Market Performance and Planning Forum. January 14, 2014

Transcription

1 Market Performance and Planning Forum January 14, 2014

2 Objective: Enable dialogue on implementation planning and market performance issues Review key market performance topics Share updates to 2014 release plans, resulting from stakeholders inputs Provide information on specific initiatives to support Market Participants in budget and resource planning Focus on implementation planning; not on policy Clarify implementation timelines Discuss external impacts of implementation plans Launch joint implementation planning process Slide 2

3 Agenda Agenda 10:00-10:05 Introduction, Agenda Kristina Osborne 10:05 11:30 Market Performance and Quality Update Guillermo Bautista Alderete, Nan Liu, Mark Rothleder 11:30 12:00 Policy Update Brad Cooper 12:00 1:00 Lunch 1:00 2:00 FERC 764 Implementation Li Zhou, Jeremy Malekos, Chris McIntosh 2:00 3:00 Release Update Janet Morris, June Xie, Chris McIntosh Slide 3 Note: Agenda is subject to change.

4 Proposed meeting dates for 2014 January 14 March 13 May 22 July 15 September 9 November 18 Page 4

5 Market Performance and Quality Update Market Quality and Renewable Integration Guillermo Bautista Alderete Nan Liu Mark Rothleder Slide 5

6 1. Hot topics and follow-up items 2. Market Metrics Price volatility and market convergence RT energy/congestion imbalance offset Convergence bidding Exceptional dispatch Bid cost recovery MIP gap Flex-ramp cost Price Corrections Slide 6

7 Hot topic and follow up items Pay for performance CRR revenue adequacy DA and RT prices Wind and solar generation MOC unit commitment RUC commitment Page 7

8 Follow up items Pay for performance Mileage cost remained at relatively low levels. Overall, regulation units continue to respond to AGC controls reliably. ISO is seeking a waiver related the minimum performance threshold of fifty (50) percent applicable to resources offering Regulation Up and Regulation Down capacity. Existing requirements is for resources not meeting such conditions to re-certify to provide the respective service within ninety (90) days. Page 8

9 11/1/ /3/ /5/ /7/ /9/ /11/ /13/ /15/ /17/ /19/ /21/ /23/ /25/ /27/ /29/ /1/ /3/ /5/ /7/ /9/ /11/ /13/ /15/ /17/ /19/ /21/ /23/ /25/ /27/ /29/ /31/2013 Amount ($) Pay for Performance $16,000 Daily Distribution of Mileage Payments $14,000 $12,000 Mileage Down Mileage Up $10,000 $121,177 $69,274 $8,000 $6,000 $4,000 $2,000 $0 Mileage Down Mileage Up Slide 9

10 11/1/ /3/ /5/ /7/ /9/ /11/ /13/ /15/ /17/ /19/ /21/ /23/ /25/ /27/ /29/ /1/ /3/ /5/ /7/ /9/ /11/ /13/ /15/ /17/ /19/ /21/ /23/ /25/ /27/ /29/ /31/2013 Pay for Performance 60% System Mileage Performance Accuracy 50% 40% 30% 20% 10% 0% System Down Accuracy System Up Accuracy Page 10

11 CRR Revenue Adequacy in 2013 Congestion rents from the dayahead market insufficient to cover all CRR payments. With CRR auction revenues, overall adequacy is a surplus of $8 million Page 11

12 Revenue (In)adequacy by Constraint ($ Millions) Constraint Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Grand Total PALOVRDE_ITC _TM_BNK_FLO_TMS_DLO_NG _MAGUNDEN_230_24153_VESTAL_230_BR_2 _ SOL-8_NO_HELMS_PUMP_NG_SUM SLIC and SOL SLIC TL50003_CFE_NG SLIC DEVERSELCASCO_ FL T-133METCALF_NG _HENRITTA_70.0_30881_HENRIETA_230_XF_ SLIC DEVERS-VISTA2_NG SLIC Devers-Vista_ PACI_ITC PATH15_BG SLIC TL50001_NG BARRE-LEWIS_NG SLIC _PVDV_Out_EDLG _SERRANO_500_24137_SERRANO _230_XF_ _SANMATEO_115_33315_RAVEWD_115_BR_1 _ NOB_ITC TRACY500_ITC _KEARNY _69.0_22496_MISSION _69.0_BR_1 _ SLIC DEVERSELCASCO_FL SLIC _PVDV_Out_LGVN _HENTAP2 _230_30900_GATES _230_BR_2 _ NdGrp: 36412_DIABLO 2_25.0_B _TL230S_OVERLOAD_NG DSP_Devers_4021_NG _LODI_230_30622_EIGHTMI_230_BR_1 _ NdGrp: 36411_DIABLO 1_25.0_B SCE_PCT_IMP_BG Other Total by month Page 12

13 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13 $/MWh Follow up items DA and RT prices Monthly Average Price Difference between RT and DA (RT minus DA) NP15 SP15 Page 13

14 1-Jan 15-Jan 29-Jan 12-Feb 26-Feb 12-Mar 26-Mar 9-Apr 23-Apr 7-May 21-May 4-Jun 18-Jun 2-Jul 16-Jul 30-Jul 13-Aug 27-Aug 10-Sep 24-Sep 8-Oct 22-Oct 5-Nov 19-Nov 3-Dec 17-Dec 31-Dec MWh Follow up items Wind Schedules 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 HASP IFM RTD Page 14

15 1-Jan 15-Jan 29-Jan 12-Feb 26-Feb 12-Mar 26-Mar 9-Apr 23-Apr 7-May 21-May 4-Jun 18-Jun 2-Jul 16-Jul 30-Jul 13-Aug 27-Aug 10-Sep 24-Sep 8-Oct 22-Oct 5-Nov 19-Nov 3-Dec 17-Dec 31-Dec MWh Wind Schedules in DA, HASP, and RTD (only PIRP). 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 HASP IFM RTD Slide 15

16 1-Jan 27-Jan 22-Feb 20-Mar 15-Apr 11-May 6-Jun 2-Jul 28-Jul 23-Aug 18-Sep 14-Oct 9-Nov 5-Dec 31-Dec MWh Solar Schedules in DA, HASP, and RTD. 25,000 20,000 15,000 10,000 5,000 0 HASP IFM RTD Slide 16

