Demand Response Working Group and
Stakeholder Meeting Agenda – January 15, 2009
Time
Topic
Presenter
11:00 – 11:10
Introduction & Meeting Objective
Tom Cuccia
11:10 – 11:40
Working Group Discussion: MRTU Release 1
Participating Load User Guide
John Goodin/
Farrokh Rahimi
11:40 – 12:00
Working Group Discussion: PDR Implementation
Detail
Jim Price
12:00 – 12:45
Lunch
12:45 – 2:15
FERC Order on Competition Adds to Requirements for Demand
Response
- Project Time Line
- Addition of Direct Participation to the two DR Models for Post- MRTU
Market Enhancements
- Design Features and Issues
2:15 – 2:30
Break
2:30 – 3:30
Cash Flow Model and Settlements Issues
Margaret Miller
3:30 – 4:30
Alternate Proposal for Proxy Demand Resource
Muir Davis
4:30 – 5:00
DR Process Issue Resolution
John Goodin
Jim Price
Update on MRTU Release 1 Participating
Loads Users Guide
John Goodin, CAISO
Farrokh Rahimi and Ali Ipakchi, OATI
Demand Response Stakeholder Meeting
January 15, 2009
Background
 Draft of MRTU Release 1 Participation Loads Users
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Guide was issued on December 9, 2008
Discussed at the Dec 12, 2008 Stakeholder meeting
Comments were received from SCE and PG&E
CAISO incorporated the comments received and made
additional changes as necessary
The next few slides indicate the main changes
Slide 3
Main Changes Made in PL Users Guide
 Editorial corrections and cleanup
 Clarification of such issues as consideration of PL in RUC
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procurement target
Correction of settlement examples involving A/S No-Pay
Consideration of Distribution Losses for SC Metered
Entities
 Elaboration of eDAC implementation requirements
Slide 4
Main Changes Made in PL Users Guide
Stakeholder Comment
CAISO Response
Section 2 - "In the RUC process, the day-ahead PL schedule CAISO treats max PL bid in DAM as PL forecast,
is used as the forecast for PL's consumption so that RUC carves it out of the UDC load and adds back in the PL
that clears as load.
will factor PL in and not over-commit resources". Explain
how the CAISO is generating a load forecast.
Source
PG&E
Section 2 - SCs providing PL resources will not be given
RUC payments, according to the last sentence on this
page. However, the paragraph above this one states “RUC
will factor PL in” based on the PL forecast. If CAISO is
factoring PL into the RUC stack, why would we not get a
RUC payment for it?
The PL curtailment in the IFM is similar to a generator
clearing IFM. Both reduce the RUC procurement
target, and neither is paid RUC availability. Besides,
PL resources are considered RA capacity and thus are
ineligible to be paid RUC availability.
SCE
Section 2 - Please clarify point (b) the Non-spinning Reserve
is deployed and delivered (based on telemetry), during a
contingency, but the hourly metered consumption of the
Participating Load is not adequate to cover the Energy
associated with the total awarded Non-spinning Reserve
capacity for the hour less the deployed Energy.
Clarifications have been added to the document.
Thanks for the comment
SCE
Slide 5
Main Changes Made in PL Users Guide (Cont’d)
Stakeholder Comment
Section 5.1 states the "CAISO may adjust the A/S and realtime imbalance energy requirements temporarily", why is this
here? It seems too generic.
CAISO Response
Agreed and paragraph deleted
The third paragraph notes that "The CAISO may adjust the
A/S and Real-time Imbalance Energy requirements
temporarily to take into account, among other things,
variation in conditions, real time dispatch constraints,
contingencies, and voltage and dynamic stability
assessment.“
Section 5.2.1 -- this is the first time that the words "nonParticipating load bid" is used. Also the CAISO now
references PL modeled at an "individual node", they need to
revise to be consistent with 'custom laps'
Source
PG&E
SCE
Agreed and text is edited accordingly
PG&E, SCE
Slide 6
Main Changes Made in PL Users Guide (Cont’d)
Stakeholder Comment
CAISO Response
Source
Section 1.1 - Are SC’s required to bid both a resource (pseudogenerator) and enough energy to cover that load (PL), or do
they have the option to just bid the resource, and take the
chance that they will be bid and will not have to purchase
energy to cover the load?
The SCs are not required to self-schedule enough load
in the Day Ahead market to cover their non-spin bid or
award but by not self-scheduling enough load they may
risk a no-pay in real-time. There are minor edits in the
document to clarify this.
