CCN Comments on 20-50 kW report due 10/23/98
All,
Please see CCN comments attached (and below w/out footnote).
Eric Wouchik
CCN
510-635-2359
BEFORE THE PUBLIC UTILITIES COMMISSION OF
THE STATE OF CALIFORNIA
Order Instituting Rulemaking on the Commission's Proposed Policies
Governing Restructuring California's Electric Services Industry and
Reforming Regulation. R.94-04-031
(Filed April 20, 1994)
Order Instituting Investigation on the Commission's Proposed Policies
Governing Restructuring California's Electric Services Industry and
Reforming Regulation. I.94-04-032
(Filed April 20, 1994)
COMMENTS OF CALIFORNIA COMPETITION NETWORK, CELLNET DATA SYSTEMS, CHRISTIAN
ENERGY, ENERGY COMPLIANCE SYSTEMS, ENRON ENERGY SERVICES, KEYSTONE ENERGY,
POWERCOM ENERGY SERVICES, AND UTILISYS CORPORATION ON ENERGY DIVISION
REPORT ON EXEMPTION FROM THE METERING REQUIREMENT FOR CUSTOMERS WITH DEMAND
BETWEEN 20 AND 50 KW
Eric C.Woychik
Executive Director
California Competition Network
9901 Caloden Lane
Oakland, CA 94605
(510) 635-2359 (Telephone)
(510) 635-5669 (Facsimile)
Email: eric@gcnet.org
October 23, 1998
California Competition Network (CCN), CellNet Data Systems, Christian
Energy, Energy Compliance Systems, Keystone Energy, PowerCom Energy
Services, and Utilisys Corporation (Market Participants) generally support
the recommendations made in the Energy Division=s October 2, 1998 AReport
on Direct Access Load Profiling Workshop Ordered by D.97-10-086" (RLP) but
seek to provide some of the "whys" regarding the costs of interval metering
(IM). Market Participants, including CCN, have participated in many of the
workshops involving a wide range of direct access implementation issues
before the California Public Utilities Commission (Commission). The goal
of these comments is for Market Participants to present to the Commission
some of the many reasons why implementation of IM is not successful as part
of direct access (DA) and why IM is therefore not cost-effective in many
applications, including applications for 20-50kW customers. This is
consistent with the Commission’s intent, as explained in the RLP (PG.2):
"The purpose of that workshop shall be to examine the costs associated with
hourly interval metering, and its impacts on customers whose maximum
demands fall within the 20 to 50 kW range."
Market Participants are service providers for customers and others in the
energy industry. We can provide a unique and detailed view of the many
issues with IM costs, including meter technology, meter installation, meter
data transfer, meter acceptance, and meter data management implementation.
Market Participants believe that the largest single issue with IM
implementation is the excessive and unnecessary transaction costs (i.e.,
the set of costs necessary to complete the IM contract "deal") which are
involved.
Customers indirectly face overwhelming transaction costs for IM as a result
of the administrative costs which Market Participants must incur to meet
burdensome UDC requirements. Because of these high transaction costs, IM
lacks scale economies and scope economies which would make IM
cost-effective for many more customers. Furthermore, Market Participants
cannot effectively stimulate IM market penetration – customer acceptance --
because market barriers exist as manifest in the combination of transaction
costs and lack of scale and scope economies.
This leaves customers in the 20-50 kW class, and other customers as well,
without the benefits of IM. Load profiling does not capture the benefits
of market competition which can be achieved with IM. With significant
competition in power as a commodity and without IM, Market Participants
lack the capability to register (1) the benefits of market arbitrage across
time periods, (2) the benefits of customer demand management (day-ahead,
hour-ahead, and real time), and (3) opportunities to lower customer costs
during high priced periods. IM is essential to enable energy service
providers, schedule coordinators, and demand-management companies to
deliver the benefits of competition to customers. The general conclusion
posed by many participants in related workshops is that under current
market conditions, sufficient savings are not available to justify the
substantial investment that IM requires.
