CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
2.1.1 Regarding Chapter 7, Borden’s Testimony on Rate Design, please answer the
following questions:
Question 2.1.1: Referring to page DAB-3, lines 3-12:
2.1.1.1.
2.1.1.2.
2.1.1.3.
Is it SDG&E intention to recover all generation-capacity-related costs
in its proposed commodity demand charge?
How are these costs to be recovered by season and by TOU period for
all M&L C&I rate schedules?
Is the proposed $/kWh charge to recover the program costs associated
with CSI, SGIP, hazardous substance cleanup costs, AMI, and DR to
be recovered on an equal cents per kWh basis for all M&L C&I rate
schedules? Will it vary by service voltage or in any other way within
the class? Will it differ from the related charge for any other class(es),
and, if so, how?
SDG&E Response:
2.1.1.1 SDG&E’s proposal is to recover 50% of marginal generation capacity costs in the
proposed commodity demand charge.
2.1.1.2 The M&L C&I generation capacity costs are recovered according to the marginal
generation capacity costs calculated for each rate schedule by seasonal period,
adjusted for rate design, as set forth on Attachment JSP-2 to the testimony of
SDG&E witness James Parsons. For rate design purposes, the marginal
generation capacity costs (in $/kW) are decreased by 50% for each M&L C&I
rate schedule with commodity demand charges.
2.1.1.3 Yes, the rate is calculated using the EPMC factors for all M&L C&I rate
schedules, with the exception of Schedule S Standby. (Standby rates do not
include an energy charge but since standby customers typically use energy on
other applicable M&L C&I rates they contribute to cost recovery for the programs
under their otherwise applicable rates.) The charge does not vary by service
voltage. For each M&L C&I rate schedule the charge is an identical amount of
$0.00213 /kWh (including FF&U) added to the proposed distribution energy
charge.
Response Prepared By: Dave Borden
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.1.2: Referring to page DAB-3, lines 3-12:
2.1.2.1.Please explain the data and methodology SDG&E proposes to use to
determine the contribution of each M&L C&I class to system peak.
2.1.2.2.Please explain in detail what SDG&E means when it says that it
“currently does not have coincident peak billing determinants for each
rate schedule and thus calculated demand charges for the rate
schedules based on the available determinants.” Which data does it
have and which data does it use for each schedule and how does it use
these data to calculate generation demand charges?
2.1.2.3.Please explain what SDG&E means when it says “[i]n allocating
capacity costs to M&L C&I, the capacity costs are allocated to each
rate schedule according to the variation in coincident peak demand by
time of use… and season.” What variation is being referenced and
how is it calculated and applied to the allocation process?
2.1.2.4.SDG&E states that “greater than 90% of the capacity costs are covered
through the summer demand charge and a small amount is recovered
in a modest winter demand charge”. Is this true for each M&L C&I
rate schedule? What data and concept create the basis for this 90-10
split?
2.1.2.5.SDG&E states that its proposed generation demand charges be set at
50% of their calculated cost of service. Where is the remaining
generation capacity revenue recovered? How would this revenue be
recovered in default CPP rates and what is the relationship between the
two types of schedules in generation revenue recovery?
SDG&E Response :
2.1.2.1 As discussed in the testimony of SDG&E witness James Parsons, JSP-10 through
JSP-14, SDG&E uses the class contribution to system load during the top 300
hours of system demand over a three year period to determine the applicable rate
schedule’s contribution to system peak.
2.1.2.2 SDG&E has monthly billing determinants for coincident peak demands for all
Schedule A6-TOU customers and for customers with demands equal to or greater
than 200 kW. For the overwhelming number of other M&L C&I customers with
demands less than 200 kW, SDG&E’s metering equipment does not record
demands in the intervals required to measure monthly coincident peak demands.
For Schedule A6-TOU, SDG&E divides seasonal marginal generation capacity
costs, as calculated by SDG&E witness James Parsons, by coincident peak
demand determinants to arrive at the $/kW demand charge.
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Response to Question 2.1.2 (Continued)
or Schedule AL-TOU, SDG&E divides seasonal marginal generation capacity
costs, as calculated by SDG&E witness James Parsons, by maximum peak period
demand determinants to arrive at the $/kW demand charge. For Schedule AD,
SDG&E divides seasonal marginal generation capacity costs, as calculated by
SDG&E witness James Parsons, by maximum peak period demand determinants
to arrive at the $/kW demand charge. For Schedule PA-T-1, SDG&E uses
Schedule AL-TOU demand charges, scaled to maintain existing relationships
between rate options on Schedule PA-T-1 to determine the $/kW demand charges.
2.1.2.3 SDG&E means that in allocating capacity costs to the classes within M&L C&I,
that it is determined by the class contribution to system peak (or coincident peak).
