Transcript DSWG Update to WMS 2/13/2013 DSWG Leadership • WMS Vote for confirmation of DSWG selections: – Chair: Tim Carter – Vice Chair: Mary Anne Brelinsky –

DSWG Update to WMS
2/13/2013
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DSWG Leadership
• WMS Vote for confirmation of DSWG
selections:
– Chair: Tim Carter
– Vice Chair: Mary Anne Brelinsky
– Vice Chair: Nelson Nease
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DSWG Goals for 2012
Scheduled
Completion
Market
Champion
Comments
Status
NPRR detailing how LRs can participate
as an RMR alternate
Sep-12
Mark Smith
Request initiated by WMS. Moved by WMS to
RCWG where tabled.
NPRR and Technical Requirements
document change to accommodate
PUCT EILS Rule change
Jun-12
Ed Echols
NPRR451 approved
Support Load participation of Load
Resources in the design of the Look
Ahead SCED project
Dec-12
John Varnell
Participated in discussion; including HAM
option. Issue at PUCT Workshop
Dec-12
Mark Smith
ERS30 pilot, NPRR505
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May-12
Eric
Rothschild
Changes to Ancillary Services Capacity Monitor
Reports identified with MISUG
NPRR494 submitted/withdrawn due to
cost/benefit
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Functional requirements and possible
Aggregations of Small Customers as proof of concept test for aggregations
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Load Resources
of small customers to qualify as Load
Resources
Sep-12
Ed Echols
ALR NPRR nearing completion
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Potential NPRR to bring DR impacts up
to a wholesale level
Oct-12
Tim Carter
NPRR delivered in 2013
In progress
Tim Carter
DSWG Goal for 2013
In progress
# Goal Description
Deliverable
1 Load Resource Alternatives to RMR
2
Modify EILS Rules to Increase
Available Capacity
3 Load Participation in SCED
Develop proposals for DR Products
4 with different ramp periods and
Functional requirements development
temperature sensitive loads
Improve access to ERCOT market
5 data to assist in DR business
decisions
7 Adjust DR Capacity for T&D Losses
NPRR for changes to MIS Reports
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Update Load Participation in ERCOT
Revised and Updated Document
Markets document
Sep-12
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Explore Settlement Improvements Develop NPRR for five minute
for Price Sensitive Loads
settlement option for Loads
Sep-12
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Review DR components of CDR and
Suggest improvements if necessary
SARA
Sep-12
Cyrus R
Presentation made to GATF. Issue at PUCT
Workshop
Write NPRR requiring a public version
of this report to be posted
Jun-12
Jay Z
NPRR not needed; survey completed.
Expand3Sources of Frequency Data Formulate recommendation to ERCOT
for UFR Events
for use of additional TDSP data
Dec-12
John Varnell
Additional data from PMUs being used.
11 4CP / Price Response Study
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Mark Smith Evaluated & white paper created – rejected due
Floyd Trefny
to cost/benefit
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Adjustment of Demand Response
Performance for T&D Losses
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What this is Not:
• An attempt to alter the current market design
– Capacity vs. Energy-Only Market
– Transmission Loss Calculation
– Instituting Separate Energy Payments
• About losses behind the meter, but rather
describes the losses between two accepted
lines of demarcation – the generation meter
and the load meter
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What this Is:
• An attempt to align how DR is treated
elsewhere (see Appendix)
• Correct an inconsistency that has existed for
quite some time
When Metered Load is Adjusted:
Long Term Load
Forecasting
When Capacity is Made
Available for Ancillary /
ERS
Short Term Load
Forecasting
Energy Charges When
Not Deployed
Energy Payments When
Deployed (through
avoided costs)
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Proposed Methodology:
• LR – Static values
– Determined by ERCOT, Approved by TAC
– Telemetry / Offer Adjustment is Optional
• ERS – Actual Values
– Automatic for Compliance Calculation
– Optional for Offer MWs
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Estimated Impacts
• LR
– None when proration exists
– Otherwise, may increase in capacity from LRs
• May reduce RRS MCPC
– Estimate: Max additional capacity of 40-45 MWs
• ERS
– Improvement in compliance metrics, increase in
capacity, or somewhere in between
• May increase cost of ERS
– Estimate: Max additional capacity of 30 MWs
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Proposed Vote:
DSWG asks that WMS endorse DSWG filing the
NPRR
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DSWG Goals for 2013
