Operations Performance Metrics Monthly Report

Transcription

1 Operations Performance Metrics Monthly Report December 215 Report Operations & Reliability Department New York Independent System Operator Prepared by NYISO Operations Analysis and Services, based on settlements initial invoice data collected on or before January 11, 216.

2 Table of Contents Highlights Operations Performance Reliability Performance Metrics Alert State Declarations Major Emergency State Declarations IROL Exceedance Times Balancing Area Control Performance Reserve Activations Disturbance Recovery Times Load Forecasting Performance Wind Forecasting Performance Wind Curtailment Performance Lake Erie Circulation and ISO Schedules Broader Regional Market Performance Metrics Ramapo Interconnection Congestion Coordination Monthly Value Ramapo Interconnection Congestion Coordination Daily Value Regional Generation Congestion Coordination Monthly Value Regional Generation Congestion Coordination Daily Value Regional RT Scheduling - PJM Monthly Value Regional RT Scheduling - PJM Daily Value Market Performance Metrics Monthly Statewide Uplift Components and Rate RTM Congestion Residuals Monthly Trend RTM Congestion Residuals Daily Costs RTM Congestion Residuals Event Summary RTM Congestion Residuals Cost Categories DAM Congestion Residuals Monthly Trend DAM Congestion Residuals Daily Costs DAM Congestion Residuals Cost Categories NYCA Unit Uplift Components Monthly Trend NYCA Unit Uplift Components Daily Costs Local Reliability Costs Monthly Trend & Commitment Hours TCC Monthly Clearing Price with DAM Congestion ICAP Spot Market Clearing Price UCAP Awards 1

3 December 215 Operations Performance Highlights Peak load of 21,254 MW occurred on 12/28/215 HB 17 All-time winter capability period peak load of 25,738 MW occurred on 1/7/214 HB 18 hours of Thunder Storm Alerts were declared hours of NERC TLR level 3 curtailment Coordinated Transaction Scheduling (CTS) with ISO New England was activated on 12/15/215. On 12/2/215 the NYISO declared the Alert State and reduced power flows to 9% of ratings due to the K-8 intensity solar storm. The Five Mile Road station project went into service 12/23/215, reducing the need for out of market commitments to manage Western New York reliability. The following table identifies the estimated production cost savings associated with the Broader Regional Market initiatives. Current Month Value ($M) Year-to-Date Value ($M) Regional Congestion Coordination $3.2 $17.91 Regional PJM-NY RT Scheduling $.5 $2.48 Regional NE-NY RT Scheduling ($.9) ($.9) Total $3.16 $2.3 Statewide uplift cost monthly average was ($.18)/MWh The following table identifies the Monthly ICAP spot market prices by locality and the price delta. Spot Auction Price Results NYCA Lower Hudson Valley Zones New York City Zone Long Island Zone January 216 Spot Price $1.37 $3.16 $5.85 $1.55 December 215 Spot Price $1.28 $3.48 $6.29 $1.85 Delta $.9 ($.32) ($.44) ($.3) LHV - Price decreases by $.32 due to increases in generator UCAP available and decrease in unoffered MW NYC - Price decreases by $.44 due to increases in generator UCAP available LI - Price decreases by $.3 due to increases in generator UCAP available 2

4 Reliability Performance Metrics Alert State Declarations 75 5 Occurrences 25 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Voltage Rating (SOL) Exceedance Thermal Rating (SOL) Exceedance Operating Reserve Deficiency Neighboring System in Voltage Reduction Interface Transfer Limit (IROL) Exceedance Frequency Threshold Exceedance Communication Degradation Adverse Operating Conditions ACE Threshold Exceedance The number and causes of Alert State declarations reflect system operating conditions beyond thresholds associated with Normal and Warning States. Declaration of the Alert State allows the NYISO to take corrective actions not available in the Normal and Warning States. Major Emergency State Declarations 1 8 Occurrences Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Voltage Rating (SOL) Exceedance Thermal Rating (SOL) Exceedance Operating Reserve Deficiency Neighboring System in Voltage Reduction Interface Transfer Limit (IROL) Exceedance Frequency Threshold Exceedance Communication Degradation Adverse Operating Conditions ACE Threshold Exceedance The number and causes of Major Emergency State declarations reflect system operating conditions beyond thresholds associated with the Alert State. Declaration of the Major Emergency State allows the NYISO to take additional corrective actions not available in the Alert State. 3

