The country’s demand for electricity continues to grow.To supply it, America’s electric utility companies are building more generation and transmission. But at the same time, with industry structural change, rising costs, and the need for even greater environmental protection, the industry recognizes that it must increase its commitment to customer energy efficiency as well.A crucial building block for a more energy-efficient future will be AMI —advanced metering infrastructure.
The nation’s electric utility companies are now creating business models and regulatory mechanisms that will help make AMI a widespread reality. This is part of a broad-based campaign to enable energy efficiency to become a viable, sustainable business for utilities and other energy providers, Digital “smart” meters, two-way communication capabilities, automated controls, and sophisticated data management systems are rapidly improving the potential for information exchange between electric utilities and their customers.When coupled with innovative approaches to ratemaking and rate design, AMI can increase the industry’s portfolio of resource options to meet the country’s growing demand for electricity.It can more closely align regulated retail markets with competitive wholesale markets to deliver more cost savings.And it can become the foundation for a dynamic partnership between utilities and their customers to achieve greater reliability, power quality, environmental protection, cost control, and risk management.
Advanced Metering Infrastructure
Advanced meters, or meters that are not visually read by a meter reader, have been around for decades.Some automated meter reading (AMR) systems consisted of a receiver that was mounted in a vehicle.As the vehicle was driven through a neighborhood, the data from the meters was read.These AMR systems reduced meter-reading costs, accelerated cash flow, and reduced the need for estimated bills.But once the meter data arrived at the utility, it followed the same path as data collected manually.
With an AMI, a utility can read almost any meter at any time, but its value extends far beyond simple meter reading.An AMI communicates through a fixed network that is in place all the time—it does not move.The meters are equipped with communication capabilities, usually radio or power line, but sometimes telephone, digital cellular or satellite.Meters using radio-based systems exchange information with data collectors located throughout the distribution system.Meters with power-line based systems communicate with data collectors located at substations.Both types of systems can in turn communicate directly with a utility’s billing system, customer information system, and its outage management system.
An AMI’s two-way communication capabilities give utilities and customers the potential to use time-based rates—such as time-of-use, seasonal, interruptible, and real-time rates—across the entire customer base.The benefits that arise from this capability are many and include:
AMI was given a boost by Congress with the passage of the Energy Policy Act of 2005 (EPAct).EPAct amended the Public Utility Regulatory Policies Act (PURPA).PUCs and the Boards of Directors of unregulated utilities were directed to take a fresh look at a number of issues, including a wide variety of time-based rate structures, and alternative rate forms, and net metering.
The 2005 revisions to PURPA also require PUCs and unregulated utilities to consider whether it is appropriate to create an AMI. If it is deemed appropriate, the PUCs may also set an advanced metering standard for utilities.Appropriateness was defined to mean whether the costs and the benefits to both the customer and the utility balance each other out.
Electric utilities have now begun moving toward creating an AMI.Last summer, Pacific Gas & Electric (PG&E) announced its plan to install 9.3 million advanced meters for its 5.1 million electricity and 4.2 million gas customers at a projected cost of $1.7 billion.PG&E’s AMI is expected to be operating system wide by 2011.
One feature of PG&E’s system is the ability to reduce peak load on the very hottest days by providing incentives to customers to shift electricity usage to a less critical time.This will reduce the company’s need to purchase power for peak demand, lessen strain on the power grid, and reduce reliance on fossil-fuel-based generation.
To fund the AMI, the average residential customer with both gas and electric service would see a rate increase ranging from 49 to 99 cents per month for the first five years (or about 1 percent), with rate decreases each year afterward.Following this initial period, PG&E projects that future rates will reflect savings generated by the program.
For example, a typical customer who reduces energy use by 25 percent during peak hours will save about 10 percent on electric bills in the summer.PG&E estimates that only 15 percent of its customers will need to enroll in the meter program to offset 10 percent of its projected cost.The AMI also will make it easier for customers to enroll in a TOU program, which now requires the installation of a special meter and payment of a monthly fee.
An last November, PPL Electric Utilities (PPL) became the nation's first utility to obtain hourly usage from its entire customer base — nearly 1.4 million homes and businesses in Pennsylvania —when its new data management software system went live.Besides managing data from the hourly meter reads, PPL’s system provides the platform for revenue protection, complex billing, forecasting, distribution management, load research, settlement, and customer energy management services.
Other PUCs have expressed interest in AMI, but due to the investment required, moving to an AMI will require utilities to offer a solid business case to proceed.AMI costs typically include the system hardware and software, new meters and meter-related utility equipment and labor, installation management and labor, project management, and IT support and integration.
