YEAR 2000. MILLENNIUM. DEREGULATION. Each word strikes fear into the heart of meter manufacturers and utilities alike. Like the turning of the century, deregulation is coming for the electric utility industry, and sooner than we think. How will it affect the metering industry?

The first real indication can be found in California. There, by order of the state public utilities commission, the customer's energy supplier (the energy service provider or the utility distribution company) will, for the time being, own the meter. The ESP or UDC will choose its own "meter data management agent" to read it and manage the data. Other states are considering similar ideas (see sidebar, California Metering Rules).

The California model has changed the face of the utility industry, helping to create a new variety of companies. Enron, for example, which now owns Portland General Electric, plans voluntarily to move to open access by establishing the "power supply coordinator." The company has proposed that ESPs should contract independently with metering companies to obtain metering services.

What are these new entities, the power supply coordinator, and the meter bill collect company or meter data management agent? What are their functions? Modeled after the California Independent System Operator, the power supply coordinator will forecast load, manage schedules, provide settlements, acquire ancillary services, act as an ISO for distribution and probably manage service outages. It will not read meters (em that function will fall to the meter bill collect company, which may, perhaps, install as well as own the meters. This MBC will supply billing-ready data and may even process bills for the ESPs, competing for that business against other MBCs.

But how will the infrastructure work with all these new entities?

Here lie some fundamental questions. How will ESPs, UDCs, MBCs and MDMAs transmit this sensitive data back and forth between each other? What sort of communications networks will they use?

Some vendors in the automated meter reading business have already come to rely on proprietary communications networks to receive and transmit data. However, a switch to public networks would allow the industry to escape from this monopolistic and closed model. In fact, these public networks already exist and provide almost complete coverage of the United States.

Consumer Credit: A Model for Meters

The future of electricity metering is best understood not by looking at the telecom industry, but by looking at the whole process of consumer retail credit.

In retail markets generally, the bank acts as credit provider. Through credit cards and other deals, it offers consumer credit and acts as intermediary for cash transactions between consumers and the retail establishment. The ESP can also act as a "bank" (as do Sears and AT&T through their Discover and Universal cards). The ESP sells energy to the consumer, makes deals and handles the cash between the consumer and the supplier.

The Visa or MasterCard system uses an information technology infrastructure to process applications for credit at the point-of-sale terminal and then processes transactions to the bank. Visa takes no financial position in the transaction but collects a transaction fee. The metering company acts like Visa. It provides the IT infrastructure to process the data but does not take a financial position in the transaction.

Will consumer metering go the way of the credit industry, operating with just a few large players? The answer may depend on the size of the customer.

For large customers or for large, special-purpose suppliers, branded metering will exist analogous to supplier-specific credit cards, such as those offered by large department stores, oil companies, and the like. Large ESPs may even tie value-added services to branded metering (em the equivalent of frequent-flyer miles, or the American Express corporate card with its special usage billing reports. However, most retail establishments that offer their own branded cards will also accept stand-alone credit cards, such as Visa, MasterCard or American Express, and it is likely that residential meters will follow this pattern (em a few large metering companies, unaffiliated with any ESPs.

The UDC, meanwhile, is a bit like the retail store: It sells goods (energy) under the manufacturer's (ESPs) branding and linking into the credit (metering) system. There is, of course, a subtle difference. The UDC must "carry" energy offered by all interested suppliers, perhaps including other UDCs, whereas the retail store can select the goods it offers, leaving the customer the choice of which store to patronize.

Thus, the UDC operates like a shipper, as does the ISO. Their customers are the ESPs (em not consumers. This role change will lead to different supplier relationships as consumers learn to take service problems to the ESPs. And, just as carriers such as FedEx allow shippers to access their IT systems to identify problems, UDCs will have to allow ESPs to access systems (like trouble call management) to identify and handle customer problems. The meter then looks like a key part of the seller's IT system, which functions like the point-of-sale terminal. It has automatic links to the credit (metering) systems and to the store (ESP and UDC) systems. The retail store uses its POS terminal to drive inventory management and ordering. The UDC and the ESP will use the meter to drive scheduling, forecasting and value-added services. The metering companies use it just as banks and Visa use POS information.