5 NERC IROL Time Over Limit 45 3 Minutes 15 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 IROL Exceedance Time IROL Exceedance Time Limit For IROL exceedances leading to Major Emergency State declarations, the maximum IROL exceedence time is identified. IROL exceedances of less than thirty minutes are considered NERC compliant. NERC Control Performance Standards CPS-1 (%) CPS-2 (%) Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec CPS-1 CPS Limit CPS-2 The values of NERC Control Performance Standards (CPS-1 and CPS-2) are indicators of the NYISO Area resource and demand balancing. Values exceeding the identified thresholds are NERC compliant. 4

6 Reserve Activations 4 3 Occurrences 2 1 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 ACE Not Normal NYCA Loss < 5 MW Simultaneous Activation of Reserve NYCA Loss >= 5 MW NYISO Reserve Activations are indicators of the need to respond to unexpected operational conditions within the NYISO Area or to assist a neighboring Area (Simultaneous Activation of Reserves) by activating an immediate resource and demand balancing operation. DCS Event Time to ACE Recovery Minutes 6 Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 NYISO ACE Recovery Time NERC DCS - ACE Recovery Time Limit For NYISO initiated Reportable Disturbances, the maximum ACE recovery time is identified. Recovery times of less than 15 minutes are considered NERC compliant. 5

7 Load Forecast Performance 2 5% 18 4% 16 3% 14 2% 12 1% MW 1 8 % -1% 6-2% 4-3% 2-4% Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15-5% Average Hourly Error MW Maximum Hourly Error MW Average Hourly Error % Day-Ahead Average Hourly Error % Hourly Error MW - Absolute value of the difference between the hourly average actual load demand and the average hour ahead forecast load demand. Average Hourly Error % - Average value of the ratio of hourly average error magnitude to hourly average actual load demand. Day-Ahead Average Hourly Error % - Average across all hours of the month of the absolute value of the difference between actual load demand and the Day-Ahead forecast load demand, divided by the actual load demand. Wind Forecast Performance Hour Ahead MW Error MW Dec-14 Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Average Hourly Error MW Maximum Hourly Error MW Hourly Error MW - Absolute value of the difference between the hourly average actual wind generation and the average hour ahead forecast wind generation. 6

8 Wind Forecast Performance Hour Ahead Percent Error Wind Capacity 1732MW MAE % Bias % MAE Forecast MAE Persistence Bias MAE Forecast - Avg actual wind generation - hour ahead forecast wind generation / Wind Capacity MAE Persistence - Avg actual wind generation - hour ahead actual wind generation / Wind Capacity Bias - Avg (actual wind generation - hour ahead forecast wind generation) / Wind Capacity 5 Wind Forecast Performance Hour Ahead Mean Absolute Percent Error Ramp Events - Hourly Changes That Exceed 2% (346MW) of Wind Capacity (1732MW) MAE % Date (Qualifying Ramp Intervals) MAE Forecast MAE Persistence MAE Forecast - Avg actual wind generation - hour ahead forecast wind generation / Wind Capacity MAE Persistence - Avg actual wind generation - hour ahead actual wind generation / Wind Capacity 7

9 Wind Forecast Performance Day Ahead Absolute Percent Error Wind Capacity 1732MW MAE % Bias % MAE Forecast Bias MAE Forecast - Avg actual wind generation - Day Ahead forecast wind generation / Wind Capacity Bias - Avg (actual wind generation - Day Ahead forecast wind generation) / Wind Capacity Wind Performance Monthly Production and Economic Curtailments 6, 24, 5, 2, 4, 16, Generated MWh 3, 2, 12, 8, Curtailed MWh 1, 4, Wind Generation Wind Curtailment Curtailment - Difference between Real-Time Wind Forecast and Economic Wind Output Limit 8

