EIM-Related Price correction events increased in November and December 18 16 14 12 Count of Events 10 8 6 4 2 0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2015 2016 Process Events Software Events Data Error Events Tariff Inconsistency Page 44
EIM Price trends Page 45
EIM transfers Page 46
EIM BCR in November and December Page 47
EIM Manual Dispatch in November and December Page 48
Day-ahead load forecast 3.0% 2.5% 2.0% 1.5% MAPE 1.0% 0.5% 0.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2014 2015 2016
Day-ahead peak to peak forecast accuracy 3.5% 3.0% 2.5% 2.0% 1.5% MAPE 1.0% 0.5% 0.0% Mar Apr May Aug Sep Nov Dec Jan Feb Jun Jul Oct 2014 2015 2016
Day-ahead wind forecast 10.0% 9.0% 8.0% 7.0% 6.0% 5.0% 4.0% MAE 3.0% 2.0% 1.0% 0.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2014 2015 2016
Day-ahead solar forecast 14.0% 12.0% 10.0% 8.0% 6.0% MAE 4.0% 2.0% 0.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2014 2015 2016
Real-time wind forecast 4.5% 4.0% 3.5% 3.0% 2.5% 2.0% MAE 1.5% 1.0% 0.5% 0.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2014 2015 2016
Real-time solar forecast 6% 5% 4% 3% MAE 2% 1% 0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2014 2015 2016
Flexible ramping sufficiency test Keith Collins Manager, Monitoring and Reporting Department of Market Monitoring Page 55
Flexible ramping sufficiency test • Ensures that each EIM balancing authority area has sufficient upward and downward ramping capability over an hour to meet expected ramp as well as uncertainty • If a balancing area does not have sufficient ramping capacity, then: – It cannot increase EIM transfers into its area to meet upward ramping limitations – It cannot decrease EIM transfers from its area to meet downward ramping limitations Page 56
Flexible ramping sufficiency test • In order to pass the hourly flexible ramping sufficiency test in a given direction (upward or downward), an EIM entity needs to show sufficient ramping capability from the start of the hour to each of the four 15-minute intervals in the hour. • An EIM entity must pass all four 15-minute interval tests in order to pass the hourly flexible ramping sufficiency test for upward and downward ramping. 𝐺𝑚𝑓𝑦 𝑆𝑏𝑛𝑞 𝑉𝑞 𝑆𝑓𝑟𝑣𝑗𝑠𝑓𝑛𝑓𝑜𝑢 −𝑂𝑓𝑢 𝐽𝑛𝑞𝑝𝑠𝑢 𝐷𝑏𝑞𝑏𝑐𝑗𝑚𝑗𝑢𝑧, = ∆𝑀𝑝𝑏𝑒 + 𝐺𝑚𝑓𝑦 𝑉𝑞 𝑉𝑜𝑑𝑓𝑠𝑢𝑏𝑗𝑜𝑢𝑧 + max −𝐸𝑗𝑤𝑓𝑠𝑡𝑗𝑢𝑧 𝐶𝑓𝑜𝑓𝑔𝑗𝑢 − 𝐺𝑚𝑓𝑦 𝑆𝑏𝑛𝑞 𝑉𝑞 𝐷𝑠𝑓𝑒𝑗𝑢 Forecasted Uncertainty component Diversity benefit and credit reduction component (Same used in flexible capped at net import capability ramping product) Page 57
Flexible ramping sufficiency test – Modifiers • Diversity Benefit Factor – A fraction that represents a balancing authority area’s share of the net load forecast error for the combined EIM area. It is equal to the EIM area uncertainty requirement divided by the sum of the individual balancing authority area uncertainty requirements. It represents the smoothing effect that happens when combining net load forecast errors across a larger footprint. • Flexible ramping credit – The ability to reduce exports to increase upward ramping capability or reduce imports to increase downward ramping capability. Page 58
Flexible ramping sufficiency test – Modifiers • Net import capability – The amount of import capacity a balancing authority area has in each interval. The reduction in the upward sufficiency test requirement because of any diversity benefit or flexible ramping up credit may not be greater than the available net import capability. • Net export capability – The amount of export capacity a balancing authority area has in each interval. The reduction in the downward sufficiency test requirement because of any diversity benefit or flexible ramping down credit may not be greater than the available net export capability. Page 59