17 Net Load Profile Page 17

18 11-Nov 13-Nov 15-Nov 17-Nov 19-Nov 21-Nov 23-Nov 25-Nov 27-Nov 29-Nov 1-Dec 3-Dec 5-Dec 7-Dec MWh Follow up items MOC commitment 4,000 3,500 3,000 2,500 2,000 1,500 1, MOC Cleared Value Pmin Cleared Value above Pmin Page 18

19 Follow up items MOC commitment MOC Name Number (Frequency) of binding hours in Nov and Dec Humboldt (38%) SCIT MOC 200 (14%) MOC Colgate B 116 (8%) MOC Kramer (7%) MOC BOGUE (6%) Orange County (4%) MOC COLGATE (2%) SDGE (2%) HNTBH (2%) MOC CARIBOU LASSEN (1%) MOC CARIBOU COLPIN (1%) MOC GEYSERS (1%) MOC KRAMER (1%) MOC Pease (0.5%) Page 19

20 1-Nov 3-Nov 5-Nov 7-Nov 9-Nov 11-Nov 13-Nov 15-Nov 17-Nov 19-Nov 21-Nov 23-Nov 25-Nov 27-Nov 29-Nov 1-Dec 3-Dec 5-Dec 7-Dec 9-Dec 11-Dec 13-Dec 15-Dec 17-Dec 19-Dec 21-Dec 23-Dec 25-Dec 27-Dec 29-Dec 31-Dec MWh Follow up items RUC commitment and Pmin energy 6,000 RUC Pmin Energy 5,000 4,000 3,000 2,000 1,000 0 Long Startup Short Startup Page 20

21 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13 Average Hourly Volume (MW) RUC Procurement 2,000 Determinants of RUC Procurement 1,500 1, ,000-1,500 Operator adjustments Cleared net virtual supply Day-ahead forecast-day-ahead cleared capacity Page 21

22 Good price convergence in November. Page 22

23 DLAP LMP Monthly Average (On Peak) Page 23

24 DLAP LMP Monthly Average (Off Peak) Page 24

25 DLAP LMP Monthly Average (All hours) Page 25

26 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13 Percent of Real Time Intervals Monthly price distributions: low volatility in November and December. 4.0% 2.0% 0.0% -2.0% -4.0% -6.0% -8.0% -10.0% -$30 to -$5 -$100 to -$30 -$300 to -$100 <-$300 $250 to $500 $500 to $750 $750 to $1000 >$1000 Page 26

27 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13 Count of Intervals Percent of Intervals Insufficient upward ramping capacity stayed at low levels since October % 3.50% 3.00% % % % % % % 5-minute intervals with insufficient upward ramping capability percent of intervals with insufficient upward ramping capability Page 27

28 Jan-11 Mar-11 May-11 Jul-11 Sep-11 Nov-11 Jan-12 Mar-12 May-12 Jul-12 Sep-12 Nov-12 Jan-13 Mar-13 May-13 Jul-13 Sep-13 Nov-13 Number of Intervals Monthly average of RTD intervals with insufficient down ramping capacity increased since October % % % % % % % % % 5-minute intervals with insufficient downward ramping capability percent of intervals with insufficient downward ramping capability Page 28

29 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13 $Millions Congestion offset decreased by 36% in 2013 compared with 2012 (January to December). 60 Real-time Congestion and Energy Imbalance Offset Cost Congestion Imbalance Offset Energy Imbalance Offset Slide 29

30 The level of Exceptional dispatch in December increased. Increase due to gas supply limitations Page 30

31 1-Nov 3-Nov 5-Nov 7-Nov 9-Nov 11-Nov 13-Nov 15-Nov 17-Nov 19-Nov 21-Nov 23-Nov 25-Nov 27-Nov 29-Nov 1-Dec 3-Dec 5-Dec 7-Dec 9-Dec 11-Dec 13-Dec 15-Dec 17-Dec 19-Dec 21-Dec 23-Dec 25-Dec 27-Dec 29-Dec 31-Dec % of Total Load Daily Exceptional Dispatches by Reason Cold weather with gas supply limitations 5.00% 4.50% 4.00% 3.50% 3.00% 2.50% 2.00% 1.50% 1.00% 0.50% 0.00% System Energy Thermal Margin Software Limitation Generation Outage Unit Testing Gas/Fuel Supply Limitations Transmission Outage 6510 Other Page 31

32 Jan-11 Feb-11 Mar-11 Apr-11 May-11 Jun-11 Jul-11 Aug-11 Sep-11 Oct-11 Nov-11 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13 $Millions Bid cost recovery (BCR) costs increased in November after declines in five straight months Bid Cost Recovery by Market Type (IFM, RT, RUC) IFM RT RUC Page 32

33 1/1/11 2/1/11 3/1/11 4/1/11 5/1/11 6/1/11 7/1/11 8/1/11 9/1/11 10/1/11 11/1/11 12/1/11 1/1/12 2/1/12 3/1/12 4/1/12 5/1/12 6/1/12 7/1/12 8/1/12 9/1/12 10/1/12 11/1/12 12/1/12 1/1/13 2/1/13 3/1/13 4/1/13 5/1/13 6/1/13 7/1/13 8/1/13 9/1/13 10/1/13 11/1/13 12/1/13 Mip Gap ($) MIP Gap Performance. 100,000 90,000 80,000 70,000 60,000 50,000 40,000 30,000 20,000 10,000 0 Daily Dollar 30 Day Moving Average Page 33

34 Dec-11 Jan-12 Feb-12 Mar-12 Apr-12 May-12 Jun-12 Jul-12 Aug-12 Sep-12 Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13 $Millions Flexi-ramp constraint costs rose in December compared with November. 6 Monthly Flexi-Ramp Cost Slide 34

35 Percentage of Nodes Corrected Corrections were low from October to December 1.8% 1.6% 1.4% 1.2% 1.0% 0.8% 0.6% 0.4% 0.2% 0.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar April May June July Aug Sep Oct Nov Dec Data Input Software Tariff Page 35