10 Lake Erie Circulation and ISO Net Interchange Schedules Monthly Averages ISO Net Interchange Schedule MW Circulation MW NY-IESO Sched MW PJM-NY Sched MW IESO-MISO Sched MW MISO-PJM Sched MW Circulation MW DAM On Peak MW DAM Off Peak MW Interchange schedules with positive values aggravate clockwise Lake Erie Circulation. Lake Erie Circulation and ISO Net Interchange Schedules Daily Averages ISO Net Interchange Schedule MW Circulation MW NY-IESO Sched MW PJM-NY Sched MW IESO-MISO Sched MW MISO-PJM Sched MW Circulation MW DAM On Peak MW DAM Off Peak MW Interchange schedules with positive values aggravate clockwise Lake Erie Circulation. 9

11 Broader Regional Market Performance Metrics $4,5 $4, Ramapo Interconnection Congestion Coordination Monthly Value Categories $3,5 $3, $2,5 $2, $1,5 $1, $5 $ NY RECO December 215 Ramapo Interconnection Congestion Coordination Daily Value Categories $35 $3 $25 $2 $15 $1 $5 $ NY RECO 1

12 Ramapo Interconnection Congestion Coordination Category NY RECO Description Represents the value NY realizes from Market-to-Market Ramapo Coordination. When experiencing congestion, this includes (1) the estimated savings to NY for additional deliveries into NY, plus (2) PJM compensation to NY for additional deliveries into PJM (as compared to the Ramapo Target level, excluding RECO). This is net of any settlements to PJM when they are congested. Represents the value of PJM s obligation to deliver 8% of service to RECO load over Ramapo 518. This includes (1) the estimated reduction in NYCA congestion due to the PJM delivery of RECO over Ramapo 518, plus (2) PJM compensation to NY for NYCA congestion for the under-delivery or inability to deliver service to RECO load over Ramapo

13 $9 $8 Regional Generation Congestion Coordination Monthly Value Categories $7 $6 $5 $4 $3 $2 $1 $ NY $1 December 215 Regional Generation Congestion Coordination Daily Value Categories $ NY 12

14 Regional Generation Congestion Coordination Category NY Description NYISO savings that result from PJM payments to NYISO when PJM s transmission use (PJM s market flow) is greater than PJM s entitlement of the NY transmission system and NYISO is incurring Western or Central NY congestion. Additionally, NYISO savings may result from the more efficient regional utilization of PJM s generation resources to directly address Western or Central NY transmission congestion. 13

15 Regional NYISO/PJM RT Scheduling for All PJM Proxies Monthly Value Categories $3, $2,5 $2, $1,5 $1, $5 $ -$5 Forecasted Regional Value - CTS Forecasted Regional Value - LBMP Forecasted NY Value Realized NY Value Forecasted Regional Value - CTS: Regional production cost savings for NY and PJM associated with intra-hour CTS transaction energy schedules using RTC/ITSCED prices. Forecasted Regional Value - LBMP: Regional production cost savings for NY and PJM associated with intra-hour LBMP transaction energy schedules using RTC/ITSCED prices. Forecasted NY Value: NY production cost savings associated with both CTS and LBMP transaction energy schedules using RTC prices. Realized NY Value: NY production cost savings associated with both CTS and LBMP transaction energy schedules using RTD prices. $7 Regional NYISO/PJM RT Scheduling for All PJM Proxies Daily Value Categories December 215 $6 $5 $4 $3 $2 $1 $ ($1) ($2) Value - CTS Value - LBMP Forecasted NY Value Realized NY Value Forecasted Regional Value - CTS: Regional production cost savings for NY and PJM associated with intra-hour CTS transaction energy schedules using RTC/ITSCED prices. Forecasted Regional Value - LBMP: Regional production cost savings for NY and PJM associated with intra-hour LBMP transaction energy schedules using RTC/ITSCED prices. Forecasted NY Value: NY production cost savings associated with both CTS and LBMP transaction energy schedules using RTC prices. Realized NY Value: NY production cost savings associated with both CTS and LBMP transaction energy schedules using RTD prices. 14