Sufficiency test example – diversity benefit • PacifiCorp West upward sufficiency test on December 2, hour 17 1,400 CAISO PACE PACW PSEI NEVP AZPS EIM area 1,200 Sum of BAA uncertainties = 1,210 MW 1,000 PACW uncertainty 800 = 97 MW MW EIM area uncertainty = 514 MW 600 400 Pro rata diversity benefit reduction = 56 MW 200 0 PACW uncertainty * PACW uncertainty BAA uncertainties EIM area uncertainty diversity benefit factor Diversity benefit factor = 514 1,210 = 42% • PACW diversity benefit reduction = 97 − 97 ∗ 42% = 56 MW • Page 60
Sufficiency test example – net transfer capability and credits • Upward sufficiency test on December 2, hour 17 1,000 HMWY import limit Total import limit = 906 MW MALIN import limit 800 Imports BPAT import limit With PACE on HMWY 600 With PSEI on BPAT With CAISO on MALIN 400 Net import capability = Total import limit 1,064 MW Net transfer 200 0 Flex ramp up credit = Exports net EIM export = 158 MW -200 (zero down credit) -400 PACW • PacifiCorp West flexible ramping up credit = 158 MW • PacifiCorp West net import capability = 1,064 MW Page 61
Sufficiency test example – PacifiCorp West Hour 17 𝐺𝑚𝑓𝑦 𝑆𝑏𝑛𝑞 𝑉𝑞 𝑆𝑓𝑟𝑣𝑗𝑠𝑓𝑛𝑓𝑜𝑢 −𝑂𝑓𝑢 𝐽𝑛𝑞𝑝𝑠𝑢 𝐷𝑏𝑞𝑏𝑐𝑗𝑚𝑗𝑢𝑧, = ∆𝑀𝑝𝑏𝑒 + 𝐺𝑚𝑓𝑦 𝑉𝑞 𝑉𝑜𝑑𝑓𝑠𝑢𝑏𝑗𝑜𝑢𝑧 + max −𝐸𝑗𝑤𝑓𝑠𝑡𝑗𝑢𝑧 𝐶𝑓𝑜𝑓𝑔𝑗𝑢 − 𝐺𝑚𝑓𝑦 𝑆𝑏𝑛𝑞 𝑉𝑞 𝐷𝑠𝑓𝑒𝑗𝑢 −1,064, 𝐺𝑚𝑓𝑦 𝑆𝑏𝑛𝑞 𝑉𝑞 𝑆𝑓𝑟𝑣𝑗𝑠𝑓𝑛𝑓𝑜𝑢 = 197 + 97 + max −56 − 158 = 80 • 𝑉𝑞𝑥𝑏𝑠𝑒 𝑠𝑏𝑛𝑞𝑗𝑜 𝑑𝑏𝑞𝑏𝑑𝑗𝑢𝑧 𝑏𝑤𝑏𝑗𝑏𝑐𝑚𝑓 = 218 • • PacifiCorp West passes the test for the fourth 15-minute interval of the hour Page 62
Flexible ramping sufficiency test example – PacifiCorp West 800 Import capability reduction Diversity benefit reduction Flex ramp credit reduction Forecasted component Uncertainty component Net requirement 600 Upward ramping capacity 400 200 MW 0 -200 -400 -600 123412341234123412341234123412341234123412341234123412341234123412341234123412341234123412341234 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Hour and test # • PacifiCorp West failed sufficiency test in hour ending 9. Page 63
Flexible ramping sufficiency test – Upward ramping sufficiency failures 30 PACE PACW NEVP PSEI AZPS Number of hours where the sufficiency test failed 25 20 15 10 5 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 October November December • There was a significant uptick in sufficiency failures after launch of the flexible ramping product on November 1. Many were due to issues in counting available supply to meet the requirement. Page 64
Flexible ramping sufficiency test – Downward ramping sufficiency failures 18 PACE PACW NEVP PSEI AZPS Number of hours where the sufficiency 16 14 12 test failed 10 8 6 4 2 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 November December • The downward sufficiency test was added on November 1. • There have been a significant set of failures in the APS area since launch. Page 65
Policy Update Brad Cooper Manager, Market Design and Regulatory Policy Page 66
Ongoing policy stakeholder initiatives • Stakeholder Initiatives Catalog – Feb EIM Governing Body and ISO Board Meetings • Energy Storage and Distributed Energy Resources (ESDER) - Phase 2 – Schedule TBD • Bid Cost Recovery Enhancements – Revised straw proposal in Jan – Remaining schedule TBD • Contingency Modeling Enhancements – Technical analysis results and stakeholder call targeted for Jan-Feb – May ISO Board Meeting Page 67
Ongoing policy stakeholder initiatives (continued) • Stepped Constraint Parameters – Incorporating parameter changes needed for FERC Order 831 compliance – Straw proposal targeted for Feb – May EIM Governing Body and ISO Board Meetings • Generator Contingency and Remedial Action Scheme Modeling – Revised straw proposal targeted for Jan – July EIM Governing Body and ISO Board Meetings Page 68