SCE
PL Requirements Table: This Ancillary Services test appears to
be another testing/certification in addition to the
/PLIP/PLAT/RDT. What type of things are going to be tested
on for this? How long will it take to get the test done? Are
there WECC or CAISO standards? If this is a WECC
requirement, we could be looking at another critical path for
bidding a resource as an ancillary service.
The testing will include a) eDAC technology and b)
resource capability for providing A/S. The CAISO
resource eligibility testing requirements are based on
the WECC requirements.
SCE
General -- most of the meters for DR will be connected to
distribution lines. However, there is no discussion in the
document about how DLF will be used for adjustment, if
any. Will there be an adjustment to telemetry? How would
those adjustments be compared to the meter, which per
RQMT need to be adjusted by posted DLF by UDC area?
The use of DLF has been incorporated for the SC
Metered Entities.
PG&E
DLF (Distribution Loss Factor): Distribution Loss
Factor represents the average electrical energy losses
incurred when electricity is transmitted over a
distribution network. DLF is represented as a
percentage of energy transmitted. For the purposes of
the CAISO PL, the DLF represents losses between the
PL meter and the associate CAISO Pricing Point
(substation connecting the load to the CAISO controlled
grid).
Slide 7
Main Changes Made in PL Users Guide
 Corrections in PL Settlement Examples
Although telemetry is required for provision of A/S, it is not used for
compliance monitoring and No-Pay
 A/S No Pay applies based on metered consumption and (day-ahead load
resource schedule minus dispatched real-time Energy from A/S capacity)
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Case 2:
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DA PL Load Resource cleared 14 MW
PL RT consumption before contingency was 15 MW
RT Energy Dispatch from PL A/S Capacity: 1 MWh
Meter read: 14 MWh
Although source reduced consumption based on telemetry, it is subject to No-Pay
Case 3:
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DA PL Load Resource cleared 14 MW
RT consumption before contingency was 13 MW
RT Energy Dispatch from PL A/S Capacity: 1 MWh
Meter read: 13 MWh
Although source did not reduce consumption based on telemetry, it is not subject
to No-Pay
Slide 8
Questions or Issues?
Email to:
[email protected]
Slide 9
Implementation Detail in Proxy Demand
Resource Design
Jim Price
Lead Engineering Specialist,
Market Design & Regulatory Policy
Demand Response Working Group Meeting
January 15, 2009
ISO is Preparing for Detailed Design Stage of
Post-MRTU Demand Response Enhancements
 Post-MRTU Release 1 market enhancements provide two DR models:
 Dispatchable Demand Resource (DDR) adds to MRTU PL: RT & DA energy, cooptimization of energy & AS, market functionality for spinning reserve & regulation, and
recognition of operating characteristics. (Involves vendor development)
 Proxy Demand Resource (PDR) simplifies administration of Custom LAPs in initial DR
integration into MRTU and migration of small loads, by scheduling load at Default LAP
and dispatch Proxy Generators at local levels. This informs the PDR resource when
significant costs can be achieved through DR.
 Initial PDR implementation modifies internal ISO systems. Initial review:
 ISO targets implementation for summer 2009. (Then, operating reserve and real-time
energy targeted for fall ‘09, and full PDR with DDR 12 months after MRTU Go-Live.
Timing is subject to MRTU staffing needs.)
 Implementation uses post-processing of market data. Must be no real-time data
changes, no change in data format transferred between systems, no change in OASIS.
 Initial implementation cannot include significant business process
changes (e.g., no baseline calculations of end use customers’ demand).
 ISO will present updates in DR working group meetings.
 Example of needed coordination: add Proxy Generators during network model updates
Working Group Discussion of DR Market
Enhancements Showed Possible Refinement
 PDR implementation involves two conceptual steps:
(1) subtract day-ahead (DA) Proxy Generator schedule from Scheduling
Coordinator’s DA Default LAP schedule, then
(2) remove Proxy Generator from Settlement data.
 Result is to credit SC with DR response.
 Concern: When Direct Access customers are in utilities’ DR programs,
utilities’ DA Default LAP schedules are adjusted, instead of the customers’
Electric Service Provider’s schedule.
 Potential resolution: perform step 2 but not step 1
 Advantage: Correct SC sees DR response in its metered demand.
 Disadvantage: DR response settles at real-time price, not DA price.
 Feedback needed: Would this be a helpful change in the
initial PDR design?