San Diego Gas & Electric turns vendor heads with its plan to install real-time meters, but the company could face heat from regulators.

This is a landmark event," says Bill Rush, a physicist at the Gas Technology Institute, and a gas industry expert on electric utility metering systems.

"We now have a very large order for real-time metering equipment that is compliant with industry standards. This plan, and the vendor interest we've seen—it's the first clear sign that people in the industry are actually willing to buy this stuff."

Rush was talking about the request for proposals (RFPs) sent out in mid-August by San Diego Gas & Electric Co., asking vendors for bids on the $25 million first phase of its multi-year plan to install real-time (hourly interval) energy meters throughout its service territory. On Sept. 1, as this issue was going to press, SDG&E reportedly was meeting with vendors, answering questions about its RFP and explaining details about equipment specifications and compliance with industry standards. Only a month earlier, in the heat of the summer and under severe political pressure, the utility had outlined its metering plan to the California Public Utilities Commission.

In its application filed on July 31 , SDG&E had touted interval meters as one way to counter the "unprecedented" price spikes that had rained down like a plague on its electricity customers this past summer. (In fact, SDG&E filed its plan just six days after the San Diego City Council had passed a resolution urging the state PUC to support statewide real-time metering as a way to lower electricity prices.) Under the plan, the utility would spend $25 million to install real-time meters by the start of next summer for all of its 22,000 customers (2 percent of meter accounts, 46 percent of system peak load) with peak demand levels equal to or greater than 20 kilowatts. Meter installations would begin a year later for Phase II, involving residential and other small-volume customers with electric loads less than 20 kilowatts. (PUC rules already require all customers above 50 kW to have real-time meters if they choose direct access from a competitive energy supplier other than the distribution utility.)

Yet not everyone was happy with the plan. Steve Linsey, a policy analyst at the PUC's Office of Ratepayer Advocates, and the project coordinator for SDG&E's meter proposal, warned that his office would be filing a protest against the plan on Sept. 7.

"We haven't totally figured out what we're going to say," said Linsey, when interviewed on Sept. 1, "but there are several areas of concern. First, should all customers between 20 kW even have real-time meters? Second, should SDG&E as a utility be the designated installer, provider, and procurer of those meters?

"Offhand," explained Linsey, "It would seem that if the PUC decides that customers between 20-50 kW should have [an hourly interval] meter, then it should be up to the customers to decide who to get it from."

Linsey's concern stems from the fact that in California, the PUC has deregulated metering and billing, known as "revenue-cycle services." The regulators have decided as a matter of policy that competitive energy retailers will find it difficult to compete against default service offered by the regulated utility distribution company unless they can offer unique metering and billing services to offer to electric consumers as part of an attractive marketing package. (For background, see "Electric Meter Deregulation: Potholes on the Road to Plug-and-Play," , Sept. 15, 1998, p. 53, and "What's Stalling AMR?" Supplement to Public Utilities Fortnightly, May 2000, p. 18.)

The danger, it's said, comes from letting the monopoly utility control access to high-tech metering, so that electricity customers find less incentive to choose service from an independent electric supplier.

Listen to this anonymous comment on the SDG&E plan, offered by an engineer from California who is familiar with PUC metering policy: "SDG&E's proposal does not appear to be a thoughtful response to the present market crisis as much as a rather callous effort to use the 'emergency' as an excuse to further hobble the restructuring effort in California.

"If the regulated utility rolls out a monolithic meter reading system, then what options are left for energy vendors? In the name of minimizing costs, you'll have a system that minimizes functionality down to the point of what one vendor and one vendor alone needs to efficiently conduct its business. That's not an open system."

This engineer sees SDG&E's application as more "about rate base"-guaranteeing recovery of the meter installation costs-than improving consumer choice.

But to be fair, there is evidence that SDG&E's plan would promote the kind of open architecture in metering systems that some say is essential for utility competition to flourish. That evidence comes from SDG&E's RFP issued to vendors. When contacted, SDG&E spokesman Ed Van Herik said his company's RFP was confidential. "It's a bidding process," said Van Herik. "We evaluated vendors and sent the RFP to a short list of companies in the metering industry." Even so, some details have emerged from interviews with industry experts, and those details seem to bolster the utility's case, especially regarding compliance with metering standards adopted by the American National Standards Institute.

