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“BGE investigated advanced metering (AMI) after performing an exhaustive, comprehensive business transformation effort that identified over 60 initiatives that could transform utility operations and customer service. AMI was one such key initiative and considered both transformational and foundational for other initiatives.”

BGE has filed an application with the Maryland PSC for a pilot program to test critical peak pricing, AMI and meter data management (MDM). While the Maryland PSC is supportive of this approach and recently approved BGE’s pilot effort, consumer advocates are not so sure. In UtiliPoint’s experience, it is not unusual for consumer advocates to be wary of time-based rates because of the cost of AMI necessary to support these rates. Advocates are also concerned that any change to underlying rate structures will result in some winners and some losers, even though the rate is designed so the average customer that does nothing to change his energy usage patterns would pay the same under the new rate as he did on the old one. However, the critical peak pricing rate is one of the easiest rates for customers to experience as their first time-based rate because the number of critical peak days is limited per year (usually around 15 or less) and critical periods last only for a limited number of hours on each critical peak day (usually four to six hours). BGE is planning to test various CPP components as part of their upcoming AMI pilot.

Demand Response and Operational Savings Key to a Positive Business Case

For BGE, building a business case for AMI was challenging since the utility had already installed automatic meter reading (AMR) for over 60 percent of their meters. Having already garnered some of the savings normally included in a business case for AMI and MDM (from the investment in AMR), BGE had to dig deeper into its operations. With demand response benefits for customers plus BGE’s operational benefits, BGE has a solid business case to go forward with MDM and AMI. Adding in many intangible customer service benefits further improves the case for AMI.

There is an additional benefit that also helps answer the question, “Why AMI now?” Peak electricity demand is forecasted to continue to increase in the BGE service territory, and with no new generation on the near-term horizon, BGE needs to close the growing gap between supply and demand. BGE is planning to deploy AMI-enabled Critical Peak Pricing, as well as Demand Response Infrastructure (DRI) and Energy Efficiency/Conservation projects, to help close that gap.

BGE issued Requests for Information (RFI) in November 2006, and based on the responses from the AMI and MDM vendors, will issue RFPs to a smaller number of vendors in May 2007. The plan is for BGE to select an MDM and AMI/DRI vendor(s) for the pilot as well as a system-wide rollout. BGE is one of a number of large utilities moving away from AMR to improve outage management, distribution planning, customer service, and support demand response—Northeast Utilities is considering a similar move for its Connecticut service territory, for example. Energy East and Consolidated Edison of New York are also considering their options for demand response and AMR/AMI.

AMI Requirements

UtiliPoint asked specific questions of BGE’s requirements for AMI and MDM in an interview with Mr. Testa. Since the business case depends on demand response, their requirements include features for demand response as well as utility operations. In terms of the requirements that UtiliPoint is seeing on a regular basis in RFPs for AMI, BGE’s requirements are similar to other utility requirements. Several requirements of note are:

• The ability to remotely upgrade firmware on endpoints—this is a relatively new capability offered by a variety of AMI vendors, and is considered vital by many utilities to support home area networks and to avoid site visits for upgrades or changes
• The ability to use the AMI network to send price signals and/or load control signals to equipment in or around the home
• ZigBee communications in endpoints—for supporting demand response and in-home networks
• Memory storage in endpoints for approximately 32 days of interval data—utilities are including this requirement because they plan on using interval data for billing and want to avoid estimates if at all possible
• BGE has an interest in using the AMI network for distribution automation and distributed generation control in the future
• Open standards protocol is most important for BGE for in-home networks because there may be a variety of vendors involved in supplying devices that communicate via in-home networks, and BGE is hoping customers will purchase ZigBee enabled appliances as they become available
• BGE needs to bring back both gas and electric hourly data over the AMI network, and a small portion of their service territory is gas-only
• BGE plans to integrate demand response communications for smart thermostats and load control devices over the AMI network
• BGE does not plan on retrieving meter data more than once per day for residential customers on a regular basis (they want to the option to perform on-demand reads where appropriate) except for some Industrial and Commercial gas customers
• BGE plans to provide customers online access to their hourly interval usage as of the day before
• BGE would like to be able to perform remote electric connect/disconnects for service order work in highly transient areas

All-in-all, BGE’s AMI requirements are very similar to those of SCE in California. Both utilities have combined operational savings with demand response benefits in their business cases, and both utilities intend to use the AMI network to assist customers in responding to time-based rates via the in-home ZigBee network.

MDM Key to Achieving AMI Benefits

Most utilities today are planning on installing MDM prior to rolling out AMI and BGE is no different. When asked why it is important to invest in MDM, Mr. Testa said: “I don’t see how you could achieve significant benefits without implementing MDM as a leading component.” He continued: “We want to achieve enterprise-wide business benefits and we envision MDM as the key to achieving the benefits we are claiming in our business case. In addition, MDM should allow us to reduce our CIS footprint, providing us more business flexibility.”

BGE plans to perform validation, estimation, and editing (VEE) in MDM, and also to replace several systems in use today for managing their Commercial and Industrial (C&I) customer interval data, such as MV-90, Metretek, Itron’s Power Billing System, MV-Web, etc. When AMI and MDM are installed, BGE estimates it will require ten full time employees to operate the MDM system. Mr. Testa also estimates that the most complex integration will be between the MDM and outage management system.

It’s Time for Time-based Rates

Utilities, regulators, and Congress are moving toward time-based rates as the preferred rate plan for all customers. Pilot and on-going programs at various utilities through North America have provided good results—customers reduce demand when prices were high or rebates were offered, and customers prefer time-based rates after experiencing them first-hand. Customers may still be a little leery of the change to time-based rates because it’s different, but customers have adapted to different prices for hotel rooms and airline tickets depending on the demand, natural gas price volatility, gasoline price fluctuations, and complex cell phone plans. It’s time for consumer advocates to weigh in on how to implement time-based rates equitably—the longer we wait to reign in volatile electric wholesale prices, the more average costs will rise.