Scheduled
Completion
Market
Champion
Contributors
Status
NPRR 505 approval
End of Q1
Robert King
Perrin Wall, Michael Cozzi, Jay Zarnikau, Kyle Miller
At PRS
2 ERS Clearing Price
Draft NPRR
End of Q1
Joel Obillo
John Tipton, Michael Cozzi, Malcolm Ainspan, Perrin Wall,
Robert King, Tim Carter
Testing in ERS30
pilot
3 ERS-30
Complete Pilot Project and
Introduce NPRR
End of Q4
Robert King
Malcolm Ainspan, Joel Obillo, Michael Cozzi, Tim Carter
Pilot Phase
through Sept ‘13
Draft NPRR, including
4 ERS Deployment Time Limit clarification of requirements
when no contractual obligation
End of Q1
Robert King
John Tipton, Malcolm Ainspan, Joel Obillo, Perrin Wall
Testing in ERS30
pilot
Draft NPRR to clarify ALR
5 Aggregated Load Resources participation in Ancillary
Services
End of Q2
David Kee
Jay Zarnikau, Perrin Wall, Justin Louis, Robert King, Ed Echols,
Cheryl Dobos, Russell Shaver, Eric Goff, Sherry Wiegand
In Progress
End of Q3
Eric Goff
Joel Obillo, Suzanne Bertin, Perrin Wall, Caryn Rexrode, Cyrus
Reed, Jay Zarnikau, John Tipton, Robert King, Justin Louis,
David Kee, Sherry Weigand, Melissa Trevino, David Power,
Marguerite Wagner, Kyle Miller, David Power
Not Started
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# Goal Description
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Weather-Sensitive ERS
Loads
Deliverable
DR Participation in the Real6
Draft NPRR
Time Energy Market
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Adjust DR Capacity for T&D Draft and present NPRR to
Losses
WMS
End of Q1
Tim Carter
Joel Obillo
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Load Resource M&V via
Baseline Methodology
Draft NPRR
End of Q1
David Kee
Caryn Rexrode, Justin Louis, Robert King
In progress
Training workshop for ERS
End of Q2
ERCOT Staff
ERCOT Staff
Not Started
9 ERS Training/Outreach
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Update Load Participation in Finish and post consistent with
ERCOT Markets document outcome of PUC project
End of Q2
Tim Carter
Joel Obillo, Caryn Rexrode, ERCOT Staff
In progress
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Retail DR/Dynamic Pricing
Project
Support ERCOT/LSEproject on
data collection & analysis
End of Q4
Jay Z
Michael Cozzi, Kyle Miller, Marguerite Wagner
Not Started
Explore locational mapping for
ERS, LR and retail demand
response
End of Q3
Perrin Wall
Tim Carter, Marguerite Wagner, Ed Echols
Not Started
Review and provide
recommendations for
reports/display to ERCOT
End of Q4
Nelson Nease
Tim Carter, David Power
Not Started
12 DR Asset Mapping
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Presentation
10 of NPRR351
Price Forecasts
Appendix
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ISO-NE
http://www.iso-ne.com/regulatory/tariff/sect_3/mr1_13-14.pdf
III.13.7.1.5.1. Capacity Values of Demand Resources.
The Capacity Value of a Demand Resource for an Obligation Month shall be its Demand Reduction Value
for the month as determined pursuant to Section III.13.7.1.5.3 multiplied by the summer Installed
Capacity Requirement divided by the 50/50 summer system peak load forecast as determined by the
ISO for the Forward Capacity Auction immediately preceding the Forward Capacity Auction in which the
Demand Resource clears, multiplied by one plus the percent average avoided peak transmission and
distribution losses used by the ISO in its calculations of the Installed Capacity Requirement for the
Forward Capacity Auction immediately preceding the Forward Capacity Auction in which the Demand
Resource clears. Beginning with the Capacity Commitment Period starting June 1, 2012 through May 31,
2017, the Capacity Value of a Demand Resource for an Obligation Month shall be its Demand Reduction
Value for the month as determined pursuant to Section III.13.7.1.5.3 multiplied by one plus the percent
average avoided peak transmission and distribution losses used to calculate the Installed Capacity
Requirement for the Forward Capacity Auction immediately preceding the Forward Capacity Auction in
which the Demand Resource clears. Beginning with the Capacity Commitment Period starting June 1,
2017, the Capacity Value of a Demand Resource for an Obligation Month shall be its Demand Reduction
Value for the month as determined pursuant to Section III.13.7.1.5.3 multiplied by one plus the percent
average avoided peak distribution losses used to calculate the Installed Capacity Requirement for the
Forward Capacity Auction in which the Demand Resource clears. For the first Forward Capacity Auction,
the value of the Installed Capacity Requirement divided by the 50/50 summer system peak load forecast
shall be 1.143, and one plus the percent average avoided peak transmission and distribution losses shall
be 1.08.
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What about 2017 in ISO-NE?
