The industry continues to debate the costs and technology of automated meter reading, even as some regulators insist on immediate implementation.
It is a choice, but might it soon be a mandate? Federal and state regulators-now more proactive after the industry credit crisis-want to know utility costs with precision (especially with all the rate increase requests recently), and they want to achieve conservation, market monitoring, or demand-side measures possible only through automated meter reading (AMR). Utilities that haven't adopted metering technology may soon be ordered to do just that.
Take Idaho Power, which went into a cost adjustment proceeding last year asking for a rate increase to spread over three years. Instead, it was ordered to recover costs in one year, and to adopt a 30-cent surcharge to look into issues relating to time-of-use (AMR implementation was not the initial focus), according to Idaho PUC officials. The Energy Efficiency Advisory Group (EEAG), established as a result of the Idaho PUC order, would examine how these policies might blunt future rate increases.
Furthermore, in two other cases,1 the commission asked the EEAG to evaluate and report to the Idaho PUC on the viability of a time-of-use residential metering program by Sept. 12, 2002. After soliciting comments on Idaho Power's report, the commission declined to authorize residential time-of-use rates.
However, following the study, the Idaho PUC directed the company to begin installing an AMR system this year, with installation completed in 2004. The company disagreed with the commission staff's calculation of the cost-effectiveness of AMR, and it now contends that implementing AMR over a four-year period (2004-07) would cost $86.5 million. Idaho Power predicted that its customers would incur greater costs through AMR for the first six years after the meters are installed and would not break even until 2024. However, Idaho Power believes AMR will become more cost-effective as technology advances, lowering the price of technology, and as AMR is viewed as a viable option for lowering employee costs.
At press time, the Idaho PUC was requesting comments by Aug. 15 on: 1) whether the company should be directed to install AMR; 2) how advanced metering technology could help the company and its ratepayers make the most of advanced technology; 3) the types of technology that should be employed; 4) the time frame for implementation; and 5) how the company could recover costs associated with AMR.
The issue of whether a PUC should order AMR implementation is a point of contention, as is the price of implementation. For instance, the Demand Response and Advanced Metering Coalition (DRAM), in comments filed with the Idaho PUC, believes the $70 million to $80 million estimate for an AMR system "is substantially too high." DRAM believes implementation would cost $30 million. Furthermore, whether to adopt fixed radio network, mobile, phone line, or power line carrier technology is debated heatedly within demand-side circles and among utility executives.
Also, the recent merger of AMR vendors SchlumbergerSema and Itron has many utility executives worried that one platform and service will be favored over the other, a worry that makes choosing an AMR technology doubly difficult.
Metering Inaccuracies and California
The California crisis has shaped regulators' new AMR politics. Regulators such as the Idaho PUC believe the technology will allow utilities to save money in areas beyond meter reading, including real-time service outage reporting; tamper- and theft-proof reporting; and a reduction in the wholesale cost of power during peak demand periods. Moreover, AMR could significantly reduce operational costs and the potential for error.
The Florida Public Service Commission (PSC) is investigating that potential. Florida Power & Light Co. in July said some large commercial customers may have been improperly charged for electricity because of faulty meters. But the utility was unsure of the extent of the underbilling. Problems arose from the use of thermal-demand meters, which the utility has been replacing with more accurate meters. The PSC has opened an investigation into the matter. The state's consumer advocate is worried that the underbillings may have been treated as line losses paid for by commercial as well as residential customers. Refunds could be warranted, the PSC said.
The issue of underbilling takes on a sinister tone in California. On Dec. 24, 2002, an article in the noted that Enron Corp. agreed it had underpaid the California Independent System Operator (ISO) by as much as $50 million because of meter reading errors attributed to its contractor, Computer Sciences Corp. The Times reported that Enron disclosed the problem in a letter to the ISO stating that Computer Science Corp. erred by not reading some meters at all, and reading other meters on a monthly basis instead of daily or more often.