Market Participants believe that the current situation of high transaction
costs presents a Catch-22 where few customers choose IM, which limits the
meter scale and density needed to lower overall IM costs, with load
profiling the benefits of DA implementation are reduced, and accordingly
fewer customers choose DA. Thus, it becomes a self-fulfilling prophesy –
IM is not cost-effective because there is little IM implementation, which
reduces DA implementation as well, most importantly because the transaction
costs of IM are too high. The RLP (at pg. 4) numbers support this case:
out of about a total of 106,000 20-50 kW customers, 5000 are on direct
access, and about 225 use IM. While Market Participants agree with the
Energy Division’s RLP, critical reasoning is lacking to explain why IM is
not cost effective for 20-50 kW customers and others.
The Energy Division’s RLP did not define with any clarity the costs
for IM implementation. Accordingly, Market Participants offer to explain
to the Commission why the transaction costs related to IM implementation
are simply too high in California. Truly, the "Devil is in the details" of
IM meter installation, UDC coordination and approval requirements, meter
data transfer requirements, MDMA requirements, and the like. Eight
examples of excessive transaction costs with IM are presented. Many more
can be defined at the Commission’s request.
First, UDCs are implementing various IM related business and
oversight processes that cost a lot of money, many of which are
unnecessary. Market Participants believe that UDCs should be doing only
what is absolutely essential with respect to IM installation and
implementation. The Commission indirectly supports UDC intervention in
these many areas by allowing UDCs to receive cost recovery for IM
administration and for processes that are redundant or unnecessary.
Second, the Commission should rapidly adopt the universal Service Delivery
Point ID proposal, in order to streamline data exchanges. Parties to a
data exchange will then know they
are talking about the same site/meter/customer, even if account or meter
numbers don't match up (which otherwise means increased transaction costs).
It will be easy for parties to cross check which sites they are
responsible for, be it for energy, metering, etc. Thus, the Commission
should adopt the consensus proposal quickly and direct the parties to start
using it as soon as possible, based on input from the market participants
on reasonable timing.
Third, rapid adoption of standardized forms for meter specific
information exchange (work ongoing by PG&E) is essential to lower
transaction costs. The parties agree for the most part on these
information exchange formats already, and no Commission action is needed.
Fourth, more flexible scheduling is needed to allow IM installers lower the
costs of schedule coordination, "joint meets," and to achieve greater scale
economies through the ability to add last-minute changes to their
schedules.
Fifth, the Commission should approve a market option for customers to be
switched to DA, and then allow meter installation to occur at a later date,
say within 90 days. This would allow rational installation, planning, and
achieving of scale economies without delaying the customer's switch. The
customer would continue to be load profiled until the new meter is
installed.
Sixth, a number of other UDC interpretations which create major
costs for IM installers are illustrative. Where the tariff says "notify"
the UDC of installs, the UDC requires that IM installers must "schedule" a
meeting with them, which dramatically increases costs because of the
logistics and transactions necessary to perform the "joint meet."
Furthermore, the paperwork required by UDCs is in excess of 1/2 hour for
each meter install. In addition, UDC information is inaccurate and cannot
be relied upon, but the IM installer’s information must be 100 percent
accurate. When IM installers attempt to clarify who is to keep metering
records, if it is the MSP who is responsible, then the UDCs don't need this
clarification – ESP metering is not part of the UDC-mandated form – but if
the UDC is the meter reading agent then the MSP must give accurate data to
the UDC and the MSP cannot maintain any related records.
Seventh, UDCs require that IM installers provide detailed data on
meter type and characteristics before installation, even when the UDC is
not the MSP or even the billing agent. Some UDCs require a filing to
define all meter attributes 30 days before IM installation. This could at
least be simplified if the UDCs would accept this information within a
reasonable time after IM installation.