This analogy implies that standards will come along for metering data exchange that will allow any meter to be read by different metering companies or "store" systems. Meter manufacturers will focus on ease of use and consumer features just as POS terminals have focused on bar-code reader design and check clearing and checking systems. Metering systems companies will focus on the information they can provide to ESPs and UDCs.

Finally, note that the store no longer has to buy the card reader from the credit card company as they used to with American Express. Today, the store is free to buy the card reader as part of its IT systems, adapted in many cases to the type of store (i.e., groceries have different bar code readers than hardware stores, for instance). This pattern suggests that at the end of electric restructuring, energy customers will have a say in selecting their meter, so long as it meets standards.

The Meter Appliance:

"Smart" or "Dumb"?

Just as superior electronic phones replaced the rotary telephone, the modern "smart" meter will replace the "dumb" electromechanical meter omnipresent in American homes and businesses today.

Smart meters will incorporate the latest microprocessors, communications and applications to take advantage of the opportunities of competition. Two key technologies needed to bring this transformation about are available today: smart, affordable meters and low-cost, pervasive, public, two-way radio networks such as cellular phone and pager networks. The missing ingredient is the regulatory (deregulatory?) framework that allows the competitive market to apply these technologies, including open standards for meter-communications and data models.

The "smart" meter (such as the ABB Alpha meter) has been available to larger business customers using three-phase power for several years; nearly one million have been successfully deployed in the United States to date; 96 percent of all polyphase meters sold today are electronic. These meters, such as the ABB PowerPlus Alpha, provide much more than simple kilowatt-hour energy measurement; they provide power quality monitoring, outage detection, two-way communications and real-time pricing. Customers also can use electronic meters with a computer to retrieve current or historic usage. Lower-cost, single-phase versions of the same electronic meters are available.

With the growth of the smart meter has also come an entirely new family of application software that allows customers to improve energy quality. Applications available to consumers via smart meters will include better monitoring and management of energy consumption; tracking of service quality, outage duration and power quality; monitoring of large-appliance loads and power-conditioning effects; and even advanced energy control and control of loads such as air conditioners in response to energy prices. Features can also be added to the meter to enhance power-system reliability, such as autonomous response to low-frequency and low-voltage conditions or to provide whole-house surge protection.

New, smart meters are 20 percent more accurate than the old ones. The standard for electromechanical meters is that they should be accurate to within 0.5 percent of full scale when new. Over time, as they wear, they slow and become less accurate. This inaccuracy is biased in favor of the consumer and lost in the rate base. Tomorrow someone will have to pay for it.

Network Connections:

Public or Private?

Today there are automatic meter reading systems that use special-purpose, proprietary and private communications networks to communicate with the meters. Older systems employed power line carrier technology (PLC) which used the actual electric power line to reach the meter. Today private radio networks are used instead. In either case, a communications module is installed in the meter to send meter reading data out over the private system. While PLC is a viable option, it offers limited capability and bandwidth.

Just as PLC was necessarily a "closed" system owned by the utility and only usable by them, the current model for private radio networks is the same. These private radio networks are only usable for metering, have limited communications capabilities compared with public networks such as cellular phones and require their own slot in the electromagnetic spectrum. They are only financially viable if they are widely deployed in a high residential density. Such radio networks come with a large up-front cost to "build-out" the system of repeaters and network devices. In the past, these up-front costs would be put in the utility rate base and recovered from the rate payers.

Public communications networks would allow the electric industry to escape from this monopolistic and closed model, encouraging innovation. In an open and public metering environment a consumer will be able to interact with their meter via their personal computer over the Internet and run application software to analyze their energy usage. Smart meters can be integrated closely with the cellular phone network and modem electronics to provide metering and enhanced services via public networks without the need for large, up-front investments in private communications or the allocation of scarce electromagnetic spectrum for these purposes. Similarly, an open environment for metering would allow consumers to choose a metering system provider (em whether it be the UDC, the ESP or a communications company. The consumer could choose to invest themselves in a sophisticated meter if they wanted the additional benefits, or they could elect the lowest cost basic service available.