16 Regional NYISO/NE RT Scheduling for ISO-NE AC Monthly Value Categories $8 $6 $4 $2 $ -$2 -$4 -$6 -$8 -$1 -$12 Forecasted Regional Value - CTS Forecasted NY Value Realized NY Value Forecasted Regional Value - CTS: Regional production cost savings for NY and NE associated with intra-hour CTS transaction energy schedules using RTC prices and NE forecasted prices. Forecasted NY Value: NY production cost savings associated with CTS transaction energy schedules using RTC prices. Realized NY Value: NY production cost savings associated with CTS transaction energy schedules using RTD prices. $15 Regional NYISO/NE RT Scheduling for ISO-NE AC Daily Value Categories December 215 $1 $5 $ ($5) ($1) ($15) ($2) ($25) ($3) Forecasted Regional Value - CTS Forecasted NY Value Realized NY Value Forecasted Regional Value - CTS: Regional production cost savings for NY and NE associated with intra-hour CTS transaction energy schedules using RTC prices and NE forecasted prices. Forecasted NY Value: NY production cost savings associated with CTS transaction energy schedules using RTC prices. Realized NY Value: NY production cost savings associated with CTS transaction energy schedules using RTD prices. 15

17 Market Performance Metrics $6, $4, Monthly Statewide Uplift Components and Rate $3. $2. $2, $1. $ $. $/MWh ($2,) ($1.) ($4,) ($2.) ($6,) ($3.) DAM Energy/Loss Residual $ Balancing Energy/Loss Residual $ Balancing Congestion Residual $ DAM BPCG - Statewide $ Balancing BPCG/DAMAP/Guarantee - Statewide $ Statewide Uplift Rate $/MWh 16

18 Balancing Market Congestion Residual Report Monthly Uplift Cost Categories $8, $6, $4, $2, $ ($2,) ($4,) ($6,) ($8,) ($1,) Storm Watch Costs Unscheduled Transmission Outage Interface Derate - NYISO Security Interface Derate - External Security Unscheduled Loop Flows M2M Settlement Cost not categorized Not Investigated December 215 Balancing Market Congestion Residual Report Daily Uplift Cost Categories $2, $1,5 $1, $5 $ ($5) ($1,) Storm Watch Costs Unscheduled Transmission Outage Interface Derate - NYISO Security Interface Derate - External Security Unscheduled Loop Flows M2M Settlement Cost not categorized Not Investigated 17

19 Day's investigated in December:1,14,15,2,28 Event Date (yyyymmdd) Hours Description 3 12/1/215 6 NYCA DNI Ramp Limit 3 12/1/ ,23 Derate Gardenville-Stolle Road 23kV (#66) for l/o TWR:PACKARD 77 & /1/ NE_AC-NY Scheduling Limit 4 12/1/ HQ_CHAT-NY Scheduling Limit 4 12/1/215 17,19 IESO_AC DNI Ramp limit 3 12/14/215,1,5,6,8-1,12-15,17-23 Uprate Central East 3 12/14/ NYCA DNI Ramp Limit 3 12/15/215-8,11-12 Uprate Central East 3 12/2/215 8 Derate Central East 3 12/2/ ,21,22 Derate Dunwoodie-Shore Road 345kV (Y5) for l/o Neptune HVDC Tie Line 3 12/2/ Derate Dunwoodie-Shore Road 345kV (Y5) for SCB:SPBK(RNS2):Y49 & M /2/ Derate Dunwoodie-Shore Road 345kV (Y5) for l/o SPRNBRK_-EGRDNCTR_345_Y /2/ ,21 Derate East Garden City-Valley Stream 138kV for l/o BARRETT 292&459&G2&IC /2/ Derate Gardenville-Stolle Road 23kV (#66) for l/o TWR:PACKARD 77 & /2/ Derate Lafayette-Clarkscorners 345kV for l/o TWR:UCC2-41&EF /2/215 19,22 Derate Meyer-Weathersford 23kV for SCB:ROCH(348): NR-2& RP /2/ Derate Packard-Sawyer 23kV (#78) for l/o Packard-Sawyer 23kV (#77) 3 12/2/215 2,7,9-14,2,23 Uprate Central East 3 12/2/ NYCA DNI Ramp Limit 5 12/2/ ,15 Lake Erie Clockwise Circulation, DAM-RTM exceeds 125MW; Central East 3 12/28/215 11,12 Derate Niagara-Packard 23kV for l/o TWR:PACKARD 62 & BP /28/215 11,12 Derate Packard-Sawyer 23kV (#78) for l/o Packard-Sawyer 23kV (#77) 5 12/28/215 11,12 Lake Erie Clockwise Circulation, DAM-RTM exceeds 125MW; Packard-Sawyer 23kV, Niagara-Packard 23kV Real-Time Balancing Market Congestion Residual (Uplift Cost) Categories Category Cost Assignment Events Types Event Examples Storm Watch Zone J Thunderstorm Alert (TSA) TSA Activations Unscheduled Transmission Outage Market-wide Reduction in DAM to RTM transfers related to unscheduled transmission outage Forced Line Outage, Unit AVR Outages Interface Derate - NYISO Security Market-wide Reduction in DAM to RTM transfers not related to transmission outage Interface Derates due to RTM voltages Interface Derate - External Security Market-wide Reduction in DAM to RTM transfers related to External Control Area Security Events TLR Events, External Transaction Curtailments Unscheduled Loop Flows Market-wide Changes in DAM to RTM unscheduled loop flows impacting NYISO Interface transmission constraints DAM to RTM Clockwise Lake Erie Loop Flows greater than 125 MW M2M Settlement Market-wide Settlement result inclusive of coordinated redispatch and Ramapo flowgates Monthly Balancing Market Congestion Report Assumptions/Notes 1) Storm Watch Costs are identified as daily total uplift costs 2) Days with a value of BMCR less M2M Settlement of $1K/HR, shortfall of $2K/Day or more, or surplus of $1K/Day or more are investigated. 3) Uplift costs associated with multiple event types are apportioned equally by hour 18

