Change is a constant state in the world today. Utilities are facing changes on a scale they have not faced since the 1900s. New technologies, merger and acquisition activities and government regulations, all mean significant change for utility companies. A number of utilities are looking at implementing advanced metering infrastructure (AMI) as a way to improve overall business operations as well as meet the Energy Policy Act of 2005 (EPAct) mandating “energy efficiency” on all levels.
Sometimes referred to as “smart meter” or “automated meter reading,” AMI is simply the use of digital technology to collect, synthesize and report data for billing purposes rather than the former labor-intensive, manual methods.
It allows utility companies constant two-way communication with their commercial, industrial and residential meters, which is essential for improving customer service, reducing operational costs and positioning for growth.
EPAct 2005 is creating even more pressure for utility companies. The act, signed in August of 2005, provides utility companies with incentives to improve traditional energy production, as well as find new and more efficient energy technologies to meet the long-range conservation effort. EPAct will force many utilities to transform metering and demand response systems, but the key will be to develop a long-term strategy on an adaptable infrastructure.
Although AMI is not a new idea within the industry, it is very much top of mind for many utility companies today. Although implementation costs may be high, the benefits of managing meters remotely far outweigh the price tag to implement an AMI solution.
The Benefits of AMI are Evident
Even though AMI was developed more than 10 years ago, the demand for “energy efficiency” by both the government and consumers is making it a reality. It is truly becoming the most effective way for utilities to replace the sometimes inaccurate, labor-intensive process of physical meter readings. This, combined with diminishing natural resources and a need to reduce operating costs, has made AMI an important consideration for future operations. In fact, many states are pushing utilities to offer
consumers more options for reducing overall power consumption.
The following is a snapshot of the benefits that have been identified and well-documented for implementing AMI:
• AMI improves the process of managing demand for natural resources allowing the utility to offer consumers incentives for selective load control.
• Making educated assumptions about future usage is the most imperative data collected by AMI. It provides information about factors that stimulate peak consumption, which can be translated into business strategies such as proactive load management, outage prevention and consumer incentive programs.
• It also enables utilities to implement pricing structures that offer incentives for efficient energy users, so peak energy users are charged more and efficient users no longer subsidize inefficient users. By monitoring almost real-time usage, utilities can ultimately help customers save money on their utility bills.
• Automated, remote data collection streamlines back office processing for billing, asset management and outage management. The automated data transfers improve meter reading accuracy which ultimately reduces customer complaints.
• AMI reduces the number of steps between consumer usage and bill distribution, so utility companies yield cost savings by significantly shortening their billing cycles.
• Rather than customers having to call in and experience long hold times, AMI can proactively provide customers with information regarding outages. Another way call center activity and related costs are greatly reduced is decreased data entry errors, which in turn reduces billing errors and customer disputes, thus reducing customer calls.
• AMI technology offers utility companies valuable insight into customer usage, including consumption behavior, effects of external variables and outages. Data collected at 15-minute intervals can be used for profiling usage, time-of-use data, demand management and phase-load balancing. The overall results are improved quality of service and shortened response times to outages.
The benefits of AMI can be seen in all areas of the supply chain. Automation alone can lower costs related to billing, meter reading, call center activity and demand response. However, the risks associated with a large-scale deployment of AMI are considerable.
Despite these risks, utilities are being forced through competitive and regulatory pressures to deploy AMI systems. It is important for utilities to understand the risks involved, in order to minimize them, while maximizing their return.
AMI’s Biggest Risks
Initial Capital Outlay and its Effect on Cash Flow
A major risk utility companies contend with when implementing the new infrastructure is the amount of capital required and the subsequent effect on the utilities’ cash flow. AMI usually requires a large capital expenditure initially for the meters, data concentrators and the labor to install them, as well as the software, hardware and communications required to run the system. That expenditure can decrease if there is a rate increase approved to support it, but cash flow is still an issue.
Potential Interruption and its Effect on Revenue
More importantly, utilities can not afford to stop or even slow down operations for a new mplementation. Since meters directly impact a utility’s revenue, the risk of changing technologies and processes means shutting down the utility’s source of collecting that revenue. The implementation can also be a drain on “people resources” because there is usually a small army of key utility staff members devoted to the project.