Ongoing policy stakeholder initiatives (continued) • Commitment Costs and Default Energy Bid Enhancements – Straw proposal targeted for February 2017 – July EIM Governing Board and ISO Board Meetings – Will address bid cost verification for FERC Order 831 compliance • Frequency Response – Phase 2 – Working groups meetings in Feb, March – Straw proposal targeted for April – Sept ISO Board Meeting • Flexible Resource Adequacy Criteria and Must-Offer Obligation – Phase 2 – Revised straw proposal targeted for Feb 2017 – Board Meeting TBD Page 69
Ongoing policy stakeholder initiatives (continued) • Regional Integration and EIM Greenhouse Gas Compliance – ARB 15-Day Notice comments due Jan 20 – Draft final proposal TBD – EIM Governing Body and ISO Board Meeting TBD • Transmission Access Charge Options, Regional Resource Adequacy – Frameworks published Dec 2016 – ISO response to comments targeted Jan-Feb – Further policy development on hold pending regional governance structure development Page 70
Policy stakeholder initiatives coming soon • Planned to start in Q1 2017 – Resource Adequacy Enhancements – Economic and Maintenance Outages – CRR Auction Efficiency Analysis Working – Blackstart and System Restoration Page 71
Sub-LAP Areas Update Jim Price Senior Advisor, Market Development & Analysis Slide 72
Recap: Sub-LAPs within default load aggregation points (DLAPs) have been implemented as of 1/1/2017 • Other than publication of locational marginal prices (LMPs), Sub-LAPs have two purposes: – Aggregations of demand response and distributed resources – More precise congestion costs than default LAPs and award of additional CRRs when congestion limits DLAPs. • Existing Sub-LAPs were identified when current market design was implemented in MRTU, and were outdated • Basing Sub-LAP boundaries on RA local capacity areas will allow demand response to qualify as local RA resources. • Several Sub-LAP boundaries have shifted slightly to reflect RA areas, and some could be merged. • Updates do not change Custom LAPs of Participating Loads. • If RA local capacity areas change, Sub-LAPs will follow. Page 73
Most Sub-LAPs retain same name. Name changes indicate splitting or merging areas. Current Sub- Current Sub- New Sub- New Sub-LAP LAP LAP LAP SLAP_PGCC SLAP_PGCC SLAP_SCEC SLAP_SCEC SLAP_PGEB SLAP_PGEB SLAP_SCEN SLAP_SCEN SLAP_PGF1 SLAP_PGF1 SLAP_SCEW SLAP_SCEW SLAP_PGFG SLAP_PGFG SLAP_SCHD SLAP_SCHD SLAP_PGHB SLAP_PGHB SLAP_SCLD SLAP_SCLD SLAP_PGZP SLAP_SCNW SLAP_SCNW SLAP_PGLP SLAP_PGKN (New SLAP_SDG1 SLAP_SDG1 LCA) SLAP_PGNB SLAP_PGNB Not defined SLAP_VEA SLAP_PGNC SLAP_PGNC SLAP_PGNV SLAP_PGNP SLAP_PGP2 SLAP_PGP2 SLAP_PGSA SLAP_PGSI SLAP_PGSB SLAP_PGSB SLAP_PGSF SLAP_PGSF SLAP_PGSI SLAP_PGSI SLAP_PGSN SLAP_PGNP SLAP_PGST SLAP_PGST Page 74
CRR Modeling of change to Sub-LAPs • Sub-LAP Changes – Changes to Sub-LAP definitions were initially intended for implementation on 1/1/2017 – A few days before the 2017 annual auction was to open the ISO received notice of a concern with the implementation of this change – After review it was determined that there was a possible exposure to the market and that the best solution was to update the model to be used for the annual auction ahead of schedule
CRR Modeling of change to SLAPs • Sub-LAP Changes created multiple revisions to CRR FNM – Since the process for developing the new Sub-LAPs was outside of the normal process for developing this data there were multiple revisions made to the CRR FNM – These revisions created additional workload for our participants as well as the ISO – The CAISO recognizes the additional effort this required for our participants – Going forward we are not expecting the significant changes that were seen this time and the updates will flow through our normal change process and not be implemented as they were this time