Finally, the DASR process is interpreted by some UDCs to require
only one ESP at a time to be responsible for meter data and customer
access, but usually an ESP relies on an agent to be IM installer, which
sets up a complicated situation where the UDC must be notified, a priori,
when the IM installer goes on the customer premise. This requires two
notices of "change in the ESP," with the additional scheduling and record
keeping. Market Participants ask why the UDC needs to be in the middle of
each of these transactions, particularly if it is not the ESP or MSP?
Market Participants appreciate the opportunity to comment on these
matters and request that the Commission investigate the opportunities to
lower the overall transaction costs of IM, in order to deliver the benefits
of DA to as many customers as possible as soon as possible. Market
Participants stand ready to assist the Commission with additional
information and insight on any of these related matters.
October 23, 1998 Respectfully submitted,
Eric C. Woychik
Executive Director
California Competition Network
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\qc\nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640 \f4 {\b BEFORE THE PUBLIC UTILITIES COMMISSION OF
\par THE STATE OF CALIFORNIA
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\brdrs\brdrw15\brdrcf8 \cellx9360 \pard \sl-120\slmult0\nowidctlpar\intbl
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Order Instituting Rulemaking on the Commission's Proposed Policies Governing Restructuring California's Electric Services Industry and Reforming Regulation.\cell \pard \sl-120\slmult0\nowidctlpar\intbl
\par \pard \nowidctlpar\intbl\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640
\par R.94\_04\_031
\par (Filed April 20, 1994)
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Order Instituting Investigation on the Commission's Proposed Policies Governing Restructuring California's Electric Services Industry and Reforming Regulation.\cell \pard \sl-120\slmult0\nowidctlpar\intbl
\par \pard \nowidctlpar\intbl\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640
\par I.94\_04\_032
\par \pard \sa58\nowidctlpar\intbl\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640 (Filed April 20, 1994)\cell \pard \widctlpar\intbl \row \pard
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COMMENTS OF CALIFORNIA COMPETITION NETWORK, CELLNET DATA SYSTEMS, CHRISTIAN ENERGY, ENERGY COMPLIANCE SYSTEMS, ENRON ENERGY SERVICES, KEYSTONE ENERGY, POWERCOM ENERGY SERVICES, AND UTILISYS CORPORATION ON ENE
RGY DIVISION REPORT ON EXEMPTION FROM THE METERING REQUIREMENT FOR CUSTOMERS WITH DEMAND BETWEEN 20 AND 50 KW}
\par \pard \nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640
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\par \pard \fi5040\nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640 Eric C.Woychik
\par Executive Director
\par California Competition Network
\par 9901 Caloden Lane
\par Oakland, CA 94605
\par (510) 635-2359 (Telephone)
\par {\pntext\pard\plain (510) \tab}\pard \fi-360\li5400\nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640{\*\pn \pnlvlbody\pndec\pnb0\pni0\pnf4\pnfs24\pnstart510\pnindent360\pnhang{\pntxtb (}{\pntxta ) }}
635-5669 (Facsimile)
\par \pard \li5040\nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640 Email: eric@gcnet.org
\par
\par \pard \nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640
\par October 23, 1998
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California Competition Network (CCN), CellNet Data Systems, Christian Energy, Energy Compliance Systems, Keystone Energy, PowerCom Energy Services, and Utilisys Corporation (Market Participants) generall
y support the recommendations made in the Energy Division{\f36 =}s October 2, 1998 {\f36 A}Report on Direct Access Load Profiling Workshop Ordered by D.97-10-086\rdblquote (RLP) but seek to provide some of the \ldblquote whys\rdblquote
regarding the costs of interval metering (IM). Market Participants, including CCN, have participated in many of the workshops involving a
wide range of direct access implementation issues before the California Public Utilities Commission (Commission). The goal of these comments is for Market Participants to present
to the Commission some of the many reasons why implementation of IM is not successful as part of direct access (DA) and why IM is therefore not cost-effective in many applications, including applications for 20-50kW customers. This is consistent with th
e Commission\rquote s intent, as explained in the RLP (PG.2): \ldblquote
The purpose of that workshop shall be to examine the costs associated with hourly interval metering, and its impacts on customers whose maximum demands fall within the 20 to 50 kW range.\rdblquote
\par Market P
articipants are service providers for customers and others in the energy industry. We can provide a unique and detailed view of the many issues with IM costs, including meter technology, meter installation, meter data transfer, meter acceptance, and mete
r data management implementation. Market Participants believe that the largest single issue with IM implementation is the excessive and unnecessary transaction costs (i.e., the set of costs necessary to complete the IM contract \ldblquote deal\rdblquote
) which are involved.