Some problems are inevitable in any large implementation, but there are ways to control costs associated with the implementation of a new infrastructure.
Strategies to Address AMI’s Risks Metering Technology
The bad news is the AMI technology, including meters, concentrators and head-end systems, is the largest cost component of a large deployment. Experience tells us this cost category is usually 35-40 percent of the total cost of deployment.
The good news is, in the long-term, this digital technology will continue to improve in functionality and decrease in cost. Take the evolution of personal computers costs as an example. When PCs first came out in the early 1980s, they cost at least $10,000. There were a number of proprietary hardware components that were unique to each manufacturer. Today, good PCs can be purchased for less than $500 with a magnitude of functionality far greater than their predecessors and are now equipped with mostly interchangeable components.
Digital metering technology will evolve in the same way, so metering technology should be treated as commodities. Utility companies should recognize there will be multiple metering systems as a result of geographical or topological concerns, as well as realize metering technology will continue to evolve and improve functionality. The metering technology implemented in the beginning will not be the same at the middle or end of the implementation. As a result, it is best for utility companies to not get tied to a particular metering vendor or pay for another utility’s deployment by purchasing its metering solution. Utility executives should buy from a reputable meter manufacturer that meets the company’s functionality needs at the lowest cost.
Networking Solutions
The key is to evaluate different local area networking (LAN) solutions for different population densities. There are several good LAN technologies. For example, PLC, RF and RF-mesh are currently available and more, such as BPL, are coming. Each has different technology issues and costs to consider.
PLC technology is great for rural and urban areas with large buildings. RF-mesh solutions are extremely cost effective for suburban areas. Most utility companies will need to use a mix of these technologies in order to minimize the LAN
networking costs.
On the other hand, Wide Area Networking (WAN) costs are commodities and should be treated as such. Utility companies should not get locked into long-term contracts with communications companies. Prices will continue to drop. The concentrator technology chosen must have the ability to use different modems, including phone, cellular, even satellite, and be replaceable when the price is right.
Meter Data Management
Meter Data Management (MDM) is the most important part of the architecture when aiming to keep costs low. A meter data management system that runs on multiple architectures, such as Windows, UNIX, and Linux, must be selected. It is best to purchase a MDM system from a company that does not make meters – unless the plan is to use only one type of metering system for the entire deployment (please refer to the above section on “Metering Technology” explaining why agility is important).
An independent software house usually has more incentive to be open to communicating with any meter manufacturer’s head-end system. Also, installing the meter data management system before any meters are deployed will allow utility companies to input current manual or handheld readings. It is imperative to then build interfaces to production systems so when the first AMI meter goes into production, the business benefits are realized immediately.
Additionally, the system must be scalable enough to handle the current and future meter population such as growth resulting from merger and acquisition activities. The MDM system chosen must also have a track record of success – the utility’s future should not be dependent upon a product that has not been tested widely in the marketplace.
Legacy System Interfaces
An enterprise application integration (EAI) tool should be utilized if it has already been
established – especially for all near real-time and real-time interfaces. Large volume interfaces, like billing systems, should still use batch interfaces. If an EAI tool has not been put into operation, utility companies should consider installing one in conjunction with the AMI deployment. In the long run, it will save time in coding and related costs.
There are several good EAI tools in the marketplace today and each has a slightly different set of advantages – but AMI should not drive the decision regarding which EAI tool is chosen since many are highly adaptable for easy use with AMI. An EAI tool should be selected because it meets the enterprise-wide objectives and needs.
Additionally, the overall project management aspect, from beginning to end, is critical to AMI success at a utility company. Whether the company chooses to implement AMI in-house or through a service vendor, it is imperative a master plan, including the IT blueprint, is in place and the executive management is committed to that plan and understands the enterprise-wide benefits.
In summary, utility companies deploying AMI will certainly face risks. Employing some of the strategies noted above can help minimize those risks and help utilities reap the advantages of implementing AMI.
About the Author
EDS Energy industry executive Bill Zorn
specializes in Advanced Metering Infrastructure (AMI). With more than 28 years of delivery, sales and consulting experience in systems and services, Zorn is considered a subject matter expert in Automated Meter Reading (AMR) and Advanced Metering Infrastructure (AMI). In addition to his expertise in the energy industry, he has considerable expertise in the manufacturing industry as well as experience in corporate and divisional business planning, management, sales, delivery and
consulting.
