|
 |
Metering
OOKING BACK AT RESIDENTIAL AMR
By Ralph Abbott and Eric Cody
Ralph Abbott and Eric Cody are with Plexus Research in Roxborough, MA.
The utility industry’s transition to market competition over the last five years has been anything but smooth. The vision of competitive retail choice has not yet fulfilled early expectations—to many, the retail electricity market has defied regulatory prescription and left many customers seeing a plateful of transition costs but rarely tasting savings.
Nor have the anticipated metering information requirements materialized. Few customers or retail suppliers appear to want to be burdened with prices that vary hourly. On the contrary, according to market research, a regimen of fixed prices locked in for several years wins wider acceptance from most residential consumers. Many states have stopped planning to introduce retail competition. Some utilities now operate under long-term rate freezes, unable to recover new automated meter reading (AMR) investments conventionally via rate base. And no less important, utility business models have moved in different directions.
In 1998, on the threshold of restructuring, AMR appeared to be the right technology at the right time. Available since the late 1970s, widely deployed AMR presented electric utilities with one of the greatest opportunities for enhanced productivity. The notion that measurements of actual energy usage could be obtained remotely captivated utility leadership and promised to revolutionize the utility’s relationship with its customers, particularly residential ones. The technology would eliminate the intrusiveness of a monthly meter reading visit, improve billing accuracy, and enable new and innovative rate forms, all while lowering costs. Apart from the projected cost savings of AMR over manual meter reading, such a system would also support frequent data collection, interval metering, and innovative rate structures—all essential features of the then widely shared vision of electricity competition.
Expectations about what restructuring might eventually mean, as well as the promise of better customer service, led some prominent shareholder-owned utilities to make significant investments in AMR. After all, the only practical way to capture the hourly and daily data required by restructured market operations was with a wide area “fixed network” AMR system.
In 1998, growing pressure to unbundle the metering function hobbled AMR expansion. Unbundling would strip utilities of the metering, billing, and customer service functions by making them competitive. Enron and others argued, but failed to prove, that it was necessary to assure a level playing field for new market participants and unlock further economic benefits for customers. Fresh acronyms popped up to describe the new roles to be created—MSPs (meter service providers), MDMAs (meter data management agents), and others. The prospect of metering becoming competitive and the likely stranding of recent investments in advanced metering and AMR systems stopped many utilities’ AMR decisions dead in their tracks. This was ironic, because these systems were the only way to capture and retrieve the data needed to support accurate and timely settlements. Moreover, if a half dozen MSPs were competing against one another in a given area, no single provider could justify the investment.
Some Truths
Looking back on the experiences of the past five years, the industry should be better prepared for the next five to make coherent and correct decisions about metering, data acquisition, and other revenue cycle services.
Some lessons:
The electric utility is, after all, the obvious and best qualified provider of metering services for the residential sector at least, given the absolute necessity that the function be performed accurately and efficiently. The claim that residential metering and revenue services had to be unbundled to assure choice did not hold water. Incumbent utilities operate with practices well-honed during the past 100 years. (Though outsourcing some components of the process, however, is becoming increasingly prevalent.)
Energy service providers (ESPs) are simply not interested in residential customers under currently prevailing market conditions and default service arrangements. (A few notable exceptions exist among individual utilities: Cleveland Electric Illuminating, Maine Public Service, and Orange & Rockland, with more than 25 percent of residential accounts supplied competitively.)
Most residential customers appear perfectly happy to remain with their historical utility as energy provider. Their unhappy experiences with various long distance telephone service providers may have hardened that view.
“Choice” is not synonymous with “supplier switch” in many customers’ minds. In fact, more than 35,000 Oregon utility customers have chosen to pay a premium for green energy products from a portfolio of options offered by Portland General and Pacific Power and ultimately supplied by Green Mountain Energy.
There is scant evidence that innovative rates have made significant headway in the residential sector since the Public Utility Regulatory Policies Act forced the promulgation of time-of-use rate structures in 1978. (See, “Take TOU?”)
|
TAKE TOU? |
|
Few in the industry or regulatory community are entirely satisfied with the metering consequences of electricity restructuring, when compared to those of telephone deregulation. Providers of telephone services are able to offer a wide array of time-of-use (TOU) pricing options without the need for AMR, or any metering changes for that matter. Their computerized telephone switches automatically capture all the detailed information describing these calls for billing purposes. Electric utilities should be so lucky!