Model Enhancement for Distributed Energy Resources with update on Sub-Lap revision implementation for PDR/RDRR Jill Powers Smart Grid Solutions Manager, Smart Grid Technologies and Strategy Slide 77
UPDATE: SubLap Redefinition Implementation Completed for PDR/RDRR ISO and Demand Response Providers coordinated PDR/RDRR registration activities to successfully transition to new Sub-Laps • Effective 1/1/2017 Locations and Registrations reflect new Sub-Lap areas • Pre-defined Resources were made available for revised Sub-Laps prior to 1/1/2017 to meet Resource Adequacy (RA) processing timelines Activities were completed prior to the Demand Response Registration System (DRRS) Phase 2 Enhancements November 30, 2016 deployment. Page 78
1/1/2017 Effective SubLap Selections Available in DRRS • Master file effective dated SubLaps • Choices in SUBLAP field are determined by Start Date / End Date of location • Any Location created with Start Date on or after 1/1/2017 can only choose new SUBLAPs Slide 79
ISO Established Pre-Defined Resource ID Modeling Based On 1/1/2017 Effective Sub-LAP Boundaries 2017 Sub-Lap Pre-Defined Modeling Impact PGCC, PGEB, PGF1, PGFG, PGHB, No Change PGNC, PGP2, PGSB, PGSF, SCEW, SCHD, SCNW, SDG1 PGNB, PGSI, PGST Distribution Factor Changes Only SCEC, SCEN, SCLD Distribution Factor Change with added or removed substation(s) PGKN, PGNP, PGZP, VEA New The ISO has posted a spreadsheet titled 2017 Sub-Load Aggregation Point to California ISO Bus Mapping to its load participation and demand response webpage http://www.caiso.com/Documents/2017Sub-LoadAggregationPointToCaliforniaISOBusMapping.xls A spreadsheet for 2017 Pre-Defined Resources Sub-LAP to Bus (Pnode) to Distribution Factor association will be posted 80
Model Enhancement Provides Ease of Resource ID Implementation for all DERs Deployed New Modeling Capability Before 1/1/2017 • Resource will be created on demand in the Masterfile when requested through the GRDT process – Significantly reduces processing timelines and management of requests for a new Resource ID for DERAs – Maintains Pre-Defined resource ID option for PDR/RDRRs – Customizing DER resources no longer requires a Full Network Model (FNM) update More information on model change requirements are in the Energy Storage and Distributed Energy Resource (ESDER) BRS: http://www.caiso.com/Documents/BusinessRequirementsSpecification-v10-EnergyStorageandDistributedEnergyResources.pdf 81
Release Plan Update Janet Morris Director, Program Office Page 82
The ISO offers comprehensive training programs Date Training February 7 Settlements 101 (Folsom) February 8 Settlements 201 (Folsom) Training calendar - http://www.caiso.com/participate/Pages/Training/default.aspx Contact us - markettraining@caiso.com 83
Release Plan 2017 Independent 2017 • Settlements Release - January 2017 • MRI-S ACL Groups + CPG Enhancements (formerly OMAR Replacement) • Reactive Power Requirements and Financial Compensation – no system changes • Administrative Pricing Policy Update • RIMS Functional Enhancements Spring 2017 • Acceptable Use Policy – CMRI • RTD Local Market Power Mitigation (LMPM) Enhancements • CRR Clawback Modifications • PIRP System Decommissioning • Metering Rules Enhancement Fall 2017 • Bidding Rules Enhancements – Part B • Reliability Services Initiative Phase 1B • Reliability Services Initiative Phase 2 • Commitment Cost Enhancement Phase 3 • RTM & EIM 2017 Enhancements • EIM Portland General Electric (PGE) Page 84
Release Plan – 2018 and subject to further planning Spring 2018 • EIM 2018 Idaho Power Company Fall 2018 – tentative, subject to impact assessment • Bid Cost Recovery Enhancements • Generation Contingency and Remedial Action Scheme • Flexible Resource Adequacy Criteria and Must-offer Obligation Phase 2 • Frequency Response Phase 2 • Contingency Modeling Enhancements • Commitment Costs and Default Energy Bid Enhancements • ADS User Interface Replacement Subject to further release planning: • ESDER Phase 2 • Stepped Transmission Constraints • Regional Resource Adequacy • Regional Integration and EIM Greenhouse Gas Compliance • Transmission Access Charge Options Page 85