Costs for the communication systems to read the meters are approximately $100 to $175 per meter.Adding demand response components (e.g., customer signaling, load control, other demand response equipment) adds another $100 to $350 per site.The systems to manage the AMI and integrate it with the utility's operating software systems are now being introduced, and the costs vary widely.
For utilities, the savings related to the reduction or elimination of manual meter reading usually constitute the single greatest benefit — accounting for fully one third to two thirds of the total AMI benefit. Some utilities are looking at an AMI for this reason alone.Other benefits vary significantly by utility, but can include the following:
The societal benefits of AMI should be included in the business case as well.These include detecting outages faster; reducing energy losses due to theft, which are borne by all customers; and giving customers more control over their energy costs through AMI’s demand response capabilities.
Electric utilities considering AMI should also look at its regional impacts.On the utility side, coordinating an AMI across multiple utilities in a region can reduce costs by allowing that region’s power suppliers to benefit from economies-of-scale.Regional coordination may also ensure that utility systems can communicate with those of the transmission operator.
From the regulator’s standpoint, a regional approach to creating an AMI can be helpful in a number of ways.It can promote uniformity in the way state PUCs in the region evaluate AMI benefits.And adopting a regional approach and the way they approach related policy issues—such as the throughput issue, the implementation of TOU, and the extent to which PUCs allow utilities to offer new products and services that AMI may enable.
The nation’s electric utility industry is backing AMI for its operating and cost-saving benefits.But it is also promoting AMI as a way to use electricity more efficiently.EEI and its member electric utility companies are now collaborating to create the foundation for the business case that PUCs will need to make AMI a widespread reality.
This effort is part of a larger, industry-wide initiative to work with regulators, lawmakers, customers, and other stakeholders to develop a sustainable role for energy efficiency.Besides AMI, EEI and its member electric utility companies are focusing their efforts on four other areas that will also result in electricity being used more efficiently.These are:
To achieve its objectives in each of these areas, the industry is aggressively supporting federal appropriations.It is performing policy research on key state topics including net metering, alternative regulation, risk management, and rate design.And it is reaching out to the National Association of Regulatory Utility Commissioners and regional state regulator groups to encourage development of supportive state policies.
Building an advanced metering infrastructure will present challenges.But it, along with a new approach to energy efficiency, will benefit the customer, the utility, and society.It is time to begin.
About the Author
K. Michael McGrath, Executive Director Retail Energy Services, Edison Electric Institute mmcgrath@eei.org Mike McGrath is Executive Director, Retail Energy Services, for Edison ElectricInstitute (EEI), which is the trade association of the investor-owned electric utilities and industry affiliates worldwide.EEI’s U.S. members serve over 90 percent of all customers served by the investor-owned segment of the industry; generate approximately three quarters of all the electricity in the country; and service approximately 70 percent of all ultimate customers in the nation.
Mike has been with EEI since 1979. In his current position as a business unit leader, he is responsible for all EEI activities related to member utility and affiliate access and service to retail customers.
As such, he is active in areas such as business practices, affiliate transactions, energy codes and standards, customer services and operations, energy efficiency initiatives, and regulatory outreach.Mike has been a principal leader in the industry effort to develop retail uniform business practices.
Prior to joining EEI, Mike was a commercial marketing supervisor for the Potomac Electric Power Company.
Mike is a graduate of the Georgia Institute of Technology (Georgia Tech) with a degree in Mechanical Engineering.He has held several leadership positions over the years within the electric industry and in allied industries.He is a member of the American Society of Heating, Refrigerating and Air Conditioning Engineers (ASHRAE) and has chaired ASHRAE’s Owning and Operating Cost Technical Committee. He is also a member of the board of directors and an officer of the Geothermal Heat Pump Consortium.
The nation’s electric utility companies are now creating business models and regulatory mechanisms that will help make AMI a widespread reality. This is part of a broad-based campaign to enable energy efficiency to become a viable, sustainable business for utilities and other energy providers, Digital “smart” meters, two-way communication capabilities, automated controls, and sophisticated data management systems are rapidly improving the potential for information exchange between electric utilities and their customers.When coupled with innovative approaches to ratemaking and rate design, AMI can increase the industry’s portfolio of resource options to meet the country’s growing demand for electricity.It can more closely align regulated retail markets with competitive wholesale markets to deliver more cost savings.And it can become the foundation for a dynamic partnership between utilities and their customers to achieve greater reliability, power quality, environmental protection, cost control, and risk management.