But critics say the paper grabbed onto only a small portion of the story. They say there is a great discrepancy between wholesale reporting and retail revenue reporting in California, which perhaps could be more evidence of market manipulation through Unaccounted For Energy (UFE). That brings into question the accuracy by which the ISO calculates UFE and spreads those costs across all the market participants. Ultimately it is the ratepayers of the "other" market participants who are paying for the meter data errors. Some say that since the energy crisis in April 2000 and the rise of energy prices, under-reported usage has become the norm, and some energy service providers may be responsible for as much as 50 percent of the error.
Critics say the market structure is not set up to allow oversight into the potential irregularities of reporting meter data by market players because FERC and CPUC jurisdiction overlap in the metering arena. The ISO, under FERC jurisdiction, is responsible for oversight of UFE calculations. Meanwhile, retail end users, through their local utility or energy service provider, fall under CPUC jurisdiction. Customers' historical usage patterns that could be used as a reasonableness check against the accuracy of the meter data submitted by the utility or ESP are not available to the ISO.
Critics believe that the situation occurs due to the market structure and the information available to the key players in the market. The root problem is that no entity has jurisdiction for end-to-end quality control of the wholesale and retail metering data.
Some help may come from a mandated, statewide residential pilot program. The California PUC initiated a rulemaking to set AMR standards for smaller customers of the state's three largest investor-owned utilities, including Southern California Edison (SoCalEd).2
David Berndt, manager of meter strategy integration at SoCalEd, explains that the PUC wants to evaluate AMR for customers below 200 kW demand, for example, setting rules on how to move forward and what kind of participation to expect, which might help the business case for advanced metering. SoCalEd has installed approximately 1,000 meters in its service territory, and Berndt is hopeful customers will see the value of price signals and respond accordingly by adjusting their energy usage. "That would affect our procurement costs, hopefully lowering them, which could contribute to the financial business case which would help justify AMR," he says. "That is not based on charging customers for more services. It is clearly based on reduced procurement costs in peak periods."
For customers 200 kW and above, the California Energy Commission (CEC) sponsors a pilot program for installation of AMR, which entails communication of 15-minute demand information for all those larger commercial and industrial customers. The CEC provides $35 million worth of meters for the large customer AMR trial as required by Assembly Bill 29X, signed into law on April 11, 2001. Both AMR pilots for large and small customers are in the trial stages.
Wireless, Mobile, or Outsourced
Utilities continue to disagree on which technology best fits their service territory.
National Grid, for its New England-based companies, decided on a technology using a van-based, drive-by system, which entails driving around the service territory to pick up a signal from an ERT (encoder, receiver, and transmitter) in the meter. Such technology makes it possible to read about 10,000 meters a day.
The company decided to try installation of AMR in a small segment of its service territory, retrofitting about 300,000 of the 400,000 electric meters in Rhode Island. (National Grid's New England subsidiaries are Massachusetts Electric, Narragansett Electric, Granite State Electric, and Nantucket Electric).
Although Barbara Hassan, senior vice-president of customer service for National Grid's New England Distribution Cos., says it was "really hard to do the cost-benefit analysis and make it work," the company knew AMR was "the right thing" before half the installations had been completed. That led to the decision to retrofit all the other residential accounts that were in Rhode Island.
According to Tom Converse, director of meter operations at NSTAR, about half the company's 1.3 million customers are equipped with AMR. He explains that prior to the merger in 1999 of Boston Edison and Commonwealth Energy to create NSTAR, the companies had two different goals regarding metering.
The original, pre-merger AMR deployments in Boston Edison and Commonwealth Energy both were retrofits of the traditional, electromechanical meters. Some new meters were purchased, along with the retrofits, depending on the vintage and life expectancy of the meters.
Now NSTAR has standardized, buying all solid-state meters, and it no longer retrofits. The demand AMRs are bought from Elster. "There really only are two vendors that had it-Elster and SchlumbergerSema, and Elster was the only system that tied to the Itron system that we use for meter reading," Converse says. NSTAR uses the Itron Premierplus4 meter reading system.
NSTAR owns and operates all its metering and meter reading technology. Converse says that because of the difficulties involved in reading indoor meters, Boston Edison used to bill bimonthly. AMR has allowed it to move to monthly meter reads and billing.