Settlements Release – January 2017 ISSUE SUMMARY BPM IMPACTED Update BPM for charge code 6478 real-time system imbalance energy offset and CC 6985 real-time marginal losses offset to align the documentation PRR 946: ( CC 6478 and CC 6985) Documentation Only with the current active settlement configuration Updated BPM for metered energy adjustment factor pre-calculation to PRR 947: (PC Metered Energy Adjustment Factor) clarify conversion of ramp rate in minutes to MWh Updated capacity procurement mechanism (CPM) related configuration PRR 948: (PC Metered Demand over TAC Area, CC 7891, guides to re-formulate the eligible CPM capacity designation quantity and and CC 7896 ) pass through bill functionality Update BPM configuration guide for spin non-spin no pay pre-calculation to retroactively adjust calculation impacting resources without regulation PRR 949: (PC Spin Non-Spin No-Pay) schedules Update BPMs for start-up and minimum load cost and integrated forward PRR 955: ( PC Start-up Metered Energy Adjustment Factor market net amount pre-calculation to implement bidding rules v.5.14, and PC IFM Net Amount) enhancement Pmin rerate Pmax derate settlements Update configuration guides in accordance with administrative pricing initiative to settle congestion revenue rights at the average hourly fifteen PRR 956: (CC 6700) minute market price when specific conditions are triggered Update existing BPM for real-time net amount pre-calculation to exclude hourly block bid opted intertie resources flex ramp product settlement PRR 957: (PC RTM Net Amount) amounts in bid cost recovery Update real time market net amount pre-calculation for regulation up and PRR# 958 (PC RTM Net Amount) regulation down bid cost recovery costs Updated calculation of day ahead and real time self-scheduled bids for PRR# 959 (PC RA Availability Incentive Mechanism) resource adequacy availability incentive mechanism Updated calculations and business rules for RA Availability Incentive PRR# 960 (PC RA Availability Incentive Mechanism, CC Mechanism settlement 8830, and CC 8831) Page 86
Settlements Release – January 2017 Milestone Date Status Configuration Guides Posted December 13, 2016 First DRAFT Configuration Output File Posted December 15, 2016 Second DRAFT Configuration Output File Posted January 13, 2017 Pre-Production DRAFT Configuration Output File Posted January 17, 2017 Production Deployment January 24, 2017 FINAL Configuration Output File Posted January 24, 2017 Page 87
2017 - MRI-S ACL Groups+ CPG Enhancements Project Info Details/Date The MRI-S metering (MRI-S) application cannot currently support ACL (Access Control List) groups functionality for defining a subset of resources belonging to an SCID. Application Software Changes Enhancements to the Application Identity Management (AIM) application will enable the use of ACL groups for SCID-level read-only access for MRI-S. BPM Changes None Potential Level-II business process changes under – • Business Process Changes Manage Market & Reliability Data & Modeling • Manage Operations Support & Settlements Milestone Type Milestone Name Dates Status Board Approval Board Approval N/A BPMs Metering BPM Changes N/A External BRS Post External BRS Nov 14, 2016 Tariff Pre-Tariff Filing QRB N/A Config Guides Configuration Guide N/A Tech Spec Publish Tech Specs Nov 02, 2016 Market Simulation Phase 2 - MRI-S Metering Enhancements Feb 01, 2017 - Feb 28, 2017 Production Activation Phase 1 - ACL Groups Feb 01, 2017 Phase 2 - MRI-S Metering Enhancements Mar 08, 2017 Page 88
