Northeast states avoid meter squabbles, stress electronic commerce.
It ain't the chip, it's the interface. That's the ticket in New England and the Northeast, where utilities, power producers, retailers and marketers are standardizing electronic data transfers of customer lists, enrollment choices, energy consumption and billing determinants - the business information that will be prove essential to a working competitive market in electricity. They've done that by postponing the question of unbundling for meter equipment, software and related technology, focusing instead on the commercial transactions that must take place at network- and client-server-level interface between distribution utilities and generation suppliers.
Contrast that with California, where policymakers had decided early on that electric competition wouldn't work without opening metering and billing at the same time, and then tried to set standards for the equipment itself.
In Pennsylvania, Massachusetts and Connecticut, industry working groups have recommended standards for electronic data interchange, or EDI, with regulators close to issuing final approvals. At press time, Pennsylvania was rushing to finish testing EDI rules in time for bills to go out at the end of January, the first month of full-scale retail electric competition, and for the first exchange of EDI-based transactional information, set for Feb. 1. Connecticut regulators approved a set of EDI standards in mid-January. In New York, recommendations were expected by May. Much of the initiative had come from the Utility Industry Group, an ad hoc group of representatives from utilities and energy suppliers formed in the late 1980s to foster national EDI standards for the energy industry. Funded by the Edison Electric Institute, the UIG functions under the umbrella of ASC X12, the Accredited Standards Committee formed by the American National Standards Institute to set standards for EDI.
But last summer in California, meter vendors were jostling technology and proprietary systems. Industry infighting over meter-level data formats diverted California's Permanent Standards Working Group. Not long after the PSWG had submitted its report to the state Public Utilities Commission in July, some questioned the result, alleging that the PSWG failed to achieve its PUC-assigned mission because it ran out of time before setting network-level communications standards.
Chris King, vice president at CellNet, a meter system vendor, highlights the difference in strategies: "EDI standards are independent of metering technologies, because they specify data transfer formats at the server level." According to King, CellNet has "strongly supported national EDI standards, and "has shared information from the various states, hoping to help the process."
Of course, the New England and Northeast states must eventually consider the tough questions. Is competitive metering required or simply optional? Should EDI standards require transfers of or access to interval usage or meter reads, even if utilities must incur high costs to extract such data? Should EDI set employ value-added networks, or VANs, for data communications, which have proven reliable? Or should standards rely instead on the Internet, which is cheaper, "but not yet common," says King, who adds that Internet use is required or planned in California, Nevada and Arizona.
In Massachusetts, the state restructuring statute postpones competition for metering, billing and information systems until Jan. 1, 2000, at the earliest. New York has yet to formally adopt competitive metering. And even in Pennsylvania, the PUC appeared to retreat after legislative committees rebuffed initial rules to open metering to competition. The new rules, issued last October, no longer mandate unbundling, but instead make it permissive. By postponing the metering question, the East Coast grabbed the momentum on EDI.
"We now have a multi-state EDI working group, for the entire eastern region," notes Peter Byrne, EDI consultant for GPU Energy, and chairman of the UIG. "The more states that adopt our standards, the more difficult it becomes to change them.
"Back when Massachusetts, New Hampshire and Rhode Island got into this, we [UIG] had not yet perfected all the standards. But now the California working groups are moving toward the UIG conventions, as is Massachusetts. Pennsylvania has mandated the UIG conventions. New York is leaning that way, and perhaps Maryland.
"And there's a group that's been meeting in New Jersey," adds Byrne, "preparing for when things get moving. They've approved the UIG guidelines. If and when New Jersey passes its restructuring, we'll be ready."
Buried in the UIG guidelines for EDI implementation lies this frank warning: "Avoid loose, careless or flippant remarks, especially in correspondence, that can pose an antitrust problem for UIG if examined out of context at a later date." The guidelines then go further, acknowledging that business standards "may necessarily result in a disadvantage to competitors of UIG members."
When asked whether UIG members imagine themselves representing their employers, the electric industry, or the group itself, UIG vice chair Johnny Robertson, from Texas Utilities, put it this way: "We're working under the ASC X12 umbrella. We have to get [prior] approval from the ANSI on whatever we do. We are a working committee under ASC X12."
Robertson continued, "As a member of a working group, in some committees, I'd be representing the UIG. But it's difficult to say who you'd be representing. So far, everything that the UIG has presented has been acceptable. A meter read and an activation date is the same, no matter what state you're in. It's a common format."
"The PUCs support EDI," adds Bill Hunsicker, senior technical consultant for SCT, which provides client-server and supply-chain software systems for energy service companies, such as PG&E Energy Services and Edison Source. Hunsicker, a member of New York's EDI working group, adds, "A supplier who works within one state then can go into another state without doing extra work."