And public networks already exist. They already provide essentially 100-percent coverage across the U.S. Their costs are kept low by a fiercely competitive industry, while the consumer has a choice of network providers and cellular phone products to use. There are 50 million cellular phones in use today and 65 million pagers. By 2002 there will be more cellular phones in use than residential households.

By contrast, the current private network and meter communications module technology would have the industry make large investments in adding communications to existing electromechanical meters. This investment would lock the public into the existing "dumb" meter for years to come with no possibility of innovation, competition or added benefit.

Today, many industrial and commercial customers suffer from degraded power quality because of the increasing number of electronic power supplies in computers and other equipment and microprocessor-controlled motors or drives. These devices generally provide improved efficiency and equipment or appliance life, but they do so at a cost (em they introduce harmonics into the power system. These harmonics, when present beyond system design parameters, can damage equipment in both the consumer and utility facilities, can increase energy losses, and can cause sensitive electronic equipment to trip off line. Smart meters can identify the source of these harmonics so that appropriate corrective measures can be taken. Smart meters save the consumer and the utility money by performing the data collection and analysis. Otherwise this job requires an engineer or technician to make a prolonged visit and install special-purpose monitoring equipment or conduct manual diagnostics.

In the future, accurate data about power quality and service availability will become all the more important as the last regulated sector, the "wireco" (distribution company) falls under performance-based rate making. The frequency and length of outages will supply the critical PBR parameters by which a "wireco" can be measured. The meter and an independent metering system are the best source of this information.

Real-Time Data:

Essential for Direct Access

Direct access only increases the need for the precision and advanced capabilities of smart meters. The challenges cover a wide range, from real-time pricing to transmission congestion.

True real-time pricing requires that the usage and price be computed on short time periods (em 15 minutes anticipated today and possibly five minutes in the future. Reading the meter like this may

frequently be beyond the capacity of the private AMR radio network technology; smart meters can retain the information and allow daily or monthly reads as desired. In California, New England and New York, the development of independent system operators has already shown the need for advanced meters for accurate measurement, settlements and accounting.

In fact, ISOs do more than assure reliability and efficient transmission. They must deal with scheduling deliveries, accounting and settling up. These tasks turn out to be as large a technical challenge as the electric operations. The California and New York ISO systems are encountering these challenges and addressing them today.

Granted, California is a large market, but nonetheless it sets the principle that the ISO will end up with a transaction processing requirement as large as any used in American commerce today. Add to this the desire of the industry and Federal Energy Regulatory Commission to move to Internet technology, and you have one of the largest information technology system challenges around today. As was said earlier, the California projects are showing that providing the needed solution is feasible, but the challenge should not be underestimated.

Ralph D. Masiello is vice president for business development, ABB Information Systems division of ABB Power T&D Col Inc., the leading manufacturer of electric meters in North America.

California Metering Rules: An Interview with ORA Engineer

Anthony Mazy

ON Dec. 3, 1997, the California Public Utilities Commission issued

Decision 97-12-048, ironing out details for deregulation of the electric metering industry, a process begun in May 1997, in Decision 97-05-039, in which it announced the unbundling of "revenue-cycle services," including electric metering.

The December order responded to a report issued by the PUC's Meter and Data Communications Standards Workshop. It was notable for appearing to cut back on the extent of meter deregulation. For example, the order appeared to give no right to direct access customers to choose their own meter service provider or meter data management agent. Instead, energy service providers and utility distribution companies will take over the role of meter service providers and meter data management agents, with the right to assign those tasks to independent vendors, if they so choose.

Does that model achieve the vision of meter unbundling? For an interpretation, Bruce W. Radford, editor of the Fortnightly, solicited comments from Anthony Mazy, a utility engineer with the state's Office of Ratepayer Advocates, who originally proposed to unbundle meter services in California.

BWR: Do you have any general comments on Decision 97-12-048?