\par \pard \qj\fi720\sl480\slmult1\nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640
Customers indirectly face overwhelming transaction costs for IM as a result of the administrative costs which Market Participants must incur to meet burdensome UDC requirements. Because of these high transaction costs, IM lacks scale economies and scope
economies which would make IM cost-effective for many more customers. Furthermore, Market Participants cannot effectively stimulate IM market penetration \endash
customer acceptance -- because market barriers exist as manifest in the combination of transaction costs and lack of scale and scope economies.
\par \pard \qj\fi720\sl480\slmult1\nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640
This leaves customers in the 20-50 kW class, and other customers as well, without the benefits of IM. Load profiling does not capture the benefits of market competition which can be achieved with IM. With significant competition in power as a commodity
and {\b without} IM, Market Participants lack the capability to register (1) the benefits of market arbitrage across time periods, (2) the benefits of customer demand management (day-ahead, hour-ahead, and real
time), and (3) opportunities to lower customer costs during high priced periods. IM is essential to enable energy service providers, schedule coordinators, and demand-management companies
to deliver the benefits of competition to customers. The general conclusion posed by many participants in related workshops is that under current market conditions, sufficient savings are not available to justify the substantial investment that IM requir
es.
\par \pard \qj\fi720\sl480\slmult1\nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640 Market Participants believe that the c
urrent situation of high transaction costs presents a Catch-22 where few customers choose IM, which limits the meter scale and density needed to lower overall IM costs, with load profiling the benefits of DA implementation are reduced, and accordingly few
er customers choose DA. Thus, it becomes a self-fulfilling prophesy \endash
IM is not cost-effective because there is little IM implementation, which reduces DA implementation as well, most importantly because the transaction costs of IM are too high. The RLP (
at pg. 4) numbers support this case: out of about a total of 106,000 20-50 kW customers, 5000 are on direct access, and about 225 use IM. While Market Participants agree with the Energy Division\rquote s RLP, critical reasoning is lacking to explain {\i
why} IM is not cost effective for 20-50 kW customers and others.
\par \pard \qj\sl480\slmult1\nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640 \tab The Energy Division\rquote s RLP did not define with any clarity the costs for IM implementation.{\cs15 \chftn {\footnote
\pard\plain \nowidctlpar \f4 {\cs15 \chftn } {\fs20 As the RLP states (at pg. 6), \ldblquote
the Energy Division concludes that (1) the available market information and experiences of direct access participants are still insufficient to answer this question with any analytical precision; and (2) anecdotal e
vidence and everyday observations strongly suggest that the costs associated with hourly interval metering render the purchase of a meter for direct access uneconomic.\rdblquote }
\par }} Accordingly, Market Participants offer to explain to the Commission why the transaction costs related to IM implementation are simply too high in California. Truly, the \ldblquote Devil is in the details\rdblquote
of IM meter installation, UDC coordination and approval requirements, meter data transfer requirements, MDMA requirements, and the like. Eight examples of excessive transaction costs with IM are presented. Many more can be defined at the Commission
\rquote s request.
\par \tab First, UDCs are implementing various IM related business and oversight processes that cost a lot of money, many of which are unnecessary. Market Participants beli
eve that UDCs should be doing only what is absolutely essential with respect to IM installation and implementation. The Commission indirectly supports UDC intervention in these many areas by allowing UDCs to receive cost recovery for IM administration and
for processes that are redundant or unnecessary.