36 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May June July Aug Sep Oct Nov Dec Percentage of Nodes Corrected Corrections in October to December mainly occurred in the real-time market 1.8% 1.6% 1.4% 1.2% 1.0% 0.8% 0.6% 0.4% 0.2% 0.0% RTD HASP DA Page 36

37 # of Instances Events of price corrections decreased in # of Price Correction Instances by Month Reduction of Price Corrections for all months (Median = 48%)

38 Policy Update Brad Cooper Manager, Market Design and Regulatory Policy Slide 38

39 2014 Stakeholder initiative roadmap Draft final 2014 roadmap to be published as part of stakeholder initiative catalog on January 21 Briefing at March ISO Board meeting Page 39

40 Stakeholder initiatives coming soon Joint reliability framework targeted to start 2014 Q1 Market-based procurement mechanism Flexible resource must offer obligation standard flexible capacity product Standard capacity product for demand response Use-limited resource must offer obligations Standard capacity product enhancements Voluntary preferred resource auction Targeted to start 2014 Q1 Page 40

41 Stakeholder initiatives coming soon (continued) Administrative pricing rules Targeted to start Feb 2014 Expanding metering and telemetry options Targeted to start Feb 2014 Flexible ramping product Targeted to start March 2014 Voltage support procurement Targeted to start March Q1 Revisions to ISO transmission planning standards Targeted to start 2014 Q1 Page 41

42 Stakeholder initiatives going to the Board for approval Initiative Full network model expansion Outage management system replacement Flexible resource adequacy criteria and must offer obligations Contingency modeling enhancements Board Presentation February February March May Page 42

43 Technical Update Li Zhou Manager, Power Systems Technology Development and Smart Grid Technology Jeremy Malekos, Project Manager Chris McIntosh, Market Simulation Lead Slide 43

44 FERC 764 Registration Changes Internal VER Variable Energy Resource (VER) ISO Internal VER resources Resource Type = GEN ISO will set flag to Y for all Wind and Solar resources Forecast Selection ISO ISO provides forecast SC SC submits forecast Default to ISO for resources that have telemetry. Resources without telemetry will be set to SC CERT_PIRP Y All Wind and Solar with telemetry P PIRP Protection* Blank resources without telemetry and non-vers Energy Type Blank HR_PRE_ DISP Blank Resources may elect SC via the RDT change process beginning on Spring Release 2014 Activation date Page 44

45 FERC 764 Registration Changes External VER Variable Energy Resource (VER) ISO External VER Resources Resource Existing TG Type = TG Resource must make a request - Dynamic to set VER flag Scheduling to Y Agreement holder Resource Type = TG No DSA; VER imports Note: This specific resource must meet definition of a VER. VER flag will be set to Y Note: This specific resource must meet definition of a VER. Forecast Selection Resource may elect ISO if it has telemetry, otherwise must elect SC Default to SC. ISO option is not available without telemetry CERT_PIRP Y if resource is VER and has telemetry P N/A Blank resources without telemetry and non-vers Energy Type DYN HR_PRE_ DISP Blank Blank FIRM N 15-min Page 45

46 FERC 764 Registration Changes Energy and AS Import Variable Energy Resource (VER) Forecast Selection ISO Existing Energy and AS Imports Resource Type = TG No DSA; A/S imports Resource Type = ITIE, ETIE ; nonresourcespecific system resource imports CERT_PIRP Energy Type HR_PRE_ DISP N/A N/A Blank FIRM Y Hourly N 15-min N/A N/A N/A FIRM NFRM UCTG WHL *PIRP Protection must be requested within 30 days of Spring Release 2014 Activation date Default to Y, SC must request N via RDT change process Y Hourly N 15-min Default to Y, SC must request N via RDT change process Page 46

47 FERC 764 Forecasting Accuracy Every 5 or 15 Minutes SC Submits a Complete Forecast in SIBR Forecast Can Be Submitted Up to 4 Hours Ahead, but No Later Than 10 Minutes Prior Forecast Contains 5 Minute Intervals, No Mixing Minimum of 2 ½ Hours Must be Submitted After Market Clears, SC Has Ability to See Which Forecast Used in CMRI At the Top of the Hour Forecasting Tool Takes a Snapshot of the Past Hour Forecasting Tool Calculates Hourly SC Forecast Difference (HFD sc ) Forecasting Tool Calculates Hourly ISO Forecast Difference (HFD iso ) Hourly Forecast Difference (HFD) = Forecast Actual Hourly Forecast Difference (HFD) is stored Period is defined as: Determined in BPM At the End of the Period Period Forecast Difference Calculated for SC Forecast (PFD sc ) Period Forecast Difference Calculated for ISO Forecasts (PFD iso ) Period Forecast Difference (PFD) =S(HFD) Min % (PFD sc, PFD iso ) = Forecast Used for Next Period Percentage under review PFD sc and PFD iso provided to SC

48 FERC 764 Questions and Answers Question Is the registration process that is due on only for the CAISO structured scenarios? For variable energy resources, eventually CAISO is doing away with PIRP, but will still create a forecast for SCs to use. Is there a requirement for VERs to actually schedule in SIBR based on the forecast given by CAISO or forecasts generated by the SCs? For interties that engage in the new bidding types, if the schedule changes intrahour and the tag needs to be updated there is an option for CAISO to update the tag for the SC. What are the associated fees behind having CAISO update the tag versus the Market Participant doing it on their own. Answer Yes, for unstructured you will be allowed to register additional resources, including the resources registered for structured scenarios we will allow 10 in total. Market participant can submit an energy bid curve or an energy self schedule for the VERs. CAISO will determine which forecast to use in ALFS. In either case, the ALFS forecast will be used as the upper economic limit for dispatch purpose. There is no fee difference there. The only caveat is that, as part of the NERC requirement, Market participants are required to tag to reflect the energy flow. CAISO automatic update of the tags is there for convenience. MPs still carry that responsibility to ensure that the tags are accurate based on the market dispatches. Page 48