MRI-S ACL Groups + CPG Enhancements # System Summary Status Estimated Fix Date Under review See previous slide 1 MRI-S CIDI 183777, 183993 - MRI-S for Metering Limitation of 100,000 records. 2 MRI-S Option to choose UOM is missing on the UI 3 MRI-S CIDI 184018 - Time zone is missing on the UI 4 MRI-S CIDI 183777, 183993 - Modification to AUP policy on data retrieval to include querying by last updated time Option to request for data in various time interval in UI 5 MRI-S Ability to view log files within the same organization 6 MRI-S Ability to provide SC ID in the data retrieve request 7 MRI-S *ACL Group – filter read-only at the resource level MRI-S In process See previous slide * ACL group creation to filter for a read only role at the resource level is not currently available Page 89
MRI-S ACL Groups + CPG Enhancements Per last fall’s Customer Partnership Group discussions, the ISO will be not be performing any user access migration, including the current third party access in OMAR to AIM because: • The platform and business logic for third party access are completely different between OMAR and AIM, so no automation is possible • Any effort by the ISO would be manual, and would require heavy market participant involvement due to data integrity questions around security and third-party access concerns • The data in OMAR is historical (aged) and therefore must be vetted by the Scheduling Coordinators to ensure its validity Page 90
2017 – Reactive Power Requirements and Financial Compensation Project Info Details/Date Application Software Changes None BPM Changes None Develop Infrastructure (DI) (80001) • Level II - Manage Generator Interconnection Process (GIP) (Logical Group): Business Process Changes Milestone Type Milestone Name Dates Status Board Approval BOG Approval N/A BPMs Post Draft BPM changes N/A External BRS Post External BRS N/A File Tariff Dec 6 Tariff FERC Approval Feb 6 Config Guides Prepare Draft Configuration Guides N/A Tech Spec Publish Tech Specs N/A Market Sim Market Sim Window N/A Production Activation Reactive Power Requirements and Financial Compensation March 6, 2017 Page 91
2017 – Administrative Pricing Policy Updates Project Info Details/Date • MQS: • Part 1 (used under normal market conditions): If there are less than 12 RTDs and 4 RTPDs missing – leverage existing process (last price used) • Part 2 (used under normal market conditions): If RTD prices are available copy over Application Software Changes to RTPD; RTPD prices available copy over RTD. If neither RTPD or RTD prices are available use DA prices • Part 3 (used Market Suspension conditions): Use DA prices. If we don’t have DA prices, revert to prior DA prices (awards and prices) • Business Process Change Manage Markets and Grid BPMs Market Instruments, Market Operations Milestone Type Milestone Name Dates Status Board Approval BOG Approval Dec 10, 2014 BPMs Post Draft BPM changes Jan 6, 2017 External BRS Post External BRS Mar 20, 2015 Tariff File Tariff Nov 23, 2016 Config Guides Prepare Draft Configuration Guides Dec 2, 2016 Tech Spec Publish Tech Specs N/A Market Sim Market Sim Window N/A Production Activation Bidding Rules Part B Feb 01, 2017 Page 92
2017 – RIMS Functional Enhancements Project Info Details/Date Status Functional enhancements resulting from the Customer Partnership Group CPG. Application Software Changes More details to be provided in the future. Generator Interconnection and Deliverability Allocation Procedures Generator Interconnection Procedures Managing Full Network Model BPM Changes Metering Generator Management Transmission Planning Process Customer Partnership Group 10/16/15 Application and Study Webinar 3/31/16 Milestone Type Milestone Name Dates Status Board Approval Board approval not required N/A BPMs Generator Interconnection and Delivery Allocation Apr 29, 2016 External BRS External BRS not Required N/A Tariff No Tariff Required N/A Tech Spec No Tech Specifications Required N/A Production Activation Ph1 RIMS5 App & Study Mar 21, 2016 Production Activation Ph2 RIMS5 Queue Management, Transmission and Generation TBD Page 93