(SDG&E is describing the methodology used primarily for Schedule AL-TOU
and A6-TOU, given that these two rate schedules make up the vast majority of
M&L C&I load and customers.) The reference to ”time of use and seasonal
variation” is only meant to explain that the class contribution to system peak
occurs over different hours and with the inclusion of October in the winter period
for M&L C&I customers, also occurs over seasons. Schedule A6-TOU demand
charges are based upon coincident peak demand determinants. Schedule ALTOU demand charges are based on demand determinants for the maximum
monthly demands during the peak period. Schedule PA-T-1 demand charges are
based upon Schedule AL-TOU demand charges scaled to maintain existing
relationships between the current rate option on Schedule PA-T-1 and Schedule
AL-TOU. For Schedule AD demand charges, SDG&E divides seasonal marginal
generation capacity costs, as calculated by SDG&E witness James Parsons, by
maximum peak period demand determinants to arrive at the $/kW demand charge.
2.1.2.4 See the marginal cost capacity amounts and resulting marginal cost revenue
amounts set forth on Attachment JSP-4-3 to the testimony of SDG&E witness
James Parsons, for seasonal recovery of capacity costs. Each rate schedule
exceeds 90% recovery of annual capacity costs in the summer. Adjusted for rate
design this still holds, with the exception of Schedule PA-T-1, which drops to
about 88.2% recovery of annual capacity costs in summer. The basis for this
result is the methodology, sponsored by SDG&E witness James Parsons, that is
used to calculate the marginal generation capacity costs.
2.1.2.5 The remaining 50% of marginal generation capacity costs is recovered through
the energy rates on an EPMC basis for each M&L C&I rate schedule. That is to
say, peak, semi-peak, and off-peak energy rates by season are adjusted on an
EPMC basis such that the overall M&L C&I commodity revenue requirement
allocation remains unchanged.
Response Prepared By: Dave Borden
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
2.1.3.: On page DAB-6, lines 18-19, SDG&E says that the annual average marginal
energy cost is scaled according to 24 hourly price shapes.
Question 2.1.3.1: What is the source of these hourly price shapes and how are they
applied?
SDG&E Response:
Please see the testimony of SDG&E witness Parsons in Chapter SDG&E-04, pages JSP16, lines 7-23, and JSP-17, lines 1-8, for a description of the rate schedule price shapes.
The model “TY 08 GRC Commodity Energy Workpapers.xls” provided in witness
Parsons’ workpapers for Chapter-04 provide the detailed calculations.
Response Prepared By: Dave Borden
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
2.1.4.
On page DAB-7, SDG&E states that the “overall revenue impact to M&L
C&I is an approximate 5% reduction in marginal generation cost recovery when
compared to existing rates” due to its proposal to set generation demand charges
initially at 50% of cost without ratchets.
Questions 2.1.4.:
2.1.4.1.
2.1.4.2.
Please provide the calculation of this reduction.
Does SDG&E believe that generation demand charges should ever
be ratcheted? Why or why not?
How does the revenue uncertainty associated with the use of these
generation demand charges compare to that associated with
recovery of generation capacity cost through CPP rates?
2.1.4.3.
SDG&E Response:
2.1.4.1.
See attached for the present and proposed commodity revenues by rate
schedule. If the present and proposed columns for M&L C&I rate
schedules are summed and compared the change should be approximately
a 4.8% revenue decrease.
EECC.xls
2.1.4.2.
SDG&E is concerned about the rate impacts to customers and in
implementing this new rate it was determined that customer impacts from
ratcheted commodity demand charges would be unacceptable at this time.
SDG&E has not determined whether it will implement ratcheted
generation demand charges in future proceedings.
2.1.4.3.
SDG&E has not conducted any analysis regarding this question. In
general, a rate design that includes demand charges should have less
variability in revenue recovery than one relying predominantly on energy
charges, all else equal.
Response Prepared By: Dave Borden
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.1.5: Please explain the basis for the distance adjustment in M&L C&I
distribution rates.
SDG&E Response:
The distance adjustment fee is intended to recover distribution-related costs from
customers served under the Primary and Secondary Substation Service options. The
distance adjustment fee, first adopted as part of SDG&E’s Primary at Substation rate
structure in D.96-06-033, allows for customers which are not located immediately
adjacent to a substation to be qualified for rates based on the higher service voltage. The
fee, intended to recover SDG&E’s costs of connecting the customer to the substation, is
based on calculations for the cost of wire per foot adjusted for losses. The rates for
overhead were established by advice letter filing in 1999. SDG&E has not updated the
cost calculations and does not propose a change to these rates in this proceeding.
Response Prepared By: Dave Borden
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.1.6: Please explain how distribution revenue is recovered between noncoincident peak demand and maximum peak demand by season and voltage rates.
SDG&E Response:
Revenue recovery is based upon the EPMC allocation of distribution revenue
requirement to the M&L C&I customer class. From the total M&L C&I allocation an
adjustment is made to remove revenue requirement associated with CSI, SGIP and
RPBA, with the remaining revenue requirement recovered from basic service fees and
distribution demand charges. Schedules AL/AY-TOU, AD, and PA-T-1 current
distribution demand charges are adjusted in order to maintain approximately the same
revenue recovery from the schedules as under existing rates and within the constraint that
the total M&L C&I customer class receives an EMPC allocation. Schedule A6-TOU
non-coincident distribution demand charges equal the Schedule AL-TOU charges. The
Schedule A6 current maximum peak distribution demand charges are adjusted based on
the same percentage change to AL-TOU distribution demand charges.
