Matthew Smith, Senior Director, Product Management
Matthew has over 20 years of entrepreneurial experience in the energy management, home computer, and consumer electronics industries, most recently at Greenbox Technology, an early leader in customer-facing smart grid applications, where he was head of Marketing and Sales. Matthew earned his MBA from the Presidio School of Management and his B.S. degree in Computer Science from the University of Pittsburgh
Q: We are seeing growing interest in demand response programs. Why is that?
A: For more than a decade, direct load control (DLC) technologies have helped utilities throttle back peak demand. However, these legacy technologies are reaching end-of-life and don’t meet current smart grid standards in terms of capability and security and burden utilities with high overhead.
Pilots of smart grid-based DR programs have shown they can cut peak energy loads significantly, and now these pilots are converting to full deployments – this is a key driver of demand. The Brattle Group recently released a survey of more than 200 energy industry experts who predict U.S. peak demand for electricity will decline by 7.5 to 15 percent compared to what it would have been without demand-management programs.
In addition to these factors, the smart grid is fundamentally changing the way utilities implement traditional DLC and paving the way for new price-based DR programs as evidenced by the OGE deployment. Near term, the smart grid enables utilities to expand existing load control programs to virtually all customers, with no changes in program structure or regulatory approval. With smart grid-enabled DLC, customers get more choice over their participation in load control events, while utilities get granular visibility into who participated and how much load each participant shed.
Q: How have multi-application smart grid networks changed the way that utilities approach their DR programs?
A: The smart grid enables a new multi-vendor approach to demand response (DR) that gives utilities and their customers greater choice – and delivers up to 40 percent more benefits than traditional DR offerings. Utilities such as Oklahoma Gas and Electric are already leveraging their smart grid networks to extend DR to a broad customer base, after studies showed customers with a smart thermostat and a variable peak price rate plan achieved an average 33 percent demand reduction during the on-peak period.
Historically, utilities have implemented vertically integrated, single-vendor DR solutions based on one-way communications. These solutions give customers no choice on whether to participate in a load control event, resulting in low participation rates. Likewise, operators have no visibility into participation patterns or the specific loads shed, making prediction of future events difficult. Nor can operators tell if an individual load control switch is working, which can lead to lower-than-expected load shedding, unnecessary truck rolls, and other negative impacts.
In contrast, a smart grid network provides highly reliable two-way communications, which eliminates the need for separate DR communications infrastructure. Utilities benefit from a cost-effective way to expand load control programs to all customers with no impact on regulatory approvals for existing programs. More importantly, two-way communications enables an entirely new paradigm for DR, increasing reliability and predictability.
Q: What are the key issues to consider when choosing a DR partner?
A: Reaping the full benefits of next-generation, smart-grid based DR requires re-thinking existing processes and a different approach to sourcing and vendor relationships. A key challenge is ensuring all smart grid and DR components work together, end to end.
Depending on how much system integration is required, utilities may need to add staff or hire a consultant to test and validate components and tie into existing DR management systems and other back-office software. Solutions based on standard technologies and open interfaces will reduce problems.
However, utilities can minimize integration issues and maximize their return on investment by selecting one vendor to be responsible for their DR solution. This vendor should provide a selection of plug-and-play components that have been pre-integrated and tested, eliminating deployment headaches while giving utilities – and their customers – mix-and-match flexibility.
When selecting a smart grid DR vendor, look for:
- The ability to take responsibility for end-to-end integration, installation, and DR program design. Successfully spanning this breadth requires a detailed understanding of the end-to-end DR architecture, including back-office systems, the smart grid platform and network, smart meters, and customer HAN endpoints, which may communicate directly to the utility’s smart grid network or via ZigBee or another technology.
- A customer engagement platform designed to keep participation high, especially in price response programs. This platform must support any endpoint, any meter type, and any customer type via mobile phone, web, or and other access method.
- Support for end-to-end SLAs and performance guarantees. Utilities may find it difficult to negotiate SLAs for every component in the DR solution.
- Choice within an integrated solution. The utility must be free to choose among a selection of supported meters, customer endpoints, back-end software including internally developed systems, and other components of the DR solution.
- Experience, with a proven track record of successful smart grid-based DR implementations.