According to GTI's Bill Rush, the RFP requires compliance with ANSI C12.18, the "optical port" standard. Moreover, Rush says the RFP states a "preference" by SDG&E for vendors who will comply with ANSI C12.19, the data formatting standard. Rush sees broad acceptance of C12.19 as crucial to the future of the electric metering industry.

"SDG&E's action is not occurring in a vacuum," says Rush. "What's behind the scene here is a grand plan to achieve full integration and eventual plug-and-play capability between meters and all utility industry systems. I think that by stating a preference for C12.19, SDG&E is furthering open architecture in metering systems. Frankly, I'm a bit surprised that ORA might see problems here."

Price Spikes: Making a Dent

"Real-time meters," says SDG&E, will "empower customers to take control of their electricity bills by reducing usage during times of peak prices." This trimming of demand, the utility adds, will reduce peak prices for all customers-"even those who are unwilling or unable to reduce their demand in response to high prices."

Does this claim hold water? George Roberts, director of regulatory affairs and strategy at Schlumberger, suggests the answer is "yes."

In comments he filed with utility regulators in Virginia, in that state's pending investigation of electric metering and billing, Roberts cited evidence from business and academia suggesting that hourly interval metering indeed can moderate electricity prices. Roberts reported that in "a wide range of studies," electricity customers have shown reductions in energy use "averaging over 10 percent" when "furnished with energy usage data "going beyond the monthly meter read." .

For instance, Roberts cites the work of Frank Wolak, of Stanford University, and Robert Patrick, of Rutgers University, on the importance of electric metering in the restructured markets of England and Wales. Their 1996 study, says Roberts, found that the lack of hourly metering enabled generators in the U.K. to "manipulate market prices for energy and capacity, resulting in excess profits."

Closer to home, Roberts notes a study conducted for the U.S. Department of Energy by Science Applications International Corp., on the effects of load shifting on wholesale prices. In that study, says Roberts, SAIC concluded that customer response to price signals could reduce average spot market prices in New York by between 3.2 and 4.9 percent, even using "very conservative" assumptions.

Finally, Roberts notes congressional testimony from Robert Levin, vice president of the New York Mercantile Exchange, presented two weeks after the infamous Midwest power price spike of $7,000 per megawatt-hour recorded on June 25, 1998. Levin testified that "a 5 percent reduction in demand at that point could have dropped some of these prices 80 or 90 percent."

The Installation: A Real-Time Timeline Residential customers would wait until 2002—or later.

The Plan: San Diego Gas & Electric asks the California PUC to authorize installation of real-time energy meters, in two phases (large and small customers), for all customers that do not already have such equipment. Requested PUC Action: Approve vendor selection. OK equipment selection. Approve expenditures for Phase I, up to $25 million. Set cost limit for Phase II. Authorize recovery both of Phase I and Phase II costs; set cost allocation method. Phase I: $25 million to install real-time energy meters for large customers with peak demands of 20 kilowatts or more (22,000 accounts, representing nearly 46 percent of utility's system peak demand). Sept. 25, 2000-Bidders respond to RFP. Sept. 29, 2000-Utility files testimony to support plan. Dec. 19, 2000-PUC decision. June 1, 2001-Installation and testing complete. Phase II: Install real-time meters for remaining small-volume and residential customers, with demands less than 20 kW (about 1.2 million customer accounts). Nov. 15, 2000-Issue RFP. n March 1, 2001-Utility files testimony to support plan. Sept. 6, 2001-PUC decision. n June 1, 2002-Installation and testing completed for first 200,000 of some 1.2 million residential and small customers with demands less than 20 kW. ?????-Installation and testing completed for small customers. -B.W.R.

But does it make sense to install real-time meters for residential and small-volume customers, as SDG&E plans to do in Phase II? ORA project coordinator Linsey conceded that the question wasn't easy.

"The issue for metering," he said, "has always been to balance the metering costs against the benefits. So it probably doesn't make sense to track individual customers' response beyond a general load profile. Certainly given the recent price runup, and since prices are expected to remain high, it's reasonable to say that we should go lower than we did before [require real-time meters for a smaller level of demand], but that doesn't necessarily yield an answer as to how low we should go."

Utility engineer Mark Lively, of Gaithersburg, Md., showed more skepticism. When asked whether real-time energy meters might make a dent in electricity prices for residential customers, Lively answered, "Only if politics don't get in the way, as it does now for SDG&E."