Response Prepared By: Dave Borden
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.1.7: On page DAB-9, lines 11-17, SDG&E states: SDG&E proposes a
monthly maximum on-peak demand charges based on $/kW to recover marginal
generation capacity costs. When Schedule AL-TOU coincident peak demand
determinants become available (in the future through the implementation of advanced
capability meters) then the capacity costs will be recovered through a coincident peak
demand charge, but until such time maximum on-peak demand are the determinations
that are available.”
2.1.7.1.
Does SDG&E have load research data providing coincident peak
demand for some of its AL-TOU customers?
Has SDG&E performed a calculation on the relationship between
maximum on-peak demand and coincident on-peak demand? If
so, please provide this calculation and its basis. If not, please
provide such a report if the data are available.
2.1.7.2.
SDG&E Response:
2.1.7.1
SDG&E has coincident peak demand determinants for Schedule AL-TOU
customers with maximum demands equal to or greater than 200 kW.
2.1.7.2
SDG&E has conducted a study that is referred to as the UCAN Study, that
examines the correlation between the customers’ average and peak
demand during peak hours with peak and other high load hours on the
system, and that is discussed in the direct testimony of SDG&E witness
Leslie Willoughby. Please see LW-13, Appendix LW-A, and relevant
workpapers.
Response Prepared By: Dave Borden
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.1.8: On page AB-10, SDG&E states that “the energy charge is the same cents
per kWhs (sic) rate applicable to all M&L C&I customers and derived from the same
CTC revenue requirement approved in the 2006 RDW proceeding.
2.1.8.1. Why has SDG&E not updated this rate component?
2.1.8.2. Why is this rate component the same for all M&L C&I customers?
SDG&E Response:
2.1.8.1 SDG&E’s CTC revenue requirement is approved in the annual ERRA filing. At
the time of filing GRC2 proposed rates, January 31, 2007, a final decision was not
available regarding the 2007 ERRA and CTC revenue requirements. (A final
decision was available on February 16, 2007.) In addition, CTC rate changes that
implement a final decision were not contemplated to be made before June 1,
2007, with the actual CTC rate changes now pending by advice letter for July 1,
2007.
2.1.8.2 The CTC revenue requirement was re-designed for the M&L C&I class as a
whole which results in the same $ per kWh charge. A single $/kWh charge is
consistent with treatment of other non-bypassable charges such as those that
recover Public Purpose Program, CSI, SGIP, and RPBA costs.
Response Prepared By: Dave Borden
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.1.9: On page DAB-11, lines 22-23, SDG&E states that it “proposes marginal
capacity and energy rates for Schedule AY-TOU that are identical to the rates proposed
for Schedule AL-TOU.” On pages DAB-16 and 17, SDG&E says the same thing about
the commodity rates for Schedules A6-TOU and AL-TOU. Why?
SDG&E Response:
Regarding AL-TOU and AY-TOU, the rate schedules are combined in the calculation of
marginal generation capacity costs. Rate schedules AL-TOU, AY-TOU, A6-TOU and
PA-T-1 are combined in calculating marginal energy costs.
Regarding A6-TOU and AL-TOU, the statement is incorrect with respect to marginal
generation capacity costs and generation demand charges.
Response Prepared By: Dave Borden
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
2.1.10. On pages DAB-18 and 19, SDG&E discusses its standby rate proposals.
Question 2.1.10..:
2.1.10.1:
Please explain what SDG&E means that a standby customer must provide
“physical assurance” to provide diversity benefits?
2.1.10.1.1. :
2.1.10.1.2.:
Is this consistent with Commission decisions on standby rates in the past?
Is it consistent with standby rates for PG&E and SCE?
2.1.10.2.:
How does SDG&E provide for recovery of generation and transmission
costs from standby customers?
2.1.10.2.1.:
Please provide a detailed explanation of how these costs are recovered, in
which rate components, and why.
2.1.10.2.2.:
Does SDG&E’s recovery of generation and transmission costs through
standby rates reflect diversity?
SDG&E Response:
2.1.10.1
SDG&E uses the term physical assurance in the same manner that it is
used in the attached workpaper to the testimony of SDG&E witness David
A. Borden, p. 13, which states that:
SDG&E is using the term “physical assurance” as the Commission defined
that term in D.01-07-027 at Finding of Fact 7: “Physical assurance is the
application of devices and equipment that interrupt a distributed
generation customer’s normal load when distributed generation does not
operate.”
The rationale for requiring physical assurance is set forth on pp. 11-13 of
the attached workpaper to the testimony of SDG&E witness David A.
Borden.
Chapter07-Workpap
ersBialekTestimonyonDistCircuits.DOC
2.1.10.1.1
It is consistent with D.01-07-027.
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Response to Question 2.1.10 (Continued)
2.1.10.1.2
It appears consistent with SCE and PG&E in concept as both utilities
require physical assurance for the waiver of standby reservation charges. However, both
SCE and PG&E recover variable costs from standby customers, which would not be
waived and SDG&E has no provision for the recovery of variable distribution costs in its
standby schedule.