Advanced Metering Infrastructure
Advanced meters, or meters that are not visually read by a meter reader, have been around for decades.Some automated meter reading (AMR) systems consisted of a receiver that was mounted in a vehicle.As the vehicle was driven through a neighborhood, the data from the meters was read.These AMR systems reduced meter-reading costs, accelerated cash flow, and reduced the need for estimated bills.But once the meter data arrived at the utility, it followed the same path as data collected manually.
With an AMI, a utility can read almost any meter at any time, but its value extends far beyond simple meter reading.An AMI communicates through a fixed network that is in place all the time—it does not move.The meters are equipped with communication capabilities, usually radio or power line, but sometimes telephone, digital cellular or satellite.Meters using radio-based systems exchange information with data collectors located throughout the distribution system.Meters with power-line based systems communicate with data collectors located at substations.Both types of systems can in turn communicate directly with a utility’s billing system, customer information system, and its outage management system.
An AMI’s two-way communication capabilities give utilities and customers the potential to use time-based rates—such as time-of-use, seasonal, interruptible, and real-time rates—across the entire customer base.The benefits that arise from this capability are many and include:
- Cost savings for customers who shift their demand from peak to off-peak periods.
- Less stress on the transmission and distribution network at peak times, which can help to maintain reliability.
- A moderation in wholesale prices due to retail markets that include more price-responsive customers.
- Lower system peak demands, which in turn reduces the need for new peak generating plants.
AMI was given a boost by Congress with the passage of the Energy Policy Act of 2005 (EPAct).EPAct amended the Public Utility Regulatory Policies Act (PURPA).PUCs and the Boards of Directors of unregulated utilities were directed to take a fresh look at a number of issues, including a wide variety of time-based rate structures, and alternative rate forms, and net metering.
The 2005 revisions to PURPA also require PUCs and unregulated utilities to consider whether it is appropriate to create an AMI. If it is deemed appropriate, the PUCs may also set an advanced metering standard for utilities.Appropriateness was defined to mean whether the costs and the benefits to both the customer and the utility balance each other out.
Electric utilities have now begun moving toward creating an AMI.Last summer, Pacific Gas & Electric (PG&E) announced its plan to install 9.3 million advanced meters for its 5.1 million electricity and 4.2 million gas customers at a projected cost of $1.7 billion.PG&E’s AMI is expected to be operating system wide by 2011.
One feature of PG&E’s system is the ability to reduce peak load on the very hottest days by providing incentives to customers to shift electricity usage to a less critical time.This will reduce the company’s need to purchase power for peak demand, lessen strain on the power grid, and reduce reliance on fossil-fuel-based generation.
To fund the AMI, the average residential customer with both gas and electric service would see a rate increase ranging from 49 to 99 cents per month for the first five years (or about 1 percent), with rate decreases each year afterward.Following this initial period, PG&E projects that future rates will reflect savings generated by the program.
For example, a typical customer who reduces energy use by 25 percent during peak hours will save about 10 percent on electric bills in the summer.PG&E estimates that only 15 percent of its customers will need to enroll in the meter program to offset 10 percent of its projected cost.The AMI also will make it easier for customers to enroll in a TOU program, which now requires the installation of a special meter and payment of a monthly fee.
An last November, PPL Electric Utilities (PPL) became the nation's first utility to obtain hourly usage from its entire customer base — nearly 1.4 million homes and businesses in Pennsylvania —when its new data management software system went live.Besides managing data from the hourly meter reads, PPL’s system provides the platform for revenue protection, complex billing, forecasting, distribution management, load research, settlement, and customer energy management services.
Other PUCs have expressed interest in AMI, but due to the investment required, moving to an AMI will require utilities to offer a solid business case to proceed.AMI costs typically include the system hardware and software, new meters and meter-related utility equipment and labor, installation management and labor, project management, and IT support and integration.
Costs for the communication systems to read the meters are approximately $100 to $175 per meter.Adding demand response components (e.g., customer signaling, load control, other demand response equipment) adds another $100 to $350 per site.The systems to manage the AMI and integrate it with the utility's operating software systems are now being introduced, and the costs vary widely.
For utilities, the savings related to the reduction or elimination of manual meter reading usually constitute the single greatest benefit — accounting for fully one third to two thirds of the total AMI benefit. Some utilities are looking at an AMI for this reason alone.Other benefits vary significantly by utility, but can include the following:
- Accelerated cash flow.
- Revenues realized from new customer services.
- Reduced capital needed as the result of less manual meter reading and optimal transformer sizing.
