Rising
Power Prices: The Metering Industry's Big Break?
October 1, 2000
By Bruce W. Radford
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 (A. 00-07-055), 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," Public Utilities Fortnightly, 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." (See Va.St.Corp.Comm'n, Case No. PUE000346, filed Aug. 24, 2000).
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. (See Sidebar, "The Installation: A Real-Time Timeline.")
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."
(Note: The draft report
on uniform business standards issued in July by the Edison Electric Institute's
working group on unbundled metering services appears to stop short of
requiring compliance with ANSI C12.19. See www.ubpnet.org.)
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."
Bruce W. Radford is editor-in-chief
of Public Utilities Fortnightly.
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