2.1.10.2
Generation cost recovery is not provided for under existing standby rate
schedules. To the extent that a standby customer uses its otherwise applicable tariff then
costs are currently recovered through energy only charges. Proposed GRC2 treatment
would recover generation costs through energy and demand charges on the otherwise
applicable tariff only to the extent that the customer’s own generation does not serve their
designated standby load.
Regarding recovery of transmission costs from Standby customers, the first step in
determining retail transmission standby rates is to first determine SDG&E’s total system
transmission revenue requirements (TRR). The TRR is allocated to each retail customer
class using a 12-CP (coincident peak) allocation factor, which represents a 12-month
average of each customer class’s contribution to SDG&E total monthly system peak.
The 12-CP information used to allocate the TRR to the standby class is calculated based
on estimates of the generation capacity factor for the standby customer class at time of
the monthly system peaks. SDG&E utilizes recorded customer generation data to
estimate this capacity factor for the standby customer class. This allocated revenue is
then assigned to individual voltage levels (transmission, primary, and secondary level) in
proportion to the sum of standby contract demands adjusted to the transmission level.
The standby revenues at each voltage level are then divided by the sum of the applicable
metered contract demands at each voltage level, which then results in the individual
transmission standby rate by voltage level.
2.1.10.2.1
Please see the response to 2.1.10.2 regarding generation and transmission
cost recovery. SDG&E’s proposal in GRC2 is a continuation of the existing rate design
for generation costs. SDG&E’s 12 CP calculation for standby customers for transmission
service is intended to estimate their contribution to coincident peak.
2.1.10.2.2
SDG&E does not have a specific generation charge for standby service
and thus customers pay rates based on actual usage on their otherwise applicable tariffs in
the event that their own generation does not serve all of their contracted standby level, or
they contribute nothing to generation cost recovery. Transmission standby rates reflect
diversity through use of the standby customers’ generation capacity factor to estimate
their share of the 12 CP TRR allocation.
Response Prepared By: Dave Borden
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
2.1.11 SDG&E states on pages DAB 18 and19: “In addition to physical assurance, a
Standby customer may provide diversity benefits through location, size and number such
that SDG&E is able to defer distribution capacity additions. In 2001 SDG&E examined
its distribution system and determined that there were no distributed generators on its
distribution system that met these criteria. Based on communications with the SDG&E
witness responsible for the 2001 report, I understand that the number of distributed
generators has increased since 2001 but the circumstance has not changed regarding
diversity benefits and that currently there are no distributed generators on the SDG&E
system that have allowed SDG&E to defer distribution capacity additions.”
Question 2.1.11.1:
Please provide any workpapers supporting this position.
SDG&E Response:
Please see the attached workpaper.
Chapter07-Workpap
ersBialekTestimonyonDistCircuits.DOC
Response Prepared By: Dave Borden
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.1.12:
SDG&E states that it “believes that an 80/20 split between fixed
and variable charges could be appropriate for [a] standby rate structure.” What is the
basis for this assertion?
SDG&E Response:
The basis for this response is a discussion with the SDG&E employee who authored the
SDG&E 2001 report on standby service. The 80/20 ratio was based upon a sample of
distribution capacity projects that determined the component whose size and subsequent
cost could be impacted by the local area load.
Response Prepared By: Dave Borden
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.1.13:
On page DAB-21, SDG&E states “To the extent that onsite
generation is operated during a summer month or a summer peak period, the customer’s
diversity in generation may allow standby customers to avoid a portion of this demand
charge. SDG&E will not provide a waiver of summer peak period generation demand
charges for standby customers because SDG&E does not provide advanced approval of
maintenance outages in summer months.”
2.1.13.1
2.1.13.2.
2.1.13.3
Does this demand charge apply only when the standby customer is taking
power from SDG&E due to a forced outage?
How does the proposed demand standby demand charge compare to the
standby charge for the standby customers otherwise applicable rate?
Is the standby demand charge subject to a ratchet mechanism?
SDG&E Response:
2.1.13.1
Yes.
2.1.13.2
They are the same. Currently SDG&E waives demand charges on the
otherwise applicable tariff for approved outages. SDG&E will continue
this policy and will not provide for a waiver during the summer period.
2.1.13.3
The demand charge for commodity service that standby load would pay is
not subject to a ratchet.
Response Prepared By: David Bordon
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.2.1.:
Regarding Chapter 11, the Velasquez testimony:
2.2.1. On page JV-1, SDG&E notes that CPP periods can occur on Saturdays, which
is not the case for current rates. However, on page JV-6, SDG&E states that
its proposal to include Saturdays as days when a CPP event may be called
“would not change the existing summer on-peak time periods.” Please
explain the inconsistency between these statements.
SDG&E Response:
SDG&E’s existing summer On-Peak period is defined as 11:00a.m. – 6:00p.m.,
weekdays (excluding holidays). The CPP time-of-use hours on a CPP event day,
including Saturdays, are the same as the summer season On-Peak time period (11:00 a.m.
– 6:00 p.m.).
Response Prepared By: Joe Velasquez
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.2.2.:
2.2.2.1 :
On page JV-2, SDG&E states that its default CPP commodity rate
is identical for both Large and Medium C&I customers.