49 FERC 764 Questions and Answers Question My understanding is that the E-tag test bed will serve as the test tags that the CAISO will automatically update for us with the 15 market awards. For example for the all 15 intervals the CAISO will update the tag at T-22.5 for each respective interval. Beginning in 2013, OATI (Open Access Technology International, Inc.) provides an optional functionality improvement to their energy Tag (etag) report zip file downloads by adding a check-box to select zip files that include the report date in the file name. The reporting process has been revised to enable the OATI Tag Report zip files to be sent to and received by an SC in either the original file name format or in the new name format that includes the date already. How can we get access to a market sim version of OMAR in order to submit our meter information for our registered resources? Answer The E-tagging test bed will act like todays E-tag system that is currently in production, this one will just point to MAP Stage. If you would like to modify a Tag or deny a Tag or change it after the fact to test your systems this will be allowed. OATI has confirmed this functionality will be available in the Market Simulation e-tag Test Bed. You will need to register the resources ahead of time as well as submit an AARF form to get access to MAP- Stage OMAR, or if you already have access to a certificate that has access you can use that. Page 49

50 FERC 764 Questions and Answers Question 1. What is the difference between the Market Awards and Market Schedules in CMRI technical interface spec. Both appear to include advisory schedules for the RTM/HASP run as well as binding schedules/awards for the DAM/IFM and RTM/RTUC runs, so I wanted to better understand the purpose of the new Market Schedules retrieval/report. 2. The CAISO added a new PRC_RTPD_LMP file for the 15 minute LMPs to the OASIS technical spec. Is there a reason that CAISO didn t also add a RTPD A/S prices file? I see there is still a HASP reference in the PRC_AS file. Will this be the file for getting the RTPD A/S prices even though it is still called HASP? Will there be convergence bidding in the market sim? Answer Good observation; as the schema data elements are mostly the same in both MarketAwards & MarketSchedules. Yet in summary, the new MarketSchedules is meant to provide the advisory 15min schedules coming from the RTUC runs only. Some notation on page 72 of InterfaceSpecsSpring2014ReleaseClean.pdf under the execution-type element. All current/existing data retrievals except from the (new) advisory RTUC/15mins would remain as is using the same/existing MarketAwards. There is already an existing/currently available RTPD 15min level A/S prices API called PRC_INTVL_AS. The scenario identified as #10 will be the last scenario run or may be deferred based on overall readiness. Convergence Bidding on the ties will not be active until a year later and at that time the ISO would conduct a market simulation. Page 50

51 FERC 764 Questions and Answers Question In the document, "FERC Order 764 Compliance 15 Minute Scheduling & Settlement and Dynamic Transfer Business Requirements Specification - Planning" dated 11/27/2013, under the section titled "Real-Time Market (RTPD/RTD)" there is a bulleted listing of the different options for bidding at the interties in the 15-minute market. Can the CAISO please clarify what it means by the intertie bidding option of "Economic bid with participation in 15-minute market only if cleared in hourly process for block schedules. We are not sure what this means and how it differs from the other options. Answer In SIBR for the Interties and TG resources there will be a Dispatch Option when bidding in for the resource. These are defined below and in the Release Notes for SIBR posted for Spring Hourly: dispatched as an Hourly Pre-Dispatched Resource with a flat Dispatch for all Trading Intervals of a Trading Hour. Once: dispatched as an Hourly Pre-Dispatched Resource with up to a single Dispatch revision in a Commitment Interval of a Trading Hour. 15MIN: dispatched in each Commitment Interval of a Trading Hour with a flat Dispatch for all Dispatch Intervals of that Commitment Interval. Dynamic: dispatched in each Dispatch Interval of a Trading Hour. The option "Economic bid with participation in 15- minute market only if cleared in hourly process for block schedules allowed by CAISO policy will be done by market participants not putting in the transmission reservation in the tags after HASP clears. This will cause subsequent RTPD not to dispatch the resource. So there is no explicit bid option in SIBR needed to do so. Page 51

52 FERC 764 Questions and Answers Question Appendix C to the Market Operations BPM defines the Expected Energy Calculation under FERC Order 764. The algorithm has been revised to reflect "MSS Load Following Energy" associated with both the FMM and RTD as described in the formulae contained in section C Will the same submitted MSS Load Following Energy quantity for a given interval be used to clear both the FMM and RTD? Or will NCPA be expected to submit two different sets of MSS Load Following Energy quantities in the FMM and RTD scheduling submittal timeframes? Lastly, there appears to be an inconsistency between the CAISO's FO 764 tariff definition of MSS Load Following Energy compared to how it is used in the Expected Energy Calculation in Appendix C. While Appendix C defines and calculates MSS Load Following Energy in each of the FMM and RTD runs, the Master Appendix A defines MSS Load Following Energy limited only to RTD IIE and further describes that "MSS Load Following Energy does not coexist with FMM Optimal Energy". This would seem to suggest that, since the difference between Day Ahead Energy Schedule and FMM will, in general, be categorized and settled as FMM IIE Optimal Energy, there will never be any related MSS Load Following Energy associated with the FMM due to the rule that MSS LF Energy in the FMM can not coexist with FMM Optimal Energy. Answer MSS Load Following energy is always considered as real-time (RTD) energy because it is an operational instruction that a unit is following load. However, internal to the expected energy algorithm, in order to properly cut out the energy component due to load following, we have to look at the impact of a MSS load following instruction impact to both FMM and RTD. If we only look at the energy area between a FMM schedule and RTD DOPs, we can potentially skip an area caused by load following. After the load following energy is accounted for, it will be reclassified all as RTD energy in 5-minute. The interim step you see in the algorithm is simply to allow the algorithm to account for the entire MSS load following instruction. An easy example, No DA; MSS LF instruction is 20MW; FMM = DOP = 20MW. So it is clear in this case, there is no market energy. All is MSS LF energy for 20MW equivalent. However, in order to get there, we have to look at both FMM and DOP to determine that the 20MW of FMM is really caused by the MSS LF instruction of 20MW. Again, after this determination, the MSS LFE of 20MW will continue to be classified back as RTD type just like production. Page 52

