DSWG Update to WMS2/13/2013

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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

# Goal Description Deliverable Scheduled Completion

Market Champion Comments Status

1 Load Resource Alternatives to RMR 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.

2 Modify EILS Rules to Increase Available Capacity

NPRR and Technical Requirements document change to accommodate PUCT EILS Rule change

Jun-12 Ed Echols NPRR451 approved

3 Load Participation in SCEDSupport 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

4Develop proposals for DR Products with different ramp periods and temperature sensitive loads

Functional requirements development Dec-12 Mark Smith ERS30 pilot, NPRR505 5

Improve access to ERCOT market data to assist in DR business decisions

NPRR for changes to MIS Reports May-12 Eric Rothschild

Changes to Ancillary Services Capacity MonitorReports identified with MISUG

NPRR494 submitted/withdrawn due to cost/benefit

6 Aggregations of Small Customers as Load Resources

Functional requirements and possible proof of concept test for aggregations of small customers to qualify as Load Resources

Sep-12 Ed Echols ALR NPRR nearing completion

7 Adjust DR Capacity for T&D Losses Potential NPRR to bring DR impacts up to a wholesale level Oct-12 Tim Carter NPRR delivered in 2013

In progress

8 Update Load Participation in ERCOT Markets document Revised and Updated Document Sep-12 Tim Carter DSWG Goal for 2013 In progress

9 Explore Settlement Improvements for Price Sensitive Loads

Develop NPRR for five minute settlement option for Loads Sep-12 Mark Smith

Floyd TrefnyEvaluated & white paper created – rejected due

to cost/benefit 10 Review DR components of CDR and

SARA Suggest improvements if necessary Sep-12 Cyrus R Presentation made to GATF. Issue at PUCT Workshop

11 4CP / Price Response Study Write NPRR requiring a public version of this report to be posted Jun-12 Jay Z NPRR not needed; survey completed.

12 Expand Sources of Frequency Data for UFR Events

Formulate recommendation to ERCOT for use of additional TDSP data Dec-12 John Varnell Additional data from PMUs being used.

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:

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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

# Goal Description Deliverable Scheduled Completion

Market Champion Contributors Status

1 Weather-Sensitive ERS Loads 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

4 ERS Deployment Time LimitDraft NPRR, including clarification of requirements when no contractual obligation

End of Q1 Robert King John Tipton, Malcolm Ainspan, Joel Obillo, Perrin Wall Testing in ERS30 pilot

5 Aggregated Load ResourcesDraft NPRR to clarify ALR 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

6 DR Participation in the Real-Time Energy Market Draft NPRR 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

7 Adjust DR Capacity for T&D Losses

Draft and present NPRR to WMS End of Q1 Tim Carter Joel Obillo

8 Load Resource M&V via Baseline Methodology Draft NPRR End of Q1 David Kee Caryn Rexrode, Justin Louis, Robert King In progress

9 ERS Training/Outreach Training workshop for ERS End of Q2 ERCOT Staff ERCOT Staff Not Started

10 Update Load Participation in ERCOT Markets document

Finish and post consistent with outcome of PUC project End of Q2 Tim Carter Joel Obillo, Caryn Rexrode, ERCOT Staff In progress

11 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

12 DR Asset MappingExplore locational mapping for ERS, LR and retail demand response

End of Q3 Perrin Wall Tim Carter, Marguerite Wagner, Ed Echols Not Started

13 Presentation of NPRR351 Price Forecasts

Review and provide recommendations for reports/display to ERCOT

End of Q4 Nelson Nease Tim Carter, David Power Not Started

Appendix

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ISO-NEhttp://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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NYISOhttp://www.nyiso.com/public/webdocs/products/icap/icap_manual/icap_mnl.pdf4.12.2.1.1 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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PJMhttp://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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