Why does SDG&E have different energy rates under its proposal
otherwise applicable tariffs for non-CPP schedules but not for CPP
schedules?
SDG&E Response:
SDG&E's proposed CPP energy rates differ by TOU period and voltage level. See
Attachments JRM 10-1, 10-3, & 10-4 to the testimony of SDG&E witness James Magill
for the CPP energy rates and the energy rates on the otherwise applicable rate schedules.
Response Prepared By: Joe Velasquez
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
1.2.
Question 2.2.3.: SDG&E proposes a Capacity Reservation Charge (CRC) as an
optional component it’s the default CPP commodity rate.
1.3.
1.4.
2.2.3.1. Does the CRC incorporate only generation cost recovery?
1.5.
2.2.3.2. Why are customers required to choose a specific capacity level for their
CRC for a twelve month-period? Are we correct in assuming that this
level is the same for all 12 months? How do customers address seasonal
diversity in loads if they must choose the same level for every month?
1.6.
2.2.3.3. If a customer chooses a CRC that covers its maximum monthly on-peak
demand during a year, how does SDG&E treat any excess revenue that
results from maximum on-peak usage below this amount in other months?
1.7.
2.2.3.4. If a customer’s maximum monthly on-peak demand is less than its CRC
level, how does SDG&E treat any excess revenue that results?
1.8.
2.2.3.5. If a customer chooses a CRC that covers its maximum monthly on-peak
demand during a year, how does the customer see any commodity-based
pricing that provides an incentive for demand response?
1.9.
SDG&E Response 2.2.3:
2.2.3.1
Yes.
2.2.3.2.
As stated on page JV-2, choosing to reserve capacity is “completely
optional”.
The capacity reservation charge (CRC) is based on the amount of reserved
capacity and is the same fixed charge for all 12 months in order to spread
the costs evenly over a 12-month period, thus providing a tool for
customers to achieve more predictable bills.
The reserved capacity is not intended to vary monthly but rather it is
intended to apply during the entire summer period (May through
September) when a CPP event can occur. In electing to reserve capacity,
a customer should consider the amount of load it can shed and the amount
of load it wishes to be subject to the CPP rate during any potential critical
peak period (i.e., May through September, 11 a.m. - 6 p.m., Monday
through Saturday, excluding holidays).
2.2.3.3.
Over collections associated with commodity-related revenues are captured
in the Energy Resource Recovery Account (ERRA).
2.2.3.4.
See response to question 2.2.3.3.
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
SDG&E Response 2.2.3-Continued:
1.10. 2.2.3.5. Customers will have the ability to reserve a level of capacity up to and
including their most recent summer maximum on-peak demand that they
believe best meets their operational needs. In the event a customer elects
to reserve 100% of its maximum on-peak demand, it would be a clear
indication that the customer has made the decision to protect its entire load
from the critical peak price and has no intentions for reducing load.
Response Prepared By:
Joe Velasquez and James Magill
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.2.4.:
Does Bill Protection only apply to the generation-related part of
the customer’s bill?
SDG&E Response:
Yes. Please refer to footnote 9 on page JV-4.
Response Prepared By: Joe Velasquez
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.2.5.:
Is it correct that the M&L C&I customer’s otherwise applicable
tariff (OAT) would be the tariffs proposed in Mr. Borden’s
testimony and not the current OAT? Would Bill Protection be
based on these newly-proposed OAT, if adopted? Would
customers have had any experience with these newly-proposed
OAT prior to default CPP service if default CPP rates go into
effect for these customers on 1/1/2008?
SDG&E Response:
After receiving service for an initial 12-month period under default CPP with Bill
Protection, customers will be permitted to opt-out of CPP and receive service under the
otherwise applicable commodity rate schedule which is described by SDG&E Witness
Borden at pp. DAB - 5 & 6.
Bill Protection would be calculated based on the otherwise applicable commodity rates in
effect that a customer would have been billed during its first year of service under default
CPP.
As indicated in Witness Borden’s prepared direct testimony at page DAB-5, SDG&E is
proposing to include a generation demand charge component, which currently does not
exist, in its electric commodity rates applicable to commercial and industrial customers.
While a generation demand charge introduces a structural change to commodity rates,
demand charges have been a component of transmission and distribution rates for over 20
years. In addition, prior to electric industry restructuring, SDG&E’s rates did include a
portion of generation costs as part of its demand charge. As such, the introduction of a
generation demand charge does not represent a change that customers have not
previously been exposed to.
Response Prepared By: Joe Velasquez
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.2.6.:
Why is the Base Interruptible Program (aka BIP) shown in Table
JV-1 as not applicable for customers on default CPP rates? What
would be the case if the Commission decides not to eliminate BIP
for SDG&E?
SDG&E Response:
Table JV-1 indicates that BIP is compatible with CPP.
To the extent that BIP remains in effect, it would be available to customers receiving
service under CPP
Response Prepared By: Joe Velasquez
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.2.7.:
Why is Capacity Bidding shown in Table JV-1 as incompatible
with default CPP rates?