53 FERC 764 CMRI Mockup FMM Binding MW Fifteen-Minute Market (FMM) Schedules Trade Date SC ID Resource Configuratio n Product Schedule Type Binding Hour Ending Interval IE:15 [MW] Interval Interval Interval IE:30 [MW] IE:45 [MW] IE:00 [MW] 01/07/2014 SC01 Resource1 Energy Market Yes /07/2014 SC01 Resource1 Energy Self Yes /07/2014 SC01 Resource1 Energy Market Yes /07/2014 SC01 Resource1 Energy Self Yes /07/2014 SC01 Resource1 Energy Market Yes /07/2014 SC01 Resource1 Energy Self Yes Page 53

54 FERC 764 CMRI Mockup FMM Binding $ s Fifteen-Minute Market (FMM) Schedule Prices Trade Date SC ID Resource Product Price Type Binding Hour Ending Interval IE:15 [$] Interval IE:30 [$] Interval IE:45 [$] Interval IE:00 [$] 01/07/2014 SC01 Resource1 Energy LMP Yes /07/2014 SC01 Resource1 Energy Energy Yes /07/2014 SC01 Resource1 Energy Congestion Yes /07/2014 SC01 Resource1 Energy Loss Yes /07/2014 SC01 Resource1 Energy LMP Yes /07/2014 SC01 Resource1 Energy Energy Yes /07/2014 SC01 Resource1 Energy Congestion Yes /07/2014 SC01 Resource1 Energy Loss Yes /07/2014 SC01 Resource1 Energy LMP Yes /07/2014 SC01 Resource1 Energy Energy Yes /07/2014 SC01 Resource1 Energy Congestion Yes /07/2014 SC01 Resource1 Energy Loss Yes Page 54

55 FERC 764 CMRI Mockup Advisory MW Real-Time Unit Commitment (RTUC) Advisory Schedules Market Run Interval Start Configurati SCID Resource DateTime DateTime on Product Schedule Type Binding Schedule [MW] 01/08/ :00:00 01/08/ :15:00 SC01 Resource1 Energy Market No /08/ :00:00 01/08/ :30:00 SC01 Resource1 Energy Market No /08/ :00:00 01/08/ :45:00 SC01 Resource1 Energy Market No /08/ :15:00 01/08/ :30:00 SC01 Resource1 Energy Market No /08/ :15:00 01/08/ :45:00 SC01 Resource1 Energy Market No /08/ :15:00 01/08/ :00:00 SC01 Resource1 Energy Market No /08/ :15:00 01/08/ :15:00 SC01 Resource1 Energy Market No /08/ :15:00 01/08/ :30:00 SC01 Resource1 Energy Market No /08/ :15:00 01/08/ :45:00 SC01 Resource1 Energy Market No /08/ :30:00 01/08/ :45:00 SC01 Resource1 Energy Market No /08/ :30:00 01/08/ :00:00 SC01 Resource1 Energy Market No /08/ :30:00 01/08/ :15:00 SC01 Resource1 Energy Market No /08/ :30:00 01/08/ :30:00 SC01 Resource1 Energy Market No /08/ :30:00 01/08/ :45:00 SC01 Resource1 Energy Market No /08/ :45:00 01/08/ :00:00 SC01 Resource1 Energy Market No /08/ :45:00 01/08/ :15:00 SC01 Resource1 Energy Market No /08/ :45:00 01/08/ :30:00 SC01 Resource1 Energy Market No /08/ :45:00 01/08/ :45:00 SC01 Resource1 Energy Market No Page 55

56 FERC 764 CMRI Mockup Forecast 15 Minute Resource-Specific VER Forecast Usage Execution Type Market Run DateTime Interval Start DateTime SCID Resource Forecast Type Forecast [MW] RTUC 01/08/ :00:00 01/08/ :00:00 SC01 Resource1 ECF RTUC 01/08/ :00:00 01/08/ :15:00 SC01 Resource1 ECF RTUC 01/08/ :00:00 01/08/ :30:00 SC01 Resource1 ECF RTUC 01/08/ :00:00 01/08/ :45:00 SC01 Resource1 ECF RTUC 01/08/ :15:00 01/08/ :15:00 SC01 Resource1 ECF RTUC 01/08/ :15:00 01/08/ :30:00 SC01 Resource1 ECF RTUC 01/08/ :15:00 01/08/ :45:00 SC01 Resource1 ECF RTUC 01/08/ :15:00 01/08/ :00:00 SC01 Resource1 ECF RTUC 01/08/ :15:00 01/08/ :15:00 SC01 Resource1 ECF RTUC 01/08/ :15:00 01/08/ :30:00 SC01 Resource1 ECF RTUC 01/08/ :15:00 01/08/ :45:00 SC01 Resource1 ECF RTUC 01/08/ :30:00 01/08/ :30:00 SC01 Resource1 ECF RTUC 01/08/ :30:00 01/08/ :45:00 SC01 Resource1 ECF RTUC 01/08/ :30:00 01/08/ :00:00 SC01 Resource1 ECF RTUC 01/08/ :30:00 01/08/ :15:00 SC01 Resource1 ECF RTUC 01/08/ :30:00 01/08/ :30:00 SC01 Resource1 ECF RTUC 01/08/ :30:00 01/08/ :45:00 SC01 Resource1 ECF RTUC 01/08/ :45:00 01/08/ :45:00 SC01 Resource1 ECF RTUC 01/08/ :45:00 01/08/ :00:00 SC01 Resource1 ECF RTUC 01/08/ :45:00 01/08/ :15:00 SC01 Resource1 ECF RTUC 01/08/ :45:00 01/08/ :30:00 SC01 Resource1 ECF RTUC 01/08/ :45:00 01/08/ :45:00 SC01 Resource1 ECF Page 56