AM: While I do not speak for ORA management, much less the CPUC, I think that it is safe to say that we are very pleased with the [December] metering decision. It adopts, substantially intact and frequently verbatim, the ORA and Joint Parties positions offered in the workshops and in formal comments on record. Many of the positions offered in the decision as derived from the workshop report were, in fact, taken from ORA and other Joint Parties' submissions in that process. While it is gratifying to find our proposals accepted and adopted by the workshop participants, I also take a lot of pride in being part of a group that took the initiative to develop these proposals.

I only found two outright errors in the decision. First, it did not include the names of all of the parties in our group. Others who participated included PacifiCorp and Southern California Gas Co., the energy services provider Illinova Energy Partners, the metering services provider Data and Metering Specialties, the Industry Canada Task Force, and customer representatives Share Plus (a hospital consortium), the U.S. Dept. of Defense (as facilities manager of extensive properties in the state) and the Utilities Consumers Action Network.

Secondly, it was erroneously reported that the Automated Meter Reading Association has rescinded its cosponsorship of our proposals when, in fact, AMRA had never been a cosponor, but IEEE SCC 31 having at one time been incorrectly identified as AMRA.

BWR: Please comment on why the decision makes ESPs and UDCs the MDMA and MSP.

AM: While ORA has recommended near-term empowerment of customers to select their own MSPs and MDMAs, we never expected this to be implemented immediately. Incremental unbundling was to be expected, given the unprecedented scope of electric restructuring.

BWR: Why give discretion to ESPs or UDCs to subcontract to other vendors?

AM: I don't believe that this is anything new, as traditional utilities have always been rather free to apportion their operations between in-house employees and outside contractors as they saw fit, with only broad PUC oversight. "Micromanagement" has been a bad word for some time now.

BWR: Why can't customers choose their own MSP or MDMA?

AM: While we never expected customer choice to be immediately established for all of the so-called "revenue-cycle" services, ORA does recommend this as a goal of restructuring. Customer choice at this level, involving as it does multiple parties, can only take place under sufficient standardization so that all parties can feel comfortable in their expectations for the provided functions. The PUC seems to adopt this approach, in its language at the end of section III.B.2.B. [p. 4]:

"We see merit in eventually allowing customers to choose their own individual metering services from different providers¼ If systems can be developed to address these [safety, reliability, and accuracy] concerns, we would be willing to revisit the further unbundling of metering services in the future."

BWR: Is this what you envisioned with revenue-cycle unbundling?

AM: Establishing the principles of interoperability, open architecture, national standards and an orderly and expeditious migration as the essential requirements for meaningful customer choice was our expressed goal. We have achieved that, so, yes, we got what we asked for. But, again, unbundling and electric restructuring are far from being finished.

For one thing, California is the first state to implement such extensive unbundling services as a key means of implementing direct access. This hasn't been without controversy. In 1998, we'll find out which other states have the backbone to participate in the creation of a new industry instead of protecting the status quo.

Also, when we began this process, many of us understood it as an adjustment (em albeit a big one (em to the electric services industry, one that changed the rules for utilities, but didn't change the fundamental vision of what electric energy service was. The more we look into these issues, the more answers we find that further challenge assumptions about the "way things are supposed to be". Now, we are coming to believe that this is the beginning of the end of the entire electric services industry as we know it (em or as we are capable of recognizing it. Whether the UDCs are the "center of the universe" may not be a very interesting question if the universe we know changes into something else fundamentally different.

BWR: Has the vision been achieved?

AM: We are far from finished with metering, much less electric restructuring, but the ORA Joint Parties have clearly taken the high ground in this proceeding. We could quibble with the PUC's judgment in certain details of implementation, but we also recognize that part of their job is to mitigate the impacts of change for stakeholders. The PUC did adopt our proposal to embark upon a deliberate migration from UDC-based "standards" to national standards.

The Permanent Standards Working Group established by the PUC will provide a mechanism to review available national standards for adoption as law by the state of California, much as local governments review and adopt periodic editions of the uniform building codes. There will always be room to adjust national standards for the real situations faced by various locales, but the market for electric services is just too big to be defined by the provincial concerns of 50 different states. Having established in the California record and policy the principles of interoperability, open architecture, and national standards, reasonable details will surely follow in good time.

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