The industry is facing fresh pressures at the federal level and in certain states to revisit TOU pricing as one arrow in a quiver of demand-response options. AMR would almost certainly be required. Is the technology for implementing large-scale residential TOU rates commercially available? Yes, absolutely, but there are prerequisite questions, and failure to answer them risks repeating past mistakes:
Do residential customers want TOU rates? What is the utility’s past experience?
Who benefits from TOU rates? Can every party be a winner?
How shall the rates be designed?
Will the rates have a “dynamic” component to reflect the new market setting?
Shall the rates be opt-in, opt-out, or involuntary?
Who will pay for the metering equipment and AMR systems necessary to enable these rates?
The clear answer to these questions in 2003 is “That depends!” It depends on top management’s vision of the intersection of internal, local, state, regional, and federal requirements. It depends on having learned the lessons taught by history. It depends on top management creating a clearly articulated vision statement with buy-in at all levels of the organization. And it depends on the very different circumstances each utility now finds itself in. |
Emerging Markets and Diverging Utility Models
Retail energy competition and its side effects have unfolded in ways that make AMR decisions more convoluted, but no less strategic. Some utilities will today view the decision quite differently than others because they view the world differently.
Today we have regional electricity markets with inconsistent rules and different preconditions, and not surprisingly, utilities are adopting divergent operating models. Some major variations:
Utilities operating under retail access that have entirely divested generation and see little bottom line impact from volatile commodity prices (most of New England, for example).
Other restructured utilities that have separated their retail functions—commodity supply as well as billing and customer services—into “unregulated” affiliates (Texas and Alberta).
Utilities with partially unbundled service where commercial and industrial customers can switch suppliers while residential customers cannot (Oregon).
Utilities in which all customers are eligible to switch suppliers but in which actual switching has been lower than expected (New Jersey; Maryland—excluding PEPCO’s territory; Virginia; Michigan).
Utilities with active competition for large commercial and industrial customers but anemic levels among residential and small business customers (Massachusetts, Illinois).
Utilities remaining in, or returning to the bundled, monopoly world (Southeastern utilities, California).
Small utilities fighting to preserve what they consider to be unique and worth preserving (electric cooperatives, for example).
The new operating conditions have a profound effect on metering and AMR decisions today and going forward. Metering and AMR are more strategic than ever. A utility’s metering and AMR system actually “shapes” the utility’s product. If a utility can’t meter innovative rates, it can’t offer them. In every industry the “shape” of the product demands senior management’s attention and involvement.
The business case for investment in metering technology has taken on new complexity as benefits become more closely tied to the utility’s individual business strategy, to specific classes of customers, and to the changing market and regulatory environment. And given the size of the technology investment and once-in-a-generation nature of the AMR purchasing decision, utilities can ill afford a misstep. For all these reasons, the AMR decision has become more complex and, in many ways, more diabolical than ever before.
Recent AMR Deployments
The most successful projects have a number of things in common. They begin with a clear and coherent vision of where the utility company is going, subscribed to and clearly expressed by top management. There is a shared view that metering and AMR are strategic to the company. AMR decisions are understood to be complex and high stakes. The AMR system investment for a typical shareholder-owned utility is in the $50 million to $200 million range installed. The technology selected will either enable the company’s customer service options for the next decade, or it won’t. These are not decisions that flow easily through the utility’s normal supply chain process. In terms of its longevity, cost and strategic asset value AMR is more comparable to a powerplant.
AMR technology itself has evolved. For some utilities, fixed networks seem to be the order of the day. Pennsylvania Power & Light has recently moved to install such fixed network AMR systems for residential meter reading. Powerline and radio communications technology has matured for low bandwidth applications such as meter reading, and the telecommunications sector implosion has made bandwidth on public networks inexpensive, releasing the need for some utilities to build and own a private network.
For residential applications, many of the expected, new metering requirements associated with retail competition have yet to emerge. Accordingly, deployment of a less functional, but lower cost, AMR system often captures many of the most prominent economic benefits of automation for some utilities. National Grid USA is well on its way to completing deployment of a “mobile” van-based AMR system covering approximately 3 million residential and small business customers throughout New England and upstate New York.
Just as there is no single “type” of utility, there is also no single “one size fits all” AMR system. Most successful large implementations today combine multiple technologies, often using one approach for residential and small commercial, and another for medium commercial through large industrial, a far cry from the popular 1998 vision of the future.
In many ways, 2003 and the next few years will set a new direction for strategic AMR and metering investments for all types of utilities.
|