57 FERC 764 CMRI Mockup 5 Minute Resource-Specific VER Forecast Usage Execution Type Market Run DateTime Interval Start DateTime SCID Resource Forecast Type Forecast [MW] RTD 01/08/ :00:00 01/08/ :00:00 SC01 Resource1 ECF RTD 01/08/ :00:00 01/08/ :05:00 SC01 Resource1 ECF RTD 01/08/ :00:00 01/08/ :10:00 SC01 Resource1 ECF RTD 01/08/ :00:00 01/08/ :15:00 SC01 Resource1 ECF RTD 01/08/ :00:00 01/08/ :20:00 SC01 Resource1 ECF RTD 01/08/ :00:00 01/08/ :25:00 SC01 Resource1 ECF RTD 01/08/ :00:00 01/08/ :30:00 SC01 Resource1 ECF RTD 01/08/ :00:00 01/08/ :35:00 SC01 Resource1 ECF RTD 01/08/ :00:00 01/08/ :40:00 SC01 Resource1 ECF RTD 01/08/ :00:00 01/08/ :45:00 SC01 Resource1 ECF Page 57

58 Spring 2014 Market Simulation The ISO has posted an updated draft of the market simulation spring 2014 release plan to its website on 1/6/ FERC Order 764 Structured scenarios: DynamicTransfersStructuredScenarios.pdf FERC Order 764 Unstructured scenarios: UnstructuredScenarioRequestsV1_0.xls Bid Floor Cap Structured scenario: %20integration/Renewable%20integration%20market%20and%20product%20review%20phase%2 01/Renewable%20integration%20market%20and%20product%20review%20phase%201%20- %20implementation The plan includes the following initiatives, enhancements and activations: FERC Order Number 764 market changes with Dynamic Transfers Bid cost recovery (BCR) mitigation measures, Mandatory multi-stage generation (MSG) Renewable integration market and product review (RIMPR) phase 1 RDRP Activation / FERC 745 Compliance ISO is requesting MP s provide feedback as to when they can support a market simulation by 1/31. SIBR-Lite is available as of 1/9/14. Please send comments to ISO Market Simulation Coordinator at MarketSim@caiso.com

59 Release Plan Updates Janet Morris, Director, Program Office June Xie, Sr. Advisor, Program Office Chris McIntosh, Market Simulation Lead Page 59

60 The ISO offers comprehensive training programs Date January 14 January 15 January 16 January January Training Introduction to CAISO Markets Training Market Transactions Training Welcome to the ISO Web Training Market Concepts and Pre-Market Sim Order 764 and Sim BCR/RIMPR Training FERC Order 764 Settlement training Training calendar - Contact us - markettraining@caiso.com Page 60

61 Release Plan 2014 Spring 2014 Post Emergency Filing BCR changes / Mandatory MSG is combined with RIMPR-Phase 1 / BCR Mitigation Measures / Bid Floor Cap FERC Order 764 Compliance / 15 Minute Market / Dynamic Transfers RDRP activation / FERC 745 Compliance Revisions to Price Corrections Independent efforts Contingency Modeling Enhancements Fall 2014 Energy Imbalance Market (EIM) Full Network Model Expansion Outage Management System Replacement (OMS) Circular Scheduling Many-to-Many Substitution Flexible Resource Adequacy Criteria and Must Offer Obligation Subject to further release planning: DRS API Deployment Subset of Hours Acceptable Use Policy Expanding Metering and Telemetry Commitment Costs Enhancements ADS User Interface Replacement and Web Service Standardization Page 61

62 2014 Release Schedule Indicates dates subject to change

63 Spring 2014 Market Participant Checkpoints Project January February March April Environment Timelines Map Test Environment Map Stage Environment Connectivity Market Sim Test Environment Stage Environment Production Production Readiness Checkpoints RUG RUG RUG RUG RUG RUG RUG RUG RUG Readiness Readiness Submit Comments Checkpoint 3 Submit Comments Checkpoint 4 Submit Comments Readiness Checkpoint 5 Based on Market Sim Readiness Based on Deployment Plan and Preliminary Market Sim Results Based on Production Readiness FERC Order 764 Compliance with 15 Minute Market and Dynamic Transfers Spring 2014 Release Project Milestones External Training Opening SIBR Lite Publish Final BPMs Connectivity Tariff Approval Structured and Unstructured Market Sim Activation April 1 Reliability Demand Response Product (RDRP) Activation, FERC Demand Response Compensation in Organized Wholesale Energy Markets Compliance Activation April 1 Post Emergency Filing Bid Cost Recovery (BCR) with Mandatory Multi-Stage Generations (MSG), Renewable Integration Market and Product Review (RIMPR) Phase, Bid Cost Recovery (BCR) Mitigation Measures and Bid Floor Cap External Training Publish Final BPMs Unstructured Market Sim Activation April 1 Revisions to Price Corrections Publish Final BPMs File Tariff Tariff Approval Activation April 1

64 Spring 2014 RIMPR Phase 1 / BCR Mitigation / Bid Floor Application Software Changes Implementation Impact Assessment IFM/RTM: Energy Bid Floor to -$150/MWh MQS: Modify MLC calculation and cost allocation rules. Change DA MLC determination Program PUIE calculation (may need to change MQS energy algorithm) Split netting between DA and RT markets. Settlements: Requires a tune-up on formulas to determine the ON criteria for resources, and the eligibility for Bid Cost Recovery. Modify and build up to 12 charge codes to implement new BCR netting rules and MLC. Program PUIE (persistent UIE) calculation. Program new RT PM (performance metric) calculation. Offset DA MLC by MLE revenues. Develop a number of BCR mitigation measurements SIBR: SIBR rule changes will be needed to change the bid floor from -$30 (soft) to -$150 (hard). CMRI: RTM to publish all advisory schedules including current and next hour in the horizon for RTPD runs Post relevant startup or transition time period for each startup cost or transition cost period from MQS in the commitment cost report Post energy allocation based on the default energy bid Post relevant startup ramp time or transition ramp time periods from MQS Monthly Market Reports incorporating greater granularity in reporting BCR components have been made available. Page 64