SDG&E Response:
While allowing customers on CPP to participate in the CBP day-of option would be
consistent with SDG&E’s position related CPP compatibility with other day-of demand
response programs, pursuant to SDG&E’s current and effective CPUC approved tariff,
Schedule CBP, Special Condition 11, customers participating in CBP are prohibited from
participating in any other utility demand response program.
Response Prepared By: Joe Velasquez
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.2.8.:
On page JV-11, SDG&E states that a voluntary CPP customer
must be signed up for voluntary CPP by May 1, 2007 to be eligible
for bill protection. How would customers know this when May 1
has already occurred?
SDG&E Response:
As part of SDG&E’s outreach efforts to recruit participants for the existing voluntary
CPP program, customers have been informed about SDG&E’s bill protection eligibility
proposal.
Response Prepared By: Joe Velasquez
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.2.9.:
2.2.9.1.
2.2.9.2.
On page JV-12, lines 11-12, SDG&E says it will provide bill
impact information to customers about the consequences of default
CPP, once such a rate has been approved by the Commission,
based on “some level of assumed demand response; and capacity
reservation assumptions.”
What would be the basis of these assumptions?
Would SDG&E use a standardized demand response assumption?
If so, what would it be?
SDG&E Response:
2.2.9.1
Consistent with the basis of the “Proposed Default CPP Bill Impacts”
results in attachment JRM 10-2 to SDG&E Witness Magill’s testimony,
the initial customer specific bill impact analyses will assume 9 CPP
events, a capacity reservation equal to 50% of the customers most recent
maximum summer on-peak demand and zero load reduction. As the
customer education process unfolds, SDG&E will work with individual
customers to assist them in developing assumptions based on their specific
operational requirements. SDG&E is also developing a rate analysis tool
that customers can use to analyze the impacts of CPP under various
assumptions.
2.2.9.2
See response to 2.2.9.1
Response Prepared By: Joe Velasquez
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.2.10.: On page JV-13, SDG&E states that “[w]hile Small C&I customers will
not default to the proposed CPP commodity rate applicable to medium and large commercial
customers, SDG&E believes that small customers that desire the benefits of lower rates
during non-CPP event periods and are willing t reduce either demand during CPP events
should have the opportunity to take service under the default CPP commodity rate, under the
same conditions that would be applicable to the medium and large customers.”
2.2.10.1
2.2.10.2.
Why should Small C&I customers not default to a proposed CPP
commodity rate?
Is the issue the availability of meters, or that Small C&I customers
should have a different CPP commodity rate, or something else.
Please explain.
SDG&E Response:
2.2.10.1
SDG&E Witness Fong, in chapter 9 at page EF 9, summarizes the
Peak Time Rebate (PTR) program proposed by SDG&E witness
Mr. Gaines1 in A.05-03-015 that would be available to small
commercial customers with demands less than 20kW. The PTR
would be available in combination with the three period time-ofuse rate described in the testimony of SDG&E Witness Magill
beginning on page JRM-10. SDG&E believes PTR is appropriate
for small C&I customers because of the simplicity of the program
and the ability for all customers in the segment to benefit if they
change their energy consumption behavior during CPP events.
The simplicity of the program allows SDG&E to easily explain the
benefits of the program to customers through mass media
information channels and to easily remind customers of the
opportunity to save money each time a CPP event is announced.
2.2.10.2.
See response to 2.2.10.1 above.
Response Prepared By: Joe Velasquez
1
See A.05-03-015, Ex. 25, Ch 5, MFG-15
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
1.11. Question 2.2.11.: Regarding Chapter 10, the Magill testimony, please answer the
following questions:
1.12.
1.13.
2.2.11.1.
On page JRM-2, SDG&E states that it “has designed the
proposed CPP rate based on the total greater than 20 kW class, rather
than bifurcating the class since the metering limitations are no longer
relevant. Please explain why SDG&E has determined that the metering
limitation is determinative here.
2.2.11.2.Will all customers with demands 20 kW and above have demandmetering and demand charges?
2.2.11.3. On page JRM-3, SDG&E states that [t]he applicable CPP rate is based
on the marginal capacity cost multiplied by the average load associated
with the greater than 20 kW customer class during the top nine (9) CPP
dates plus the summer on-peak marginal energy cost.” Would this
calculation be different if there were a separate CPP rate for each
schedule for customers greater than 20 kW due to different average loads?
2.2.11.4.On page JRM-6, SDG&E states that the “CPP energy rate equals the CPP
marginal capacity cost revenues, minus the capacity revenues associated
with the CRC, divided by forecasted billed CPP usage, plus the summer
on-peak marginal energy rate.” In a footnote to this sentence, SDG&E
states that [t]he CPP billing determinants are CTC revenues reflect the
proposed fifty (50) percent default CPP.
1.14. 2.2.11.4.1. Please produce CPP rates based on an assumed 100 percent CRC.
2.2.11.4.2. Please produce CPP rates based on an assumed zero percent CRC.
2.2.11.4.3. Please provide forecast revenues under the 0%, 50%, and 100% CRC
alternatives.
