A decade of demand-response growth has generated benefits and created new challenges.
Las Vegas, Nevada, has a well-deserved reputation as the embodiment of excess consumption, from its myriad buffets to its lavish pool parties. Las Vegas also is gaining a reputation for shaping how and when energy is consumed through its innovative use of demand response (DR). The large-scale deployment of DR has brought operational challenges to NV Energy, the investor-owned utility that serves the Las Vegas valley. NV Energy has met these challenges with practical, repeatable solutions.
Thanks to DR, NV Energy has the ability to reliably reduce more than 140 MW of residential and small commercial air conditioner load. There are more than 70,000 air conditioners in the Las Vegas valley at more than 50,000 homes of customers who are currently participating in a voluntary DR program. When the outdoor temperature rises to between 104°F and 108°F (40°C and 42.2°C), a pager signal can be sent to some or all of the 70,000 air conditioners. Once signaled, the air conditioners increase their setback by 4°F (2.2C°), causing them to ramp down consumption, thus dropping the system load by more than 140 MW. When called upon, these DR curtailments produce measurable, consistent reductions in demand on the distribution system.
NV Energy did not grow to 140 MW of DR overnight. NV Energy has been growing its base of participants in its air conditioning load-management program for nearly 10 years. As a consequence, the utility manages a portfolio of DR control devices from a cross-selection of vendors (for example, Carrier, Honeywell and so forth). Each vendor has its own proprietary software headend, which resides in a corporate data center or on the cloud and communicates to the DR device using the manufacturer-specific language of the device.
Keeping the data in each software headend updated is a challenge. For example, when a customer leaves a DR program, it is critical to update the software headend to stop sending dispatch signals to curtail consumption to the customer's DR device. The data can be updated manually through a graphical user interface within the software headend, or it can be updated automatically using a software interface. However, updating the data manually is costly from a labor perspective and error-prone.
A second challenge to maintaining a portfolio of DR devices is managing the wireless communications systems used to signal the curtailment. DR devices cannot be dispatched if the communications system is malfunctioning or unavailable. Communication with stand-alone thermostats and load-control switches is done through a pager network. Home area network (HAN)-based DR devices, such as in-home displays (IHDs), are controlled over the Internet. There are plans to communicate with IHDs using the meter network later in 2012. All of these communications systems experience a diversity of issues that must be monitored and managed for the dispatch signal to be sent out and, more importantly, received whenever needed.
A third challenge related to DR device portfolio management is losing communication between devices in the HAN. Obviously, this challenge is unique to DR control through a HAN and is not relevant to the stand-alone thermostat or load-control switch. For example, a meter can stop communicating with an IHD, thus causing the IHD to stop functioning correctly. The IHD also can lose connectivity with other HAN devices, such as a thermostat or lighting control. When this happens, the functionality of the device can be reduced in some way. For example, when disconnected from the IHD, the thermostat may lose the ability to change program set points. This challenge is important to manage from a customer's perspective. Consequently, the connectivity between devices in the HAN must be actively monitored and managed.
A fourth and final challenge related to DR device portfolio management is reporting. NV Energy has significant reporting requirements both to manage the operations of DR programs as well as program oversight. For example, NV Energy is required to periodically report data to the Public Utilities Commission of Nevada regarding the cost-effectiveness and efficacy of its DR programs. To show that building DR capacity is more cost-effective than building a peaker plant, data must be assembled and processed from many disparate systems. Aggregating and providing operational and regulatory reports from many different systems is a challenge.
A DR resource does not have value if it cannot be reliably dispatched. To be dispatched as a reliable resource, DR must meet the challenge of developing confidence in system or grid operators. Operators must have confidence the DR resource will behave as forecasted. To create and maintain operator confidence, an accurate forecast must be available each day for every dispatch algorithm so the operator knows exactly how the DR resource will impact the system load.