"On the large commercial side we are going to time-of-use metering that is going to be read remotely and daily," Converse says. "So we expect to be able to offer some new service in the future, but we are waiting until we get a sizeable population installed until we push it." Future services include e-mail on outage notification, power quality enhancements, and daily reporting of exact numbers, instead of estimates, to the New England ISO.
"We continue to install AMR and target it via cost-per-read analysis on residential meters," Converse says. "Our composition of 1.3 million customers is about 5,000 time-of-use and 60,000 commercial demand, and the rest are residential." But some areas will not get AMR. For example, NSTAR has service areas where meter-read percentages are very high, and the number of meters on a route is very high, so an internal rate-of-return analysis does not justify AMR.
Moreover, those utilities worried about AMR being mandated, and about the costs, might rent rather than buy. That's what PECO did.
Sandy Goodwin, energy usage manager at PECO, says AMR technology is not something PECO would take to the PUC to ask for rate relief. Instead, it is an outsourced needs-for-services contract with SchlumbergerSema and is classified as an O&M (operations and maintenance) expense. She said it was easily justified because it reduced the company's overall O&M expenses.
PECO made the decision to retrofit 50 percent of its electric meters-everything that was retrofittable. The balance was replaced with SchlumbergerSema electric meters.
"We are the eighth utility in the United States to deploy a SchlumbergerSema fixed wireless network," says. "We were the largest, but we were not the first." At the time PECO evaluated AMR, the majority of the AMR users chose mobile, drive-by technology. Goodwin says PECO evaluated all available AMR technology, including drive-by, and narrowed the options down to a half dozen. "What drove us to the SchlumbergerSema solution was two things: It met or exceeded all of our business requirements, and it also used proven technology," she explains. "Also, it offered an opportunity for the future in the way that we structured our contract to get more data from our meters if we needed it. And the price was very favorable."
Mark Strutz, manager of AMR strategies at PECO, says AMR produced opportunities where PECO may have not been capturing all the revenue, or "tariff-enabled" opportunities-charging for energy that the company may not have been charging for because of limitations with the old metering. Strutz says one example is power factor, or the result of energy being delivered as real energy and reactive energy. While meters meter real energy, certain meters only meter reactive energy. "Our new AMR system allows us to measure this other form of energy and make more revenues than in the past via adjustments to invoices," he says. "So we're coming up with lots of additional value that we didn't anticipate, and it is just making our business case stronger and stronger." Certainly, with talk like this, regulators will listen, and act accordingly.
PECO has bundled information from those meters and "packaged that in a pretty slick, Web-based service that allows our larger C&I customers to assess their energy usage and make decisions around how they are consuming energy," Strutz says. The "Evaluator" service launched a few years ago and has been received very well across PECO's market. "We know that because it is an annual subscription and many of our larger customers have renewed their subscriptions or the service," Strutz says. PECO also just launched a service called "Billing Estimator."
David Berndt, manager of meter strategy integration at Southern California Edison, says about 500,000 of the company's 4.5 million electric meters have been changed over to AMR. The utility has a handful of residential customers with advanced metering, which is read by drive-by, so there is no backbone communication system installed.
Berndt finds that for the residential sector, without drive-by, "the business case has not been positive." SoCalEd had done a small-scale deployment of residential AMR but has not gone any further.
Berndt says SoCalEd uses an Itron ERT model for communications and will use any meter that can be retrofitted to comply with that system. But the technology the utility might go with on a systemwide AMR deployment is not locked in yet. The drive-by AMR system in place could change.
"I don't want to leave you with the impression that we have a specific plan in place today to do that because we don't," he cautions. "We are evaluating the technologies, we are looking at the costs, and we are especially watching what happens with this order instituting rulemaking to determine how this test comes out and see how the public responds to price signals." He believes the test of how customers respond will make a big difference to the business case to determine if AMR is financially feasible.
Remember, regulators will be watching.
- Case nos. .
- Re Order Instituting Rulemaking on policies and practices for advanced metering, demand response, and dynamic pricing, , June 10, 2002 (Cal.P.U.C.).
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