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Changing Business Requirements Shift Value Demand

By: An AMR and Real-Time Industry Examination

Tim Smith, PhD, Chief Editor
October 2003 Energy & Utilities

For most of the 20th century, reading utility meters had been a mundane process. Meter readers traversed neighborhoods, examined dials, and recorded utility consumption in log-books. At the office, the log-book meter reads were entered into corporate records in preparation of customer billing.

Fortunately, the state-of-the-art business process for reading utility meters has changed during the last decade. Technology, in the form of automatic meter reading (AMR) systems, is steadily displacing manual labor from this menial and sometimes dangerous task. Yet, this is only the beginning of the story. Similar to the new business requirements created in retail after the advent of point-of-sale (POS) systems, utilities are finding new value within AMR systems. The changing business requirements enabled by new AMR technology are shifting the markets towards new compelling value propositions. In the process, competitor positions are changing.

Large Growing Market in Automatic Meter Reading (AMR)

Automating the business process of reading meters is a large industry. A single automatic meter read (AMR) sale to any single one of the 179 top US investor owned utilities is valued between $100 and $150 million. These systems are more costly than the average Boeing 737 commercial aircraft priced near $75 million.(1) Moreover, AMR is a global market with expressed demand across the developed nations. The high price of AMR adoption is related to the work required to produce, install, and integrate the technology throughout the million plus service points in a typical investor owned utility service area.

Not only is the AMR market large but, unlike most other technology, it is still growing. Although economist report anticipated growth for the technology sector to be in the 2% range, the AMR market grew by 18% in 2002 and is anticipated to grow by 19% in 2003.(2) The disparity of growth in favor of AMR reflects the saturation of enterprise database solutions and the untapped latent market potential in machine-to-machine communication.

This is selling the equivalent of Boeing 737s to a growing market.

Shifting Business Requirements

During the early AMR market in the 1990’s, the business value of AMR was largely created by displacing the meter reading workforce. At that time, utilities required no more than monthly meter reads from residential service points and perhaps fifteen minute interval meter reads from large commercial and industrial service points. For residential meters which are a vast majority of the service points, a drive-by AMR solution was sufficient. In the drive-by AMR solution, a radio module mounted on the meter would wirelessly send the meter read to a radio transceiver mounted within a utility van as the van drives by the service point. 15 minute interval data from large commercial and industrial was often made available via dedicated or commercial telecommunication systems.

The value of transforming the business process of reading meters from mundane manual labor to automated technology persists today however, new business requirements which expands the financial impact of automatic meter reading and meter management, have evolved. These new business requirements are related to the overall shift in the environment of the utility competitors towards the creation of a real-time institution with real-time reaction speeds.

While most consumers are still billed once a month, real-time communication with utility meters and service points creates three new significant sources of value. These are: (1) On demand meter reads; (2) Outage management; (3) Demand Response contracts.

On Demand Meter Reads

Although the typical utility customer is only billed once a month, many customers will move during the billing cycle. When they move, accurate billing requires the meter is read on the first day of new service or the last day of existing service rather through estimation algorithms based upon past behavior. On demand meter reading enables the utility to capture consumption at anytime.

On demand meter reads have also been of value with respect to settling high-bill complaints as well as in identifying suspicious behavior. Teenage binge parties at summer residences are readily identified by sudden increases in power demand in unusual seasons. Likewise, basement greenhouses of illegal herbs can be identified by abnormal consumption patterns.

Outage Management

Outage management is a costly challenge. Outside of the spectacular power failure on August 14th 2003 in the Northeastern US, EPRI estimates that in 2001 the cost of power outages across the nation was $119 billion in lost productivity, or $425 per person.(3) Most power outages are not on the scale or duration as the August 14th event. Monitoring power quality in real-time, both at the service point through AMR and at the distribution point through other means (SCADA), enables utilities to identify downed power lines and overloaded transformers quicker, thus restoring power sooner. The reduction of power outages and faster restoration of power create value for our economy.

Demand Response Contracts

“Demand Response” has become the utility industry buzz phrase for methods that use a pricing mechanism to manage load demands. (Load refers to the amount of power drawn from the transmission grid.) Although the majority of utility customers cannot enter into demand response service contracts at this time, the prevalence of these contracts will increase in the coming years.