FERC Docket No. ER12-1627-000 (from 1/14/13):
On the issue of transmission losses, FERC notes that currently, the capacity value of a demand resource is its Demand
Reduction Value, adjusted upwards by the average peak transmission and distribution losses that are avoided by
reducing demand. FERC explains that to serve 1 MWh of load, generators must produce more than 1 MWh of energy,
because some of the energy production will be lost in moving the energy from the generator to the load. Thus, if a
customer commits in the capacity market to reducing its load by 1 MWh at its load site, FERC explains that ISO-NE’s
need to procure generation capacity is reduced by more than 1 MWh, that is, 1 MWh plus the amount of transmission
and distribution losses that are avoided due to the load reduction. FERC states that ISO-NE proposes to remove the
adjustment for transmission losses as of June 1, 2017 (the date when the Fully Integrated rules are implemented),
while retaining the adjustment for distribution losses.
According to FERC, ISO-NE’s rationale for the proposed change, as presented in the Joint Testimony of Henry Y.
Yoshimura and Christopher A. Parent, is that the adjusted loss factor will be the same as that used in the Fully
Integrated rules for the energy markets, which FERC accepted in the January 19 Order. FERC explains that it accepted
ISO-NE’s proposal in the January 19 Order to remove the transmission loss adjustment in the energy market, because in
the energy market, the LMP at a load’s location reflects the cost of producing energy by the marginal generator plus the
marginal cost associated with the losses incurred in moving the energy from the marginal generator to the load. FERC
explains that in other words, when a demand response resource reduces its load and is paid the LMP for doing so, the
LMP reflects the marginal cost of the full amount of energy production that is avoided, including the avoided cost of
losses on the transmission system. According to FERC, there is no need to make a further adjustment for transmission
losses in the energy market for demand response resources, however, FERC explains that transmission losses are not
reflected in capacity market prices. FERC explains that a commitment by a demand response capacity resource to
reduce load by a specified amount will avoid the need for ISO-NE to otherwise acquire from generators both (i) the
amount of load provided by the demand response capacity resource; and (ii) the associated distribution and
transmission losses that are associated with generation but not demand response. Given that ISO-NE has not
explained why an adjustment for transmission (as well as distribution) losses is not necessary, FERC requires ISO-NE to
submit, in a compliance filing, further justification for the removal of using transmission losses in its calculation of
demand resource capacity values. In addition, FERC instructs that ISO-NE must also explain whether, and if so how, it
will otherwise adjust the total capacity requirement to reflect avoided transmission losses when procuring capacity.
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NYISO
http://www.nyiso.com/public/webdocs/products/icap/icap_manual/icap_mnl.pdf
4.12.2.1.1 Determining the Amount of UCAP for a Non-Generator Based Special Case Resource with a Provisional ACL
Where:
UCAPQgm = the Unforced Capacity that Resource g is qualified to provide in month m;
ACLPgm = the Provisional Average Coincident Load for Resource g applicable to month m, using data reported in the enrollment file uploaded
to DRIS; in accordance with Section 4.12.4 of this ICAP Manual ;
CMDgm = the Contract Minimum Demand for Resource g applicable to month m, using data reported in the enrollment file uploaded to DRIS;
LRHgbe = the set of hours (each an hour h) in the period beginning at time b and ending at time e in which Resource g was requested to
reduce load;
ACLPgh = the Provisional Average Coincident Load for Resource g applicable to hour h, using data reported in the enrollment file uploaded to
DRIS as of time e in accordance with Section 4.12.4 of this ICAP Manual;
AMDgh = the Average Minimum Demand for Resource g for hour h, using data using data reported in the performance data file uploaded to
DRIS;
CMDgh = the Contract Minimum Demand for Resource g applicable to hour h, using data reported in the enrollment file uploaded to DRIS;
NLRHgbe = the number of hours during the period beginning at time b and ending at time e in which Resource g was required to reduce load
(including any hour in which Resource g was required to reduce load by the ISO as part of a test);
b = the Capability Period prior to the Prior Equivalent Capability Period in which the performance factor is being computed, unless Resource g
had not begun at that time to serve as a Special Case Resource available to reduce load, in which case b is the earlier of time e or the time at
which Resource g began to serve as a Special Case Resource available to reduce load;
e = the Prior Equivalent Capability Period in which the performance factor is being computed; and
TLFgv = the applicable transmission loss factor for Resource g, expressed in decimal form (i.e. a loss factor of 8% is equal to .08). The
applicable transmission loss factor shall be the loss factor for deliveries of Energy at voltage level v by the relevant TO to the retail
customer where the Resource g is located as reflected in the TO’s most recent rate case and stored in DRIS.
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PJM
http://www.pjm.com/~/media/documents/manuals/m18.ashx (see page 50)
– The nominated value for a guaranteed load drop
customer will the guaranteed load drop adjusted
for system losses, as established by the customer’s
contract with the resource provider.
– Nominated Value of GLD = GLD (LossF), where GLD
is guaranteed load reduction and LossF is the
customer’s EDC-assigned loss factor
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