Spring 2017 – Acceptable Use Policy – CMRI Project Info Details/Date Scope includes enforcement of Acceptable Use Policy for CMRI services to support the full implementation of 1 call per service per identity (as designated by certificate) every 5 seconds. An error Application Software Changes code of 429 will be returned for any violation instance of the use policy. Milestone Type Milestone Name Dates Status Board Approval Board Approval N/A BPMs BPMs N/A External BRS External BRS N/A Tariff Tariff N/A Config Guides Config Guide N/A Tech Spec Tech Spec N/A Market Sim Market Sim Window Aug 23, 2016 - Sep 23, 2016 Production Activation Acceptable Use Policy - CMRI Apr 1, 2017 Page 94
Spring 2017 - Real Time Dispatch Local Market Power Mitigation Project Info Details/Date • CMRI – Display mitigated bids from RTD process • OASIS (Open Access Sametime Information System): Display RTD reports for Market Clearing, the Pnode clearing, similar to current RTPD reports Application Software Changes • RTM (Real Time Market) • RTPD: Perform the LMPM run as an integral part of the binding interval RTPD run • RTD: Proposed mitigation in RTD run would work the same way as the current RTPD run • Energy Imbalance Market (EIM): under the proposed RTD method, bids are not necessarily mitigated for the whole hour BPM Changes • RTD MPM will work the same way as the current RTPD MPM • Manage Markets & Grid • ATF – System Operations: Add MPM Application to Real Time and annotate inputs and outputs Business Process Changes • ATF – System Operations, Real Time: Add MPM to diagram with inputs and outputs • Level II – Manage Real Time Operations – maintain balancing area Page 95
Spring 2017 - Real Time Dispatch Local Market Power Mitigation Milestone Type Milestone Name Dates Status Board Approval Board of Governors (BOG) approval Mar 24, 2016 BPMs Posted Market Operations BPM PRR 945 Nov 04, 2016 External BRS Post External BRS Apr 05, 2016 Tariff Received FERC approval Nov 08, 2016 Tech Spec Publish Technical Specification - OASIS Apr 08, 2016 Publish Technical Specification - CMRI Apr 14, 2016 Market Sim Market Sim Window Jan 31, 2017 - Feb 16, 2017 Production Activation RTD - Local Market Power Mitigation Enhancement Apr 01, 2017 CMRI OASIS ADS Project Update (add RTD results)- - PRC_MPM_RTM_LMP - PRC_MPM_RTM_NOMOGRAM - PRC_MPM_RTM_NOMOGRAM_CMP N/A RTD LMPM Update (add RTD results): - PRC_MPM_RTM_FLOWGATE MPMResults v3 - PRC_MPM_CNSTR_CMP - PRC_MPM_RTM_REF_BUS -ENE_MPM Page 96
Spring 2017 – Congestion Revenue Rights (CRR) Clawback Project Info Details/Date MQS/CRR Clawback: If import bid <= day-ahead price, then the import is not considered a virtual award. If export bid >= day-ahead price, then the export is not considered a virtual award. If an import/export bid/self-schedule in real-time market is less than the day-ahead schedule, then the difference shall be still subject to CRR Clawback rule. Application Software Changes CRR Clawback rule should include convergence bids cleared on trading hubs and load aggregation points in the flow impact used to determine if the 10% threshold is reached. Inform Market Participants of CRR annual allocation/auction for 2017. BPM Changes Market Operations Appendix F Business Process Changes TBD Milestone Type Milestone Name Dates Status Board Approval Board of Governors Approval Jun 28, 2016 BPMs Publish Final Business Practice Manuals Jan 30, 2017 External BRS Post External BRS Nov 29, 2016 Tariff File Tariff Jan 20, 2017 Receive FERC order Mar 21, 2017 Production Activation CRR Clawback Modification Apr 01, 2017 Page 97