A dispatch algorithm might be, for example, to dispatch all air conditioners at 4 p.m. and bring them all back to normal at 6 p.m. An alternative dispatch algorithm would be to dispatch a subset of the air conditioners at 3:30 p.m., another subset at 4 p.m. and so on. These different dispatch algorithms produce different load shapes on the system grid and each algorithm has a different cost per megawatt-hour.
A second element of providing operator confidence is a real-time feedback loop that a DR resource is reducing demand as expected. Unfortunately, most metering systems transmit data too slowly to be used to provide near-real-time feedback. This feedback can be provided using supervisory control and data acquisition (SCADA) because this is collected fast enough; the data updates every 1 sec to 60 sec, providing near-real-time feedback.
The Customer Side
DR programs also introduce customer service and field service challenges. NV Energy customer service representatives (CSRs) are trained to enroll a customer in a DR program or to assist with other DR customer service inquiries. Customers may call CSRs regarding the operation of their devices, DR program rules or the dispatch of field services staff for repairs. Tracking notes for each customer interaction is a challenge, as is managing customer service request queues, such as scheduling a repair service request with a customer.
Once a customer enrolls in a DR program, a field services vendor, managed by NV Energy, installs an IHD and a programmable communicating thermostat (PCT) at the customer premise, configures the IHD and PCT based on customer preferences and demonstrates basic device usage. Assigning and tracking field work, or work orders, is a significant challenge further complicated by the fact NV Energy uses multiple field services companies. One such complication is that NV Energy must have processes in place to assign field services work to the least-cost, highest-quality company that has availability matching the customer's availability.
The solution to many of these operational challenges can be provided by change management and appropriate software. After a careful review of existing in-house systems, NV Energy published a request for proposal in late 2009 to purchase software that would meet these requirements. There were no solutions on the market that met the requirements out of the box.
However, UISOL, now part of Alstom, had a software product developed for the wholesale energy market (usually independent system operators and other power pool entities) that had similar features needed by NV Energy. So, NV Energy partnered with UISOL to implement a commercial product for the retail utility market. That product is called the Demand Response Management System (DRMS) by NV Energy and branded as DRBizNet by UISOL. The product was implemented using funds from a smart grid investment grant that was part of the American Recovery and Reinvestment Act of 2009.
The DRMS reduces the impact of the challenges previously described. Specifically, the DRMS integrates with software headends to keep data synchronized between systems, monitor DR communications and provide reports. It provides forecasts and near-real-time displays to system operators. The DRMS also manages the activities of the DR CSRs and field service contractors using service request queues and work orders.
The first production release of the DRMS was in October 2011. Being a prudent utility, NV Energy first released the DRMS to a limited audience of employees. The limited release is now about to be expanded to include a few hundred customers. If that goes as expected, plans are to install up to 3,000 new devices per month throughout the rest of 2012.
An Exciting Time
NV Energy's leadership in the DR market will continue to push the frontiers of what is feasible. In 2011, NV Energy was able to reduce its system operating reserve requirements because of DR. Going forward, the utility expects to improve the value of DR by optimizing dispatch algorithms, paying market-based incentives and expanding the footprint of devices that can participate in DR curtailments to include pool pumps, variable-speed motors, batteries, lighting controls, smart appliances and the like.
Many other utilities are now interested in DR because of the influx of smart grid projects. It is an exciting time to be in the DR field.
Victor “Tor” Garman (email@example.com) is a project manager at NV Energy with a focus in demand response and distributed energy. He has worked in the utility industry for seven years and is a certified energy manager. Garman received a bachelor's degree in mathematics and computer science from Vanderbilt University's school of engineering in 1996.
Editor's note: This material is based upon work supported by the Department of Energy under Award Number DE-OE0000205.
Carrier | www.carrier.com
Honeywell | www.honeywell.com
NV Energy | www.nvenergy.com
Public Utilities of Nevada | pucweb1.state.nv.us/pucn
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