- Savings realized through fewer billing inquiries and faster resolution of inquiries.
The societal benefits of AMI should be included in the business case as well.These include detecting outages faster; reducing energy losses due to theft, which are borne by all customers; and giving customers more control over their energy costs through AMI’s demand response capabilities.
Electric utilities considering AMI should also look at its regional impacts.On the utility side, coordinating an AMI across multiple utilities in a region can reduce costs by allowing that region’s power suppliers to benefit from economies-of-scale.Regional coordination may also ensure that utility systems can communicate with those of the transmission operator.
From the regulator’s standpoint, a regional approach to creating an AMI can be helpful in a number of ways.It can promote uniformity in the way state PUCs in the region evaluate AMI benefits.And adopting a regional approach and the way they approach related policy issues—such as the throughput issue, the implementation of TOU, and the extent to which PUCs allow utilities to offer new products and services that AMI may enable.
The nation’s electric utility industry is backing AMI for its operating and cost-saving benefits.But it is also promoting AMI as a way to use electricity more efficiently.EEI and its member electric utility companies are now collaborating to create the foundation for the business case that PUCs will need to make AMI a widespread reality.
This effort is part of a larger, industry-wide initiative to work with regulators, lawmakers, customers, and other stakeholders to develop a sustainable role for energy efficiency.Besides AMI, EEI and its member electric utility companies are focusing their efforts on four other areas that will also result in electricity being used more efficiently.These are:
- Fostering Smart and Efficient Buildings—Homes and commercial buildings account for over two-thirds of the nation’s electricity use and over one-third of its natural gas use.The industry currently has many programs that encourage energy-efficient construction and remodeling, such as online energy audits and construction programs that offer incentives and training.These will be strengthened and expanded in the future.
- Promoting Smart and Efficient Appliances and Equipment—Home appliances and commercial equipment represent the fastest growing use of electricity.We are advocating for stronger/accelerated federal appliance efficiency standards.We are also encouraging greater tax incentives.And we will continue our own long-standing efforts to make high-efficiency appliances and technologies more popular and affordable.
- Supporting the Development of Innovative Rates and Regulation—Innovative ratemaking and rate design will be essential for customers and utilities to reap the full benefits of energy efficiency.To achieve this, the industry is encouraging new regulatory constructs and business models that will enable energy efficiency and demand response to be not only good policy, but also good businesses.
- Advancing Plug-In Hybrid Electric Vehicles—These technologies offer tremendous potential for both reducing our dependence on foreign oil, and for further reducing the nation’s air emissions. The industry is collaborating with automobile manufacturers, suppliers, advocacy and governmental groups, and other stakeholders to bring the plug-in hybrid electric vehicle to the market.
To achieve its objectives in each of these areas, the industry is aggressively supporting federal appropriations.It is performing policy research on key state topics including net metering, alternative regulation, risk management, and rate design.And it is reaching out to the National Association of Regulatory Utility Commissioners and regional state regulator groups to encourage development of supportive state policies.
Building an advanced metering infrastructure will present challenges.But it, along with a new approach to energy efficiency, will benefit the customer, the utility, and society.It is time to begin.
About the Author
K. Michael McGrath, Executive Director Retail Energy Services, Edison Electric Institute mmcgrath@eei.org Mike McGrath is Executive Director, Retail Energy Services, for Edison ElectricInstitute (EEI), which is the trade association of the investor-owned electric utilities and industry affiliates worldwide.EEI’s U.S. members serve over 90 percent of all customers served by the investor-owned segment of the industry; generate approximately three quarters of all the electricity in the country; and service approximately 70 percent of all ultimate customers in the nation.
Mike has been with EEI since 1979. In his current position as a business unit leader, he is responsible for all EEI activities related to member utility and affiliate access and service to retail customers.
As such, he is active in areas such as business practices, affiliate transactions, energy codes and standards, customer services and operations, energy efficiency initiatives, and regulatory outreach.Mike has been a principal leader in the industry effort to develop retail uniform business practices.
Prior to joining EEI, Mike was a commercial marketing supervisor for the Potomac Electric Power Company.
Mike is a graduate of the Georgia Institute of Technology (Georgia Tech) with a degree in Mechanical Engineering.He has held several leadership positions over the years within the electric industry and in allied industries.He is a member of the American Society of Heating, Refrigerating and Air Conditioning Engineers (ASHRAE) and has chaired ASHRAE’s Owning and Operating Cost Technical Committee. He is also a member of the board of directors and an officer of the Geothermal Heat Pump Consortium.