Lively concedes that customers want "to be good citizens when the governor calls for a cut-back on air conditioning." But he stresses that regulators often don't let real price incentives out of the bag.

"Even if my supplier is paying $5,000 per megawatt-hour," notes Lively, "why should I cut back? Under traditional regulation, consumption only costs me $100 per megawatt-hour [under the utility's standard-offer rate], plus a minuscule share of that $5,000 that gets to me through the fuel adjustment clause. And even under real-time pricing, politics may not allow SDG&E to charge me the $5,000 per megawatt-hour rate. Consider the recent decision to defer part of the July fuel clause adjustment because it kicked the price up too high.

"What good is real-time metering," he asks, "if we don't use it to set real-time prices?"

And politics may well dictate the fate of real-time metering in California. On Aug. 30, the state legislature passed a bill that would fix the price of the electricity commodity (the product traded on the California Power Exchange) to 6.5 cents year-round. When interviewed on Sept. 1, Mike Schmidt, a regulatory expert at Sempra Energy, said the measure would create something akin to statewide mandatory "budget billing," with payments for electricity supply levelized over 12 months, "with overcollection in the winter and undercollection in the summer." According to Schmidt, the governor was evaluating the bill over the Labor Day weekend.

Utility Control: Fears of Monopoly

When asked whether SDG&E's metering plan was good for utility competition in California, and whether he would support it, Michael Shames, the executive director of UCAN, the Utility Consumers' Action Network, paused and then offered a revealing reply.

"This is not an easy question to answer," said Shames, from UCAN headquarters in San Diego.

A couple years back, when it deregulated metering and billing, the California PUC stressed that the very design of the metering system both reflects and constrains the design of the industry. It concluded then that the ability to control and design operation of these systems was essential to the ability of competitive energy retailers to reach and conduct business effectively with their customers. In other words, when you have a legally mandated customer base and the customers in turn face a legal monopoly for their only source of service, then "marketing," per se, gets rather perfunctory.

Of course, Michael Shames is familiar with all of that. But when questioned, he suggested that his group might well support a meter installation plan run by the utility itself-at least in Phase I for large-volume customers-if only to make the best of a bad situation.

Shames explained further. "In general, we support the deployment of real-time meters. [But] we have come to realize that such meters will not be deployed by the competitive market in any kind of timely manner. So far, the ESPs have failed miserably to deploy such systems-but through the poor design of the California market, more than through their own inattention. So we believe it is useful for the UDC to serve as the installer of real-time meters, but on a transition basis only."

When told that the Office of Ratepayer Advocates intended to protest the plan, owing to its possible chilling effect on competition from independent retailers, Shames acknowledged the problem but took a practical bent.

"We long made the same arguments about interference with the market-until we realized the market wasn't going to get there any time soon because of the screwed-up nature of the California experiment. SDG&E's application deals with large customers first-and we don't conceptually oppose (as ORA does) the company's role in installing and maintaining these meters."

Yet Shames concedes that UCAN might change its stance.

"There are going to be a substantial number of detail-laden issues about deployment of small customer meters," Shames notes, "including who pays, who maintains, what choices customers will have, cost of ESPs to use, rate schedules that will be used in conjunction with the meters, etc. Those issues may cause a great deal of friction. The devilish details may cause us to reverse our field. [But] because SDG&E is not proposing near-term deployment for small customers, I'm assuming I'll have an opportunity to work through these things with SDG&E."

When pressed, Steve Linsey from the ORA seemed to admit that his agency might draw a distinction between customer classes when it comes to any perceived threats against California's regime for utility competition. Is one customer class more vulnerable than the other in terms of monopoly influence over the metering function?

"Let me answer that question a little indirectly," said Linsey. "We would absolutely draw a distinction between Phase I and Phase II, not necessarily on the monopoly issue, but on the fact that the widespread rollout of real-time energy meters is a statewide issue, not merely an issue for SDG&E, and should be considered for all the utilities together, and the customers they serve. Should the state embrace a single technology? Should it embrace a whole host of technologies? Should it have some strategy for how you roll out and make a significant investment in infrastructure? I don't know what the answers to those questions are, but it seems like they ought to be considered in a coordinated way, as opposed to dealing with SDG&E alone, because by the time we consider them, all the utilities should be out of the rate freeze."