Sometimes referred to as “smart meter” or “automated meter reading,” AMI is simply the use of digital technology to collect, synthesize and report data for billing purposes rather than the former labor-intensive, manual methods.
It allows utility companies constant two-way communication with their commercial, industrial and residential meters, which is essential for improving customer service, reducing operational costs and positioning for growth.
EPAct 2005 is creating even more pressure for utility companies. The act, signed in August of 2005, provides utility companies with incentives to improve traditional energy production, as well as find new and more efficient energy technologies to meet the long-range conservation effort. EPAct will force many utilities to transform metering and demand response systems, but the key will be to develop a long-term strategy on an adaptable infrastructure.
Although AMI is not a new idea within the industry, it is very much top of mind for many utility companies today. Although implementation costs may be high, the benefits of managing meters remotely far outweigh the price tag to implement an AMI solution.
The Benefits of AMI are Evident
Even though AMI was developed more than 10 years ago, the demand for “energy efficiency” by both the government and consumers is making it a reality. It is truly becoming the most effective way for utilities to replace the sometimes inaccurate, labor-intensive process of physical meter readings. This, combined with diminishing natural resources and a need to reduce operating costs, has made AMI an important consideration for future operations. In fact, many states are pushing utilities to offer
consumers more options for reducing overall power consumption.
The following is a snapshot of the benefits that have been identified and well-documented for implementing AMI:
• AMI improves the process of managing demand for natural resources allowing the utility to offer consumers incentives for selective load control.
• Making educated assumptions about future usage is the most imperative data collected by AMI. It provides information about factors that stimulate peak consumption, which can be translated into business strategies such as proactive load management, outage prevention and consumer incentive programs.
• It also enables utilities to implement pricing structures that offer incentives for efficient energy users, so peak energy users are charged more and efficient users no longer subsidize inefficient users. By monitoring almost real-time usage, utilities can ultimately help customers save money on their utility bills.
• Automated, remote data collection streamlines back office processing for billing, asset management and outage management. The automated data transfers improve meter reading accuracy which ultimately reduces customer complaints.
• AMI reduces the number of steps between consumer usage and bill distribution, so utility companies yield cost savings by significantly shortening their billing cycles.
• Rather than customers having to call in and experience long hold times, AMI can proactively provide customers with information regarding outages. Another way call center activity and related costs are greatly reduced is decreased data entry errors, which in turn reduces billing errors and customer disputes, thus reducing customer calls.
• AMI technology offers utility companies valuable insight into customer usage, including consumption behavior, effects of external variables and outages. Data collected at 15-minute intervals can be used for profiling usage, time-of-use data, demand management and phase-load balancing. The overall results are improved quality of service and shortened response times to outages.
The benefits of AMI can be seen in all areas of the supply chain. Automation alone can lower costs related to billing, meter reading, call center activity and demand response. However, the risks associated with a large-scale deployment of AMI are considerable.
Despite these risks, utilities are being forced through competitive and regulatory pressures to deploy AMI systems. It is important for utilities to understand the risks involved, in order to minimize them, while maximizing their return.
AMI’s Biggest Risks
Initial Capital Outlay and its Effect on Cash Flow
A major risk utility companies contend with when implementing the new infrastructure is the amount of capital required and the subsequent effect on the utilities’ cash flow. AMI usually requires a large capital expenditure initially for the meters, data concentrators and the labor to install them, as well as the software, hardware and communications required to run the system. That expenditure can decrease if there is a rate increase approved to support it, but cash flow is still an issue.
Potential Interruption and its Effect on Revenue
More importantly, utilities can not afford to stop or even slow down operations for a new mplementation. Since meters directly impact a utility’s revenue, the risk of changing technologies and processes means shutting down the utility’s source of collecting that revenue. The implementation can also be a drain on “people resources” because there is usually a small army of key utility staff members devoted to the project.
Some problems are inevitable in any large implementation, but there are ways to control costs associated with the implementation of a new infrastructure.
