption.”

OpenADR 2.0 is expected to be ready for full-scale implementation in the coming months.  It is currently the only existing open data model to bridge communications between a utility and control systems in commercial, industrial and residential facilities.  It has been used by a number of utilities and independent systems operators in the U.S.  While California has been the primary state for OpenADR implementations, it has also been adopted by other U.S. utilities to enable their Auto-DR programs.  So far, OpenADR has been either piloted or implemented by Seattle Power & Light, NV Energy in Nevada, City of Tallahassee in Florida, Bonneville Power Administration in Oregon, and most recently Hawaiian Electric Company in Hawaii, which is undertaking a pilot with Honeywell to demonstrate how DR can help integrate intermittent renewable energy into the grid.  It has also been tested by software developers in Canada and Spain, and is currently being piloted by Honeywell for utilities in China and the United Kingdom.

The introduction of a uniform standard in the Auto-DR market will help lower the cost of technology as well as the services, including maintenance, associated with these tools.  So far, more than 60 building controls vendors have developed products with OpenADR. Second, it will improve the reliability and predictability of Auto-DR because using an Internet-based interface and communication standard will eliminate the reliance on person-to-person interaction between the utility’s personnel and facility management. Third, standardizing a message format will increase the interoperability, efficiency and reliability of DR systems. As a result, both the National Institute of Standards and Technology (NIST) and the Federal Energy Regulatory Commission (FERC) have endorsed OpenADR as a key smart grid standard. And the OpenADR Alliance, a nonprofit organization, has been created to promote the development, adoption and compliance of the standard across the utility industry.  “Through this member-represented organization, the OpenADR Alliance, and significant support, OpenADR 2.0 has certainly the potential of accelerating Auto-DR adoption across the globe,” said Barry Haaser, managing director of the OpenADR Alliance.

It seems only logical that demand response and energy efficiency should go hand-in-hand.  Both spring from concerns about energy usage and aim to accomplish the same outcome, i.e., energy reduction.  But reality doesn’t always follow logic.

Instead, often the two concepts are pursued by different departments and individuals within a utility.  What’s worse, the two organizations in some cases do not even speak to each other. Although demand response contributes to lower energy use, its main goal is not to achieve energy efficiency.  Rather, it aims to reduce the use of electricity on a temporary basis at a specific time (i.e., in times of peak demand, typically within hours or minutes) in order to balance the grid to avoid power shortages.  By contrast, the main objective of energy efficiency or conservation programs is to reduce electricity consumption on a long-term basis with the help of various energy efficiency measures.

Still, there is a strong interrelationship between demand response and energy efficiency.  In the residential sector, demand response is typically a standalone program that aims to achieve 1 kilowatt (kW) and perhaps up to 2.5 kW of energy reduction from the average household – sometimes through a smart thermostat or a load-control switch on an air-conditioning system.  This often requires incentives from the utility.  But when demand response is integrated with behavioral-based energy efficiency programs to raise customers’ awareness about energy conservation, interest in participating in demand response programs improves significantly.  According to Tendril, “When the ground is first seeded with behavioral-based efficiency programs that begin the energy awareness cycle of consumers – by delivering personalized, relevant information about energy use, the ability for them to set an energy savings goal and measure their progress towards that goal in an active learning environment – consumers can then opt in to more complicated energy management programs that include demand response.”

It is quite possible that the demand response and energy efficiency departments have more in common than they realize or are willing to admit.  Better-informed customers may be the link to integrate the two energy efficiency and demand response camps together.  By educating consumers about the benefits of participation and improving their access to detailed data about their energy use and performance, both groups will essentially seek to achieve the same goal – an educated, well-informed and motivated energy consumer.  Indeed, some utilities have already begun to take steps to bring the two initiatives closer together.  For example, industry sources tell me that some have recently appointed a director to head both the demand response and energy efficiency programs in order to coordinate efforts to benefit both and to leverage each other’s skills and know-how.  Instead of working at cross purposes, utilities should make every effort to create synergies between the two organizations so that they can truly work in unison to achieve new and improved energy efficiency and demand response behaviors.

The news that Comverge has accepted a private equity buyout of roughly $49 million does not come as a surprise to anyone who has been watching this company over the last couple of years and hearing rumors about its financial and resource problems.  According to The Wall Street Journal, a recent filing with the Securities and Exchange Commission reported that Comverge’s independent auditor had expressed serious doubt as to whether the company could continue to operate due to lack of cash flow and debt-related issues.

The buyout by the private equity firm H.I.G. Capital will address these immediate financial and liquidity problems, allowing Comverge to continue its operations and to execute its strategic plans.  H.I.G. Capital is offering Comverge shareholders $1.75 a share well below its 52-week high at $5.09.  The Comverge board has approved the definitive agreement, which enables the company to seek other offers during a so-called 30-day “go-shop” period. As of the close of trading on March 26, the stock was up at $1.79 indicating that investors are expecting a higher offer.

Despite its financial woes, Comverge still runs a viable demand response (DR) business.  As one of the largest curtailment service provider (CSP) and outsourcer of residential DR programs in the country, Comverge had $136.4 million in annual revenues in 2011, representing a 14% increase from the previous year’s revenue of $119.4 million. Moreover, the company added more than 800 new megawatts (MW) under management and increased adoption of its enterprise software platform, IntelliSOURCE, with 22 utilities.  Comverge was also chosen by Gulf Power to double the country’s largest residential dynamic pricing program from approximately 8,000 to an expected 16,000 participants over the next four years.  Perhaps most important was Comverge’s recent $27 million international deal with Eskom, the largest electricity provider in Africa, to create and co-manage its first open market for DR resources.