2.2.11.5. On page JRM-6, SDG&E states that it only adjusts non-CPP on-peak and
semi-peak rates to achieve revenue neutrality, since a downward
adjustment to off-peak rates would lead to rates below marginal cost.
What is the resulting TOU energy rate ratio and how does it compare to
the MEC ratio?
2.2.11.6. Referring to page JRM-9, why did SDG&E chose to use “the top forty
(40) hours… to split 2008 forecast energy sales into CPP-E and on-peak,
semi-peak, and off-peak energy billing determinants” as opposed to a
different number of hours?
1.15.
1.16.
1.17.
1.18.
1.19.
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
1.20. Question 2.2.11.-Continued:
2.2.11.7. On page JRM-14, SDG&E indicates that on 1/1/2011 it will switch to a
6-month summer period. Has SDG&E performed any bill impact
calculations on the impact of a longer summer and a shorter winter rate
period? If so, please provide them. If not, will SDG&E provide such
analysis prior to such a change going into effect? How will SDG&E
notify its customers of this change and when?
1.21.
SDG&E Response 2.2.11:
2.2.11.1
Please refer to the Prepared Direct Testimony of SDG&E Witness James
Magill, page JRM-2, lines 4-11. For commodity revenue allocation
purposes customers with demands greater than 20 kW (for twelve
consecutive months) are treated as a single customer class. All customers
with demands greater than 20 kW(for twelve consecutive months) will
have interval metering once AMI is implemented and should be treated as
a single rate class for CPP rates.
2.2.11.2
Customers with demands greater than 20 kW (for twelve consecutive
months) currently have demand metering and demand charges.
2.2.11.3
The resulting rates would differ to the extent the individual schedules have
different demand / energy ratios as compared to the total class during the
top nine days.
2.2.11.4
See the attached workpapers.
C:\Documents and
C:\Documents and
C:\Documents and
Settings\jmagill\Desktop\James
Settings\jmagill\Desktop\James
Magill\RDW\2008
Settings\jmagill\Desktop\James
GRC Magill\RDW\2008
P2\Filed 13107\CLECA
GRC Magill\RDW\2008
P2\Filed
2.2.11.4.1
13107\CLECA
CPP Rates
GRC P2\Filed
2.2.11.4.2
(20kW -13107\C&I
9DCPP
100 Rates
CRC)
CPPv12
(20
Ra
2.2.11.5
See the attached workpaper.
C:\Documents and
Settings\jmagill\Desktop\James Magill\RDW\2008 GRC P2\Filed 13107\CLECA 2.2.11.5.xls
2.2.11.6
The top 40 hours were used as a proxy for the number program hours that
could potentially occur during the year. The CPP-E rate is limited to a
maximum of 40 hours in a month and 80 program hours per year.
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
SDG&E Response 2.2.11:
2.2.11.7
SDG&E has not performed any bill impact calculations. Prior to
implementing the seasonal change, SDG&E will provide estimated bill
impacts for various customer types. SDG&E would notify customers in
any of a number of ways including direct mail, email or bill insert as well
as by posting on SDG&E’s website.
Response Prepared By:
James Magill
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
2.3 Regarding Chapter 13, the Willoughby testimony, please answer the following
questions:
Question 2.3.1: On page LW-2, in describing the monthly statistics it will provide for all
CPP and PTR events, SDG&E states that it will “include econometric Model estimates
for peak days”.
2.3.1.1.:
Won’t SDG&E have actual peak day data to be used after the date
whose results are being reported? Why use model estimates?
SDG&E Response:
The CPUC requires monthly reporting of demand reduction estimates for all Demand
Response programs (D.)01-04-006. Even though SDG&E will have peak day data to
assist in providing results, there also must be an estimate of what the load would have
been in absence of the rate or program. In order to estimate the impacts from CPP and
PTR events in a timely manner SDG&E proposed using econometric model estimates.
SDG&E currently uses econometric estimates in its Dynamic Load Profile (DLPs)
process along with meter data estimates. The econometric estimates produced are not
influenced by CPP or PTR events. This process would produce an estimate of the load
that would have been without the CPP or PTR event. The large meter data sample can
be used to calculate estimates of demand levels on CPP days. An estimate of the overall
load reductions can be derived by taking the difference of the meter data estimates and
econometric estimates. The purpose of this method is to aid in providing the monthly
report of DR activities and is not intended to replace the official load impact estimation
that will take place after the program year has ended.
Response Prepared By: Leslie Willoughby
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.3.2: On page LW-2, in describing the monthly statistics it will provide for all
CPP and PTR events, SDG&E states that it will “utilize population and large meter sample
for megawatt (MW) load reduction estimates compare (sic) to forecasted system load shape
with no demand response”.
2.3.2.1.
2.3.2.2.
2.3.2.3.
Please describe in detail how SDG&E proposes to do this analysis.
What load sample will SDG&E use to estimate load reductions? Is it
statistically significant?
Has SDG&E ever performed such an analysis before? If so, how accurate
were the results?
SDG&E Response:
2.3.2.1 Please see SDG&E’s response to 2.3.1.1
2.3.2.2 SDG&E intends to use as much information as feasible to estimate load
reductions. When possible all available load data will be used. This is subject to
basic verification and editing. SDG&E intends to utilize samples that are
statistically significant for the monthly reporting.