Strategies to Address AMI’s Risks Metering Technology
The bad news is the AMI technology, including meters, concentrators and head-end systems, is the largest cost component of a large deployment. Experience tells us this cost category is usually 35-40 percent of the total cost of deployment.
The good news is, in the long-term, this digital technology will continue to improve in functionality and decrease in cost. Take the evolution of personal computers costs as an example. When PCs first came out in the early 1980s, they cost at least $10,000. There were a number of proprietary hardware components that were unique to each manufacturer. Today, good PCs can be purchased for less than $500 with a magnitude of functionality far greater than their predecessors and are now equipped with mostly interchangeable components.
Digital metering technology will evolve in the same way, so metering technology should be treated as commodities. Utility companies should recognize there will be multiple metering systems as a result of geographical or topological concerns, as well as realize metering technology will continue to evolve and improve functionality. The metering technology implemented in the beginning will not be the same at the middle or end of the implementation. As a result, it is best for utility companies to not get tied to a particular metering vendor or pay for another utility’s deployment by purchasing its metering solution. Utility executives should buy from a reputable meter manufacturer that meets the company’s functionality needs at the lowest cost.
Networking Solutions
The key is to evaluate different local area networking (LAN) solutions for different population densities. There are several good LAN technologies. For example, PLC, RF and RF-mesh are currently available and more, such as BPL, are coming. Each has different technology issues and costs to consider.
PLC technology is great for rural and urban areas with large buildings. RF-mesh solutions are extremely cost effective for suburban areas. Most utility companies will need to use a mix of these technologies in order to minimize the LAN
networking costs.
On the other hand, Wide Area Networking (WAN) costs are commodities and should be treated as such. Utility companies should not get locked into long-term contracts with communications companies. Prices will continue to drop. The concentrator technology chosen must have the ability to use different modems, including phone, cellular, even satellite, and be replaceable when the price is right.
Meter Data Management
Meter Data Management (MDM) is the most important part of the architecture when aiming to keep costs low. A meter data management system that runs on multiple architectures, such as Windows, UNIX, and Linux, must be selected. It is best to purchase a MDM system from a company that does not make meters – unless the plan is to use only one type of metering system for the entire deployment (please refer to the above section on “Metering Technology” explaining why agility is important).
An independent software house usually has more incentive to be open to communicating with any meter manufacturer’s head-end system. Also, installing the meter data management system before any meters are deployed will allow utility companies to input current manual or handheld readings. It is imperative to then build interfaces to production systems so when the first AMI meter goes into production, the business benefits are realized immediately.
Additionally, the system must be scalable enough to handle the current and future meter population such as growth resulting from merger and acquisition activities. The MDM system chosen must also have a track record of success – the utility’s future should not be dependent upon a product that has not been tested widely in the marketplace.
Legacy System Interfaces
An enterprise application integration (EAI) tool should be utilized if it has already been
established – especially for all near real-time and real-time interfaces. Large volume interfaces, like billing systems, should still use batch interfaces. If an EAI tool has not been put into operation, utility companies should consider installing one in conjunction with the AMI deployment. In the long run, it will save time in coding and related costs.
There are several good EAI tools in the marketplace today and each has a slightly different set of advantages – but AMI should not drive the decision regarding which EAI tool is chosen since many are highly adaptable for easy use with AMI. An EAI tool should be selected because it meets the enterprise-wide objectives and needs.
Additionally, the overall project management aspect, from beginning to end, is critical to AMI success at a utility company. Whether the company chooses to implement AMI in-house or through a service vendor, it is imperative a master plan, including the IT blueprint, is in place and the executive management is committed to that plan and understands the enterprise-wide benefits.
In summary, utility companies deploying AMI will certainly face risks. Employing some of the strategies noted above can help minimize those risks and help utilities reap the advantages of implementing AMI.
About the Author
EDS Energy industry executive Bill Zorn
specializes in Advanced Metering Infrastructure (AMI). With more than 28 years of delivery, sales and consulting experience in systems and services, Zorn is considered a subject matter expert in Automated Meter Reading (AMR) and Advanced Metering Infrastructure (AMI). In addition to his expertise in the energy industry, he has considerable expertise in the manufacturing industry as well as experience in corporate and divisional business planning, management, sales, delivery and
consulting.