65 Spring 2014 RIMPR Phase 1 / BCR Mitigation / Bid Floor Milestone BPM Changes Business Process Changes Board Approval Date Settlements & Billing, Market Operation, Market Instrument Manage Billing and Settlements, Market Performance Bid Floor and BCR netting: December 15-16, 2011 Post Emergency BCR / Mandatory MSG: Feb 15, 2012 BCR Mitigation Measures: December, 2012 External Business Requirements April 19, 2013 (Post Emergency BCR posted on Feb 1, 2013) Technical Specifications October 30, 2013 Draft Configuration Guides Released in conjunction with FERC 764 on 11/14/13, 11/21/13 and 12/5/13 DRAFT Bill Determinant Matrix December 27, 2013 DRAFT Configuration Output File January 10, 2013 Updated BPMs February 7, 2013 Market Simulation February 10, 2014 March 31, 2014 Tariff filing date Mandatory MSG Filed July 30, 2013 (pending order) RI-MPR/BCR Filed September 24, 2013 FERC Order Received RIMPR/BCR December 19,2013 ISO Compliance Filing January 21, 2014 Production Activation Spring 2014 (April 1, 2014) Page 65

66 Spring FERC Order 764 Application Software Changes Implementation Impact Assessment MasterFile: Identify variable energy resources and their selection of using ISO VER forecast or their own VER forecast. SIBR: Allow market participants to submit 5-minute VER forecast with a 2-hour lookahead window Allow an intertie various additional bidding options: An hourly block schedule A single curtailment for the remainder of the hour with block schedule Option to determine 15-minute market participation if not accepted in the hourly process IFM/RTM: A new 15-Minute market with financially binding energy and AS awards for internal generators, imports/exports, and participating loads. Real time bid submission process remains same Cleared against the CASIO forecast of real time demand Executed 37.5 minutes prior to the start of the binding interval, 15 minutes earlier than the current 22.5 minute prior to the binding of RTUC run Allow a number of bidding options for an intertie A new hourly process to produce the advisory hourly block schedule for the non-dynamic intertie transaction that will be used for subsequent 15- minute market. Convergence bidding will be allowed on intertie scheduling point. All convergence bids will be settled between the day-ahead market and the 15-minute market The physical only constraint at the scheduling point of the dual constraints not enforced in the IFM but enforced in RUC. RUC establishes the number of etags it can accept for day-ahead physical market awards. 15-minute market and 5-minute market dispatch VER based on its economic energy bid and use forecast as its upper operation limit Support Primary/Alternative ITC for DS/PTG Slide 66

67 Spring FERC Order 764 Implementation Impact Assessment Application Software Changes CAS: Perform scheduling check-out based on the 15-minute based schedules and tag energy profile Perform the tag update/approval by the hourly deadline T-20 for various intertie bidding options Receive and consume the RUC cleared capacity for day-ahead tagging check-out purpose Receive and consume the RTPD 15-minute schedules for tagging check-out purpose Automatically match retag DS/PTG schedule from the primary ITC to the alternative ITC when the primary ITC become open ADS As the HASP will be replaced the hourly process to accept the block schedule and the hourly process schedule is advisory, no more HASP predispatch schedules will be issued through ADS Settlements: 15-minute energy settlements will be based on the 15-minute schedule and the dayahead energy schedule. 5-minute energy settlement will be based on the difference of 15-minute schedule and 5-minute dispatch. All metering related settlement will be changed to 5-minute base. Real-time Inter-SC trades based on 15-minute price. Metering: 10-minute metering data changed to 5-minute metering data CMRI will report the following forecast data: MarketForecastType: RTUC ( all binding and advisory 15-mintue intervals) and RTD ( all binding and advisory 5-mintue interval). Published at the same time as RTUC/RTD awards are currently published. The forecast data finally used in RTUC/RTD and available after the market runs. OASIS: Report OTC and ATC output from the IFM, Hourly Process and the 15-minute market. Report the 15-minute market LMP. DLAP/CLAP load forecast (including potential operator bias) from the market system Slide 67

68 Spring FERC Order 764 Milestone BPM Changes Date Market Operation, Market Instruments Metering Settlements & Billing, Definitions & Acronyms Business Process Changes Manage Master file: Identify variable energy resources and their selection of using ISO VER forecast or their own VER forecast DA and RT processes: A new financially binding 15 minute scheduling market run for import, export, internal resources and loads Settlements: 15-minute market settlement Price Correction and Validation: Price Validation and correction tools and/or proposed MVT tool shall be modified to include 15-minute market Price validation. Interchange Scheduling: Update/approval etag hourly transmission profile and the 15-minute energy profile for various intertie bidding options. Manage Metering: Metering data for settlement for both CAISO ME polled data and SC submitted data are changed to 5-minute. Analysis Dispute and Resolution: expanded to include validation rules and corrections for the 15-minute market solution. Market Performance (MAD/DMM): expanded to monitor market performance related to the 15-minute market scheduling and settlement. Training: Training will be needed to train Operator/Analysts on the 15-minute market scheduling and settlement. Slide 68

69 Spring FERC Order 764 Milestone External Business Requirements Date Board Approval May 15, 2013 External Data Requirements Specification Technical Specifications Draft Updated BPM s Draft Configuration Guides Market Simulation Tariff filing Nov 26, 2013 May 20 th MasterFile and SIBR May 24 th Metering and Settlements June 3 rd ADS, OASIS and CMRI Complete BRS: June 21, 2013 Jul 22 nd MasterFile, SIBR, ADS, CMRI and OASIS Jul 23 rd RUG walkthrough each application Sep 13 th - MasterFile (updated 11/7) Oct 1 st - SIBR (updated 10/28) Oct 16 th - OASIS Oct 30 th - CMRI Oct 25 th - ADS Nov 22 nd - Metering functional spec. Draft Expected Energy Formula Calculation (posted 12/9) Draft Market Instrument Dec 23 rd Draft Market Operations Dec 23 rd All draft configuration guides posted Bill determinants matrix - posted first draft 12/13 Draft configuration output file Jan 10, 2014 Production Activation Spring 2014 (April 1, 2014) Initial Draft Mkt Sim Plan and Scenarios posted on 11/13/13 Feb 3 Mar 31, 2014 Slide 69