Despite these achievements, which resulted in the company’s best performance ever, it was apparently not enough.  As Comverge’s president and chief executive officer, R. Blake Young, noted on March 15:  “Despite the strongest operational and financial performance in the company’s history, we still require capital to fund our operations, and the Board and management are working diligently on strategic alternatives for obtaining the required capital and financing.”

Pike Research does not believe that Comverge’s financial issues mean that the DR market is in trouble.  Some observers have claimed that the major CSPs are reaching their saturation level, having to seek new market opportunities in order to continue to grow their business. This does not indicate a lack of interest among end-users to participate in DR programs.  Indeed, both Comverge and EnerNOC have been able to increase their customer base as well as MW under management in 2011.  Although it may become tougher to recruit new customers once the low-hanging fruit is picked, there is still ample opportunity in the United States and in other countries to grow a DR business.  Let’s not forget that DR is more than just curtailing loads during peak events; it can accomplish a lot more as it addresses all the different ways that a utility, grid operator or CSP balances supply and demand of electricity by responding to the needs of the grid.  And with the increasing application of automated DR (Auto-DR) by utilities around the world to make it more cost-effective, more reliable, more predictable, and easier to  execute demand response than ever before, the growth prospects look strong.

Everyone is familiar with prepayment, especially when it comes to prepaid wireless phone services.  But, in the United States, the concept of prepayment for electric services is not yet well understood. By contrast, electric prepayment is a common practice in many other nations, especially in the United Kingdom, Ireland, South Africa, and many parts of Asia Pacific.  In South Africa, for example, over 50% of the residents use electric prepaid programs that are offered by its major utility, Eskom, the largest producer of electricity in Africa and among the top seven utilities in the world in terms of generation capacity.  With the oldest prepaid program in Europe, the United Kingdom has approximately 14-15% of all households on an electric prepaid plan – usage of which, according to Ofgem, increased by 5% in 2010.  Recognizing that these types of services represent an essential part of the electric metering market, the U.K. authorities have mandated that the nation-wide roll-out of smart meters will include a prepayment functionality. 

In the United States. some observers estimate that less than 10% of the 3,200 utilities in the country offer prepaid electric services.  Texas, Arizona, Oklahoma, Vermont, State of Washington and a few states in the Southeast have been frontrunners, especially among cooperatives and municipalities. The large independently-owned utilities (IOUs) have, on the other hand, been reluctant to adopt prepaid plans – in part because they are more constrained than the other utilities to comply with state utility commission rulings.  As a result, the overwhelming majority of prepaid programs in the country are run by smaller utilities, frequently serving rural and low-income communities with many transients like college or university students. 

The oldest and best known prepaid program is the Salt River Project (SRP) in Phoenix, Arizona, which initiated its prepaid program – the M-Power Program – in 1993.  In 2011, its program enrollment rose by 16% to a total of 125,000 participants. This is an especially remarkable achievement because SRP does not advertise its prepaid services.  Oklahoma Electric Cooperative (OEC) offers another, albeit younger, example of a prepaid program with somewhat more than 10% of its total customer base currently enrolled as prepaid participants, i.e. about 5,122 customers. Every resident is eligible to become a participant in this program, though it is most popular among its student population.

Barriers to electric prepaid services have primarily stemmed from objections from consumer advocacy groups, public utility commissions (PUCs) and regulatory agencies.  One fear has been the possibility of utilities shutting off power to certain “disadvantaged” customers.  In November 2011, the Iowa Gazette ran an article pointing to the threat of electrical disconnections from prepaid programs for vulnerable residents, such as the elderly, individuals with disabilities or life-threatening medical conditions.  Another objection has been that prepaid programs might encourage low-income customers to disconnect electric service in order to keep money available for other necessities like food and clothing.  In some instances, PUCs have accused utilities of targeting low-income consumers for prepaid programs, fearing that they are stigmatizing these consumers.  Some time ago, these concerns may have had some validity, but they have begun to make less sense today as prepayment is increasingly becoming the preferred payment method among consumers in a wide variety of situations, especially among mobile phone users. 

In addition, there is growing evidence that the benefits of electric prepaid programs far outweigh any of these concerns.  Customer surveys have consistently shown high customer satisfaction – around 80-90% of prepay customers are happy or very happy and would recommend the program to others.  Prepay consumers tend to feel that they are in control of their electricity bill and can better manage their budget by being able to choose when, how, and what they pay each month for their electricity. As one prepaid customer put it:  “It is easier to pay $25 every week than $100 at the end of every month.”  Because prepaid programs encourage consumers to pay attention to their use of electricity, many utilities, such as SRP and OEC, have been able to demonstrate improved energy efficiency behavior among their prepay customers.

Utilities also benefit from prepaid programs, through better revenue protection and cash flow.  With a traditional post-pay system, some consumers may owe hundreds or even thousands of dollars before they are disconnected, whereas with prepayment, a much smaller amount of less than $50 is owed before they are disconnected.  For example, at Brunswick Electric Municipal Corporation, reduction in write-offs has averaged between $1,000 and $2,000 per month. Moreover, in a prepaid system utilities can achieve significant administrative cost savings by not having to support resources to track and collect deposits for initiating electricity for customers, to send monthly bills and to collect reconnection fees from consumers that have been disconnected.  In many cases, electric prepaid services are a win-win. 

The growing realization of the value proposition of such services, together with the increasing deployment of advanced smart meters that will greatly facilitate prepaid programs, has become a powerful incentive for U.S. utilities to seriously consider adoption of such plans.  And unlike programs in the past, which frequently targeted low-income residents, the prevalent goal today is to make these programs available to every utility customer.  As better customer choice becomes a key strategic focus among utilities, electric prepaid services will eventually become the new norm – even in the United States.