Linsey has a point. Note that under its proposal as filed, it would take SDG&E nine and one-half months from the issue date of the RFP-until June 1 of next summer-to complete installation and testing of real-time meters for Phase I, the 22,000 large customer accounts with demand levels between 20 and 50 kW. SDG&E would not send out its RFP for Phase II until Nov. 15, and then would take 18 months-until June 1, 2002-before installing even as many as 200,000 real-time meters for accounts below 20 kW. Thus, even two summers from now, SDG&E would have interval meters installed only for about one-sixth of its residential electric customers.

Meanwhile, at Schlumberger, George Roberts sees the industry caught in an endless loop, as policymakers debate how to make metering policy mesh with competitive realities. He makes a plea for regulatory certainty.

"For the last several years," notes Roberts, "most states have been in a condition of maximum uncertainty. Metering has not been made competitive, but competitive metering has been identified as a distinct possibility for the future.

"Under these conditions," he adds, "it is extremely difficult for any party to deploy advanced metering. Competitive suppliers are, of course, prohibited from installing advanced metering because metering remains a monopoly service. However, while utilities are allowed to deploy advanced metering, they are discouraged from doing so by the possibility that metering might become competitive soon. With the prospect of competitive metering on the horizon, utilities have had no guarantee that they will be able to recoup that up-front investment.

"The end result is that customers are losing out on the benefits that advanced metering would provide. Once the PUC provides the necessary certainty, the appropriate parties will be able to provide advanced metering to customers. Only then will customers realize the full benefits of electric competition."

The Technology: Toward an Open Architecture

"The basic problem," says the engineer from California, "is to make it easier to plug in another generator than it is to plug in another toaster."

He continues. "Whether a $25 million AMR system is a good deal overall for SDG&E's ratepayers depends on many interrelated issues. First, is the technology based on an open architecture that allows incremental upgrades over time, in an upcoming period that promises dramatic advances in the services and value that such a system might provide customers, or is it based on a proprietary system that locks consumers into 1990s technology, or worse? Second, does the initial system enable multiple types of transactions between consumers and competing sources of services, or will it effectively limit consumer interaction to the existing monopoly service providers?"

Nevertheless, Bill Rush is bullish on the SDG&E plan. He sees it as a step forward for open architecture in metering systems. By crafting its RFP to require compliance with certain technical and operational standards, Rush believes that SDG&E has opened the door to true plug-and-play in metering systems, in the utility's choice of vendor, and in the consumer's choice of energy supplier.

"Let me tell you what is really going on." According to Rush, "both Southern California Edison Co. and San Diego Gas & Electric are well-versed in the standards. They understand ANSI C12.18, the optical port standard, which requires a physical interface and a blinking infrared light-emitting diode that sends data, according to codes and protocols and format requirements set down in ANSI C12.19. And, as I understand it, the request for proposals in the SDG&E case requires compliance with ANSI C12.18. Moreover, it says that compliance with C12.19 is 'preferred.' And from my conversations with folks at SDG&E, I interpret that 'preference' as a very strong one."

Rush sees this RFP as the real deal for the metering industry. "This puts C12.19 on the map. In fact, from what I understand, SDG&E has received substantial interest and feedback from vendors on its RFP. Here we have a very large order for standards-compliant equipment. I predict that C12.18 & C12.19 will now become the accepted standards in the industry. Heck, Canada has already mandated the C12.19 standard, beginning Jan. 1, 2001, subject to certain grandfather exceptions."

And more than just inviting compliance with the standards, Rush emphasizes that some utilities themselves are starting to embrace standards-moving away from reliance on proprietary technology.

"There are several U.S. utilities requiring compliance with both C12.18 and C12.19 for electric meters. I can't tell you who those utilities are-that's confidential information. But I can tell you is that the rumor is afoot that the Southern Co. [its operating subsidiaries] are requiring C12.19. Thus, this rollout [by SDG&E] is very significant from a technical point of view."

Will standardization make installation easier?

"It can be done," predicts Rush. "But I would not regard this as a cakewalk," he adds. "The C12.19 standard is not easy to specify. There is some possibility that manufacturers might have some different interpretations of what the standard means.

"Of course, if you're after the cheap—if you're after the lowest bidder—then you might go with a proprietary protocol," says Rush. "But that might be counterproductive in the long run. You see, with C12.19, anybody can now read that meter. Not only can Schlumberger, Itron, ABB, and the rest of the metering industry read the meters, but so can GreenMountain.com and the other competitive retailers and ESPs. And so can a media company like AOL. When that happens, you truly have open architecture."

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