70 Spring RDRP Activation / FERC 745 Compliance Milestone Application Software Changes BPM Changes Board Approval External Business Requirements Technical Specifications Date Activation of Reliability Demand Response Product (RDRP) including FERC Order 745 compliance. Metering (re-include what was originally removed) Market Operations Not required See: ydemandresponseproduct.aspx NA Updated BPMs Dec 2013 Market Simulation Tariff Market Simulation registration due 1/31/2014 ISO is requesting MP s to send their feedback as to when they can support a Market Simulation to MarketSim@caiso.com by 1/31. Aug 19 th, 2013 Compliance filing Production Activation Spring 2014 (April 1, 2014) * *Date subject to change Page 70

71 Spring 2014 Revisions to Price Corrections Milestone Application Software Changes Date Board Approval September 12, 2013 BPM Changes Purpose: Identify improvements in price correction rules and requirements, and time horizon for price corrections MQS: Calculation and publication change SIBR: Workflow changes to accommodate change of closing time for inter schedule trades OASIS: Publishing times from MQS February 7, 2014 Market Operations Market Instruments External Business Requirements November 18, 2013 Technical Specifications Draft Configuration Guides Market Simulation Tariff N/A N/A February 17 March 7, 2014 (tentatively) Post: December 23, 2013 File: January 2013 Approval: March 2014 (section 35.3) April 2014 (all other sections) Production Activation Spring April 1, 2014 Page 71

72 Contingency Modeling Enhancements Milestone Application Software Changes Date Distribute Study Results January 30, 2014 Board Approval May 2014 BPM Changes IFM/RTN: Adds a preventive-corrective constraint to the market cooptimization OASIS/CMRI: Publish preventive-corrective capacity awards with associated LMPC Settlements: Payment and charges for corrective capacity awards, allocation of cost of the corrective capacity constraint, no-pay provisions, bid cost recovery Manage Full Network Model, Market Operations, Market Instruments, Settlement and Billing, Definitions and Acronyms External Business Requirements Technical Specifications Draft Configuration Guides Market Simulation File Tariff Production Activation TBD TBD TBD TBD TBD 2014 will be not be in the Spring or Fall 2014 Releases; will be in an Independent Release Page 72

73 Fall 2014 Energy Imbalance Market (EIM) Milestone Application Software Changes Date Master File: Register EIM entity, EIM resources, EIM resource emission rate, EIM Interties SIBR: Accept and validate submitted EIM resource plan and load base schedule, EIM resource bids. ALFS: Forecast EIM load, EIM VER. EMS: Model updates EIM BAA, model EIM NSI. DAM/RTM: Perform the DCPA for each BAA for the constraint in the BAA and the test and mitigate the resources in the BAA; Decompose the LMP congestion by the constraint belong the same BAA; option for EIM entity unit commitment; All LMPs will not include marginal loss contributions from external network losses; The EIM entity access the interface to submit exceptional dispatch with EIM type ; send the latest valid prior RTD advisory results to EIM when ISO run RTCD. Model Greenhouse Gas (GHG) emission for EIM to ISO; Calculate BAAs transfers; Perform flexible ramping requirement sufficiency test. Meet flexible ramping requirement by BAA and total. MQS: Calculate resource unit contribution on congestion cost for real time congestion balance account. OMS: EIM submission of resource and transmission Outages Settlement: settle 15 minute and 5 minute markets IIE and UIE at LMP ; Calculate EIM LAP hourly volumetric weighted average LMP weighted by the load forecast deviations bounded by the min/max LMPs; Settle EIM administrative cost; create real-time congestion balancing account for each BAA; Collect and allocate underschedule penalty by month. Settle EIM resource BCR. Allocate uplift to the BAA shared by the transfers. Pay the flexible ramping capacity use current formula, allocate the cost prorata to the requirements. CMRI/OASIS/ADS: Publish the market results for EIM BAA and resources. Page 73

74 Fall 2014 Energy Imbalance Market (EIM) Milestone Date BPM Changes Market Operations, Market Instruments, Settlements and Billing Board Approval November 8, 2013 External Business Requirements September 27, 2013 Technical Specifications April 1, 2014 Updated BPMs June 6, 2014 Market Simulation July 8, 2014 Tariff filing February 28, 2014 Production Activation October 1, 2014 Page 74

75 Fall 2014 Full Network Model Expansion Milestone Application Software Changes BPM Changes Date Board Approval February 2014 External Business Requirements October 31, 2013 Technical Specifications February 3, 2014 Updated BPMs Master File: Define external BAA scheduling point as Generation Aggregated Point (GAP) and GDF SIBR: Submit and create transaction ID for the SC Bids on Scheduling Points-BAA dynamically; Allow the SC bids at same BAA-SP to bid to different interties. DAM/RTM: Receive the dynamically formed transaction ID attributes from bid, perform contingency analysis for some critical external BAA resources and transmission equipment. Incorporate external BAA critical outages, Enforce both flow and schedule Intertie constraints, Model HVDC line. CRR: CRR market run on expanded Full Network Model. CMRI/ADS/OASIS/Settlement: Receive and process the dynamically formed transaction ID. Market Operations, Market Instruments, Managing FNM TBD Market Simulation July 8, 2014 Tariff TBD Production Activation Fall 2014 Page 75

76 Fall 2014 Many to Many Substitution Requests Milestone Application Software Changes Board Approval BPM Changes Date RAAM/CIRA: New functionality to process many to many substitution requests. The system needs to be able to track RA, Non-RA, and substitution capacity. System must have the capability to use any Non-RA capacity for a substitution even if the unit is used for another substitution as long as eligible Non-RA capacity exists. Validation rules for submission of substitution requests must be enhanced. View within RA system must be enhanced to show RA, CPM, RMR, and SCP substitution capacity. Views must be enhanced in the system to display substitution requests, usage of resources and outage information Existing production defects must be fixed N/A External Business Requirements November 18, 2013 Reliability Requirements, Settlement and Billing Technical Specifications Draft Configuration guides Market Simulation File Tariff Production Activation TBD TBD TBD Tariff clarification likely in legal review Fall 2014* *subject to full funding approval by CMC in Dec/Jan 2013 Page 76