Hunsicker notes that if a working group member was torn between the group recommendation or what's best for his employer, the case might well involve a transfer of data not easily retrievable using the employer's current software.
In the Pennsylvania EDI proceeding, the PUC appeared to confirm Hunsicker's thinking. It noted that with progress in EDI implementation, "There have been some computer system difficulties. ¼ It must be remembered that the [utilities] will have to continue to work with legacy systems. ¼ [We have] experienced unanticipated problems with respect to the ability of the [utilities] to extract the essential information."
Should this "data extraction" problem excuse utilities from going beyond consumption data to provide interval data, such as actual meter reads?
In the Connecticut EDI proceeding, NorAm Energy Management Inc. intervened to argue that if a utility had access to interval (e.g., hourly) metering data, it would have an advantage over electric suppliers if it did not provide them with the same information. The issue arose again in Pennsylvania, where GPU expressed concern that it might be required to produce actual hourly demand data by customer account, "even when interval data does not exist."
The PUC put the utility at ease: "We do not expect the metering entity to transmit data that exceeds the general capability of the metering equipment installed at the customer's site, nor do we anticipate the installation or use of any interval meter which would not be directly related to the method used for billing the customer."
The PUC then added, "We do not believe that it is reasonable to imply that [a supplier] would develop a customer price schedule that does not reflect the [utility's] tariff rates nor the physical capability of the customer's installed metering device."
Thus, the PUC policy might appear to discourage supplier innovation in services and pricing. It would bar supplier pricing strategies not possible using current metering equipment, and the PUC's most recent incarnation of metering rules would not require unbundling, but would only require utilities to install advanced meters or related devices on a written request from both a customer and the customer's supplier.
In the Connecticut case, however, the commission denied a request by CellNet for incentives for advanced or network metering. It feared that such incentives could discriminate against rural areas, which already suffered inferior reliability. It explained that current metering capability (with utilities free to offer metering options to customers) was "adequate" for retail competition, as state law didn't permit competitive metering or billing.
It was just this problem - older meters limiting customer choice - that had persuaded California regulators to include competitive metering as an essential element of that state's competitive regime. However, that move unwittingly delayed EDI in California, when the PSWG reported back to the PUC last July by recommending the ANSI C12.19 standard for data format at the meter equipment level, but without any consensus for a data communications standard at the meter server level.
The PSWG report had suggested that so-called "plug-and-play" standardization was impossible: "[H]aving universal interoperability and interchangeability between the meter and data retrieval technologies is not feasible without constraining technological alternatives."
However, in a joint statement issued last fall, the California Office of Ratepayer Advocates questioned that claim, joined by the Electric Power Research Institute and Standards Coordinating Committee 31 of the Institute of Electrical and Electronics Engineers:
"If true interoperability is to be achieved, all the pieces of the system must be linked through a completely defined set of standard interfaces."
On Dec. 17, in a complex decision running over 100 pages, the PUC cautioned against too much definition, but it favored EDI over technology-laden standards, like C12.19.
Back at the UIG, Peter Byrne summed it up: "We see us fitting in with the PUCs in keeping the costs down. If this whole process ends up being more expensive for customers, then we've failed."
Bruce W. Radford is editor of Public Utilities Fortnightly.
The PUC Process Testing and confirmation continues nonstop.
California. Orders EDI on trial basis by Sept. 1, with full compliance by Feb. 1, 2000. Decision 98-12-080, Dec. 17, 1998.
Connecticut. Adopts report of working group proposing UIG EDI standards by Jan. 1, 2000. Utilities must provide historic customer usage on supplier request, but not interval data. Dkt. No. 98-06-17, Jan. 13, 1999.
Massachusetts. Working group recommends EDI standards based on UGI guidelines, Apr. 18, 1998, and issues additional reports modifying standards. Group reportedly expanding EDI standards to encompass gas restructuring. See http://www.eua.com/restructdocs.htm.
New Hampshire. Working group submits consensus EDI plan. DR 96-150. Apr. 2, 1998. As of January 1999, PUC staff believed to be working on draft initial proposal for EDI, metering requirements. DRM 98-050, DRM 98-051.
New York. Adopts staff recommendation to set up collaborative working group, to achieve EDI implementation during spring 1999. Case 98-M-0667, July 15, 1998.
Pennsylvania. PUC adopts and modifies EDI standards in four recent orders. Dkt. No. M- 00960890F.0015, June 18, 1998, Aug. 18, 1998, Sept. 17, 1998, Nov. 4, 1998. Adopts rules allowing for advance meter deployment, on joint request by customer and supplier, but no mandate for competitive metering. Dkt. No. L-00970128, 189 PUR4th 162, Oct. 19, 1998.
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