Power loads on electric transmission grids vary by the time of day. Despite the fact that commercial and industrial customers are heavy consumers of power and that they use most of their power during the day when people are at work, peak demand comes when the majority of the workforce is at home. Peaks load demand occurs during early morning hours between 6 and 9 am and again in the evening between 4 and 10 pm.

In the past, regulated monopoly utilities were required to carry as much as 20% excess generation capacity to allow for load fluctuations. Consumers were burdened with the costs of carrying large excess capacities through contractually negotiated rates with regulators. Deregulation however strands these costs with the historic supplier which leads to politics regarding the “recuperation of stranded costs”. To both lower the cost to supply power by removing excess capacity and avoid future regulatory challenges with stranded costs, regulators and many utilities favor demand response programs.(4) Economically, shifting the load management problem to the consumer of power creates a more efficient market in matching supply to demand.

Unlike curtailment programs wherein a utility unilaterally shuts off power regardless of consumer demand, demand response programs enable customers to make their own choice whether or not to consume. To encourage customers to alter their consumption timing, the price of power changes over the course of a day. During high-demand periods when the transmission or generation capacity is constrained, prices rise. During low-demand periods, prices fall.

Residential demand response programs predominantly take one of two forms. In the first form, voluntary residences enter into contracts to shed loads during periods of peak power. In these situations, the utility will actually alter the thermostat of air conditioners and turn off appliances at their discretion. If the residence then selects to turn the load back on, they are then billed for their choice to consume at a premium price. In the second form, voluntary residences contract with the utility for a dynamically fluctuating rate. During peak load demand times, the consumer will pay more per kilowatt-hour than during day-time or night-time usage. (The amount at which residential rates fluctuate between peak-load and off-load times is determined by agreements between local regulators and utilities. These time-of-day rate fluctuations can be as large as a factor of 4.)

Commercial and industrial demand response programs usually take the form of applying different rates according to the time of use (TOU rates). In a valuable minority of cases, an industrial demand response program allows for the industrial customer to purchase power through alternative markets. This may include a mixture of purchases from the spot market, the options market, co-generation, and contractual relationships.

Increased Technological Requirements

These three factors, (1) on demand meter reads (2) outage management (3) demand-response contracts, are shaping the current generation of business requirements in AMR technology. On demand meter reads require the ability to collect specific meter reads at any time. Outage management requires the data communication to occur in real time. And demand response programs require the ability to manage loads and monitor power consumption continuously through two-way data communication.

Drive-by solutions are inadequate for real-time data communication. Telecommunication solutions such as remote dial-up internet connections are both too costly for the millions of service points and too problematic due to phone-number shutoffs. Filling this void has been a number of solutions that rely upon either wireless networks or transmission of the data through the powerline itself.

Due to the current and anticipated changes in the regulatory environment, electricity utilities will feel increased pressure to adapt real-time AMR solutions. As the industry shifts from meter-reading for monthly billing purposes towards meter-reading for real-time management of customers, supply, and pricing, the competitive position of vendors within the AMR market will shift. Many of today’s wining solutions are on the path to becoming tomorrow’s outdated legacy systems. For companies still focused on displacing manual meter-readers with monthly AMR meter reads, current market penetration provides little assurance of tomorrow success.

In next issue’s article, we will examine one possible solution for creating the real-time utility, the powerline carrier.

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References

1. Boeing 2002 Financial Report (www.boeing.com) indicates $54 B revenue wherein 53% was derived from their commercial sector. They delivered 381 commercial aircraft of which 59% were 737 models. In estimating the $75 million price for a Boeing 737, many assumptions and approximations were made.

2. Wiglaf AMR Market Forecast 2003. http://www.wiglaf.biz/LOB/Research/2003AMR.htm

3. “The cost of Power Disturbances to Industrial and Digital Economy Companies”, EPRI CEIDS, June 2001. http://ceids.epri.com/ceids/Docs/outage_study.pdf

4. FERC’s SMD Proposal, David Kathan, PhD, April 15 2003. http://www.aceee.org/conf/mt03/wbprsnt/Kathan-CC4w.pdf



About the author

Tim J. Smith, PhD is the Managing Principal of Wiglaf Pricing, and an Adjunct Professor at DePaul University of Marketing and Economics. His most recent book is Pricing Strategy: Setting Price Levels, Managing Price Discounts, & Establishing Price Structures.

Tim J. Smith, PhD
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