DSWG Update to WMS 2/13/2013

1. DSWG Update to WMS2/13/2013

2. DSWG Leadership • WMS Vote for confirmation of DSWG selections: • Chair: Tim Carter • Vice Chair: Mary Anne Brelinsky • Vice Chair: Nelson Nease

4. Adjustment of Demand Response Performance for T&D Losses

5. 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

6. 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:

7. 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

8. 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

9. Proposed Vote: DSWG asks that WMS endorse DSWG filing the NPRR

11. Appendix

12. 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.

13. 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.

14. 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.

15. 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