2.3.2.3 SDG&E currently uses a similar methodology when calculating it’s Dynamic
Load Profiles (DLPs). SDG&E has using this methodology for nearly 10 years.
SDG&E has no reason or cause to believe that the estimates are not accurate.
Response Prepared By: Leslie Willoughby
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.3.3: On page LW-3, SDG&E states that it has used DRA’s estimated benefits
attributed to daily website access and information display technologies from A. 05-03-15.
What level of benefits did the Commission adopt for this technology in that proceeding?
SDG&E Response:
(D.)07-04-043 adopted $19 million for Information Feedback Systems benefit.
Response Prepared By: Leslie Willoughby
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.3.4: With reference to the Peak Time Rebate (PTR), SDG&E has chosen to
use the highest 3 out of the past 5 eligible days as a reference level for residential
customers but the highest 3 out of the past 10 eligible days for small commercial
customers. What is basis for this difference?
SDG&E Response:
SDG&E analyzed the accuracy of several reference levels using statistics such as total
error and bias. The overall goal was a reference level with low total error, low bias, easy
for customers to understand, and difficult for a customer to game. The residential high 3
of 5 day baseline performed well in all categories as did the high 3 of 10 day for the small
commercial class.
Response Prepared By: Leslie Willoughby
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.3.5: On page LW-7, Table LW-1, SDG&E shows its estimate of Total
Rebates Paid no DR and Total Rebates Paid with DR. Please calculate what these
numbers would be if SDG&E had used a reference level of the highest 1 day in the past 5
eligible days for residential customers. Please perform a similar calculation for small
commercial customers (per Table LW-3) using the highest 1 day in the past 10 eligible
days for small commercial customers.
SDG&E Response:
Residential High 1 of 5 CRL
Year
2004
2005
2006
Reference
Level
High 1of 5
High 1of 5
High 1 of 5
Total rebates
no DR
(millions)
-$24
-$23
-$25
Total
rebates with
DR
(millions)
-$30
-$29
-$33
Small Commercial High 1 of 10 CRL
Total Rebates
No DR
(millions)
Total Rebate
with DR
(millions)
Year
Reference
Level
2004
High1 of 10
-$3.91
-$5.05
2005
High 1 of 10
-$3.77
-$4.86
2006
High 1 of 10
-$5.52
-$6.91
Response Prepared By: Leslie Willoughby
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.3.6: Please provide workpapers developing SDG&E’s claimed increased
demand response benefits from its proposed rates in this proceeding compared to its AMI
business case.
SDG&E Response 2.3.6:
Ch13_tbl5_DRbenefi SCh13_SDGE_Prism_ Ch13_SDGE_Prism_R
ts_v2.xls
Commercial_jan31.xls
es_jan31.xls
Response Prepared By: Leslie Willoughby
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.3.7: On page LW-12, SDG&E states that the assumptions it uses to calculate
these benefits “are consistent with the assumptions used in SDG&E’s AMI application
(A).05-03-15”. Please calculate SDG&E’s proposed demand response benefits based
upon the benefit figures adopted by the Commission in Decision 07-04-043.
SDG&E Response:
Table DR Benefits according to AMI decision
Present Value of Demand Response Benefits
(Millions of 2008 $)
Customer Segment
Residential
Capacity
$72.8
Energy
$6.2
Total
$79.0
2011 MW
109
Small C&I (<20 kW)
$11.1
$0.8
$11.9
9
Medium C&I (20- 200 kW)
$49.4
$2.0
$51.4
72
Large C&I (> 200 kw)
Total
$47.9
$181.2
$1.6
$10.5
$49.5
$191.7
66
256
Customer Class
Assumptions
Residential
50%
Avoided Capacity Value
Small Commercial
Medium Commercial
Large C&I years 2009-2010
Large C&I year 2011-2026
All classes
Prices
Dollars
All classes
All classes
100% of customers
with thermostats
100%
5%
100%
$52/kw real
GRC phase II
proposed rates
present value 2008
Load
Benefit Period
All classes
All classes
2005 load
2009-2026
Participation Rates
Response Prepared By: Leslie Willoughby
CLECA DATA REQUEST
CLECA DR-02
SDG&E PHASE 2 GRC – ELECTRIC RATE DESIGN - A.07-01-047
Date Submitted: July 5, 2007
Question 2.3.8: Please explain why, on page LW-12, SDG&E says it has chosen to
change the “load underlying the avoided capacity benefits ...to the annual peak day load
from 11 am to 6 pm instead of the average of the top 9 days” when there is only one
annual peak day and SDG&E is performing its calculations based on an assumed 9 event
days
SDG&E Response:
SDG&E provided an example on LW12-LW13 as to why it is more appropriate to
calculate the capacity benefits using the annual peak load instead of an average of the
highest 9 days. SDG&E believes that if it uses the average of the nine peak days that it
underestimates the load reduction and therefore underestimates the capacity benefits.
The average usage for the top 9 days is still used to calculate the avoided energy benefits.
Response Prepared By: Leslie Willoughby