\par \pard \qj\fi720\sl480\slmult1\nowidctlpar Second, the Commission should rapidly adopt the universal Service Delivery Point ID proposal, in order to streamline data exchanges. Parties to a data exchange will then know they
\par \pard \qj\sl480\slmult1\nowidctlpar are talking about the s
ame site/meter/customer, even if account or meter numbers don't match up (which otherwise means increased transaction costs). It will be easy for parties to cross check which sites they are responsible for, be it for energy, metering, etc. Thus, the Com
mission should adopt the consensus proposal quickly and direct the parties to start using it as soon as possible, based on input from the market participants on reasonable timing.
\par \pard \qj\sl480\slmult1\nowidctlpar \tab Third, rapid adoption of standardized forms for meter specific information e
xchange (work ongoing by PG&E) is essential to lower transaction costs. The parties agree for the most part on these information exchange formats already, and no Commission action is needed.
\par \pard \qj\fi720\sl480\slmult1\nowidctlpar Fourth, more flexible scheduling is needed to allow IM installers lower the costs of schedule coordination, \ldblquote joint meets,\rdblquote
and to achieve greater scale economies through the ability to add last-minute changes to their schedules.
\par \pard \qj\fi720\sl480\slmult1\nowidctlpar Fifth, the Commission should approve a market option for customers to be switched to DA, a
nd then allow meter installation to occur at a later date, say within 90 days. This would allow rational installation, planning, and achieving of scale economies without delaying the customer's switch. The customer would continue to be load profiled un
til the new meter is installed.
\par \pard \qj\sl480\slmult1\nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640 \tab
Sixth, a number of other UDC interpretations which create major costs for IM installers are illustrative. Where the tariff says "notify" the UDC of installs, the UDC requires that IM installers must "schedule" a meetin
g with them, which dramatically increases costs because of the logistics and transactions necessary to perform the \ldblquote joint meet.\rdblquote
Furthermore, the paperwork required by UDCs is in excess of 1/2 hour for each meter install. In addition, UDC information is inaccurate and cannot be relied upon, but the IM installer\rquote
s information must be 100 percent accurate. When IM installers attempt to clarify who is to keep metering records, if it is the MSP who is responsible, then the UDCs don't need this clarification \endash ESP metering is not part of the UDC-mandated form
\endash but if the UDC is the meter reading agent then the MSP must give accurate data to the UDC and the MSP cannot maintain any related records.
\par \pard \qj\sl480\slmult1\nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640 \tab
Seventh, UDCs require that IM installers provide detailed data on meter type and characteristics before installation, even when the UDC is not the MSP or even the billing agent. Some UDCs require a filing to define all meter attributes 30 days before IM
installation. This could at least be simplified if the UDCs would accept this information within a reasonable time after IM installation.
\par \pard \qj\sl480\slmult1\nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640 \tab
Finally, the DASR process is interpreted by some UDCs to require only one ESP at a time to be responsible for meter data and customer access, but usually an ESP relies on an agent to be IM installer, which sets up a complicated situation where the UDC mu
st be notified, {\i a priori}, when the IM installer goes on the customer premise. This requires two notices of \ldblquote change in the ESP,\rdblquote with the additional scheduling and record keeping
. Market Participants ask why the UDC needs to be in the middle of each of these transactions, particularly if it is not the ESP or MSP?
\par \tab Market Participants appreciate the opportunity to comment on these matters and request that the Commission investigate the opportunities to lower the overall transaction costs of IM, in order to deliver the benefits of DA
to as many customers as possible as soon as possible. Market Participants stand ready to assist the Commission with additional information and insight on any of these related matters.
\par \pard \fi720\sl480\slmult1\nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640
\par \pard \nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640 October 23, 1998\tab \tab \tab \tab Respectfully submitted,
\par
\par \pard \fi4320\nowidctlpar\tx0\tx720\tx1440\tx2160\tx2880\tx3600\tx4320\tx5040\tx5760\tx6480\tx7200\tx7920\tx8640 Eric C. Woychik
\par Executive Director
\par California Competition Network
\par }