Spring 2017 – PIRP Decommissioning Project Info Details/Date • Forecast Data Reporting (resource-level) that was performed in PIRP will be done in CMRI. Rolling Hour Ahead, Locked Hour Ahead, and Rolling Day-Ahead forecasts. • PIRP Decommissioning to occur in 2017 Application Software Changes: PIRP/CMRI • CMRI to receive the Electricity Price Index for each resource and publish it to the Market Participants. • 60 Day PIRP / CMRI parallel production to start when AIM/ACL becomes available. BPM Changes CMRI Technical Specification; New APIs will be described. Atlas Reference: 1. Price Correction Messages (ATL_PRC_CORR_MSG) 2. Scheduling Point Definition (ATL_SP) 3. BAA and Tie Definition (ATL_BAA_TIE) Data Transparency 4. Scheduling Point and Tie Definition (ATL_SP_TIE) • Independent changes, won’t 5. Intertie Constraint and Scheduling Point Mapping (ATL_ITC_SP) impact existing services 6. Intertie Scheduling Limit and Tie Mapping (ATL_ISL_TIE) • Will be made available in Production and cutover Energy schedule is discretionary • EIM Transfer Limits By Tie (ENE_EIM_TRANSFER_LIMITS_TIE) • Wind and Solar Summary (ENE_WIND_SOLAR_SUMMARY) Prices • MPM Default Competitive Path Assessment List (PRC_MPM_DEFAULT_CMP) Business Process Changes MPs will receive the VER reports from CMRI rather than PIRP. Page 98
Spring 2017 – PIRP Decommissioning Milestone Type Milestone Name Dates Status Board Approval Board Approval N/A Publish Draft Business Practice Manuals (Market BPMs Sep 06, 2016 Instruments; PRR 936) External BRS External Business Requirements Jun 29, 2015 Tariff Tariff Filing Activities N/A Config Guides Settlements Configuration N/A Tech Spec Publish Technical Specifications (CMRI; Wind and Solar) Apr 15, 2016 Publish Technical Specifications (CMRI: PIRP Feb 05, 2016 Decommissioning) Market Sim CMRI Reports; VER Forecast & EPI (Fall 2016 Release) Aug 23, 2016 - Sep 23, 2016 New Renewables CMRI reports and APIs Mar 02, 2017 - Mar 20, 2017 Production Activation CMRI Reports; VER Forecast & EPI (Fall 2016 Release) Oct 01, 2016 OASIS API Enhancements; 9 Reports Dec 20, 2016 New Renewables CMRI reports and APIs April 1, 2017 Page 99
Spring 2017 – Metering Rules Enhancements Project Info Details/Date Application Software Changes N/A Metering • Metering BPM will be updated to reflect the ISO ME vs SC ME role options, changes to the metering entity election process, and impacts for metering data access via the metering data submission portal. • EIM BPM will be updated to explain Metering data reporting access BPM Changes based on transitions from ISOME to SCME (shall transition to submission of SQMD meter data to Metering Data submission portal) or SCME to ISOME (shall be able to review historical meter data in MRI-S when resource was SCME). Definitions & Acronyms BPM Changes • New Tariff and Business Process/System acronyms. • Manage Transmission & Resource Implementation • Manage Market & Reliability Data & Modeling (MMR) (80004) • ISO Meter Certification (MMR LII) • Metering Systems Access (Production) (MMR LII) • Metering System Configuration for Market Resources (MMR LII) • Station Power Implementation (MMR LIII) Business Process Changes • Application Flow - Billing & Settlements • Analyze Missing Measurement Report (MOS LIII) • Manage Market Billing & Settlements (MOS LII) • Manage Market Quality System (MOS LII) • Manage Rules of Conduct (MOS LII) • Meter Data Acquisition & Processing (MOS LII) • SCME Self Audit (MOS LII) Page 100
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