20 DAM Congestion Residual Report Monthly Cost Categories ($2,) ($15,) ($1,) ($5,) $ $5, $1, NYTO Outage Allocation Central East Commitment Derate External Outage Allocation Costs Not Categorized October 215 DAM Congestion Residual Report Daily Cost Categories ($2,) ($1,8) ($1,6) ($1,4) ($1,2) ($1,) ($8) ($6) ($4) ($2) $ $2 NYTO Outage Allocation Central East Commitment Derate External Outage Allocation Costs Not Categorized 19

21 Day-Ahead Market Congestion Residual Categories Category Cost Assignment Events Types Event Examples NYTO Outage Allocation Responsible TO Direct allocation to NYTO's responsible for transmission equipment status change. DAM scheduled outage for equipment modeled inservice for the TCC Auction. External Outage Allocation All TO by Monthly Allocation Factor Direct allocation to transmission equipment status change caused by change in status of external equipment. Tie line required out-ofservice by TO of neighboring control area. Central East Commitment Derate All TO by Monthly Allocation Factor Reductions in the DAM Central East_VC limit as compared to the TCC Auction limit, which are not associated with transmission line outages. 2

22 Monthly Power Supplier Uplift Components $12, $1, $8, $6, $4, $2, $ DAM BPCG State-wide RT BPCG State-wide DAMAP State-wide Import DAM BPCG State-wide Import RT GP State-wide DAM BPCG Local Reliability RT BPCG Local Reliability DAMAP Local Reliability MOB $25 $2 December 215 Daily Power Supplier Uplift Components $15 $1 $5 $ DAM BPCG State-wide RT BPCG State-wide DAMAP State-wide Import DAM BPCG State-wide Import RT GP State-wide DAM BPCG Local Reliability RT BPCG Local Reliability DAMAP Local Reliability MOB 21

23 $4,5 $4, Local Reliability Cost Monthly RT BPCG, DAM BPCG, DAMAP & Minimum Oil Burn Costs $3,5 $3, $2,5 $2, $1,5 $1, $5 $ CON ED NY CITY LIPA LONG ISLAND 2 December 215 Local Reliability Commitment Hours Monthly DARU & SRE Hours CON ED NY CITY LIPA LONG ISLAND ASTORIA 5 NORTHPORT 3 PORT_JEFF_4 BARRETT 2 CAITHNESS_CC_1 ARTHUR_KILL_2 22

24 $3,5 $3, Local Reliability Cost Monthly RT BPCG, DAM BPCG & DAMAP Costs $2,5 $2, $1,5 $1, $5 $ NMPC WEST NYSEG CENTRAL O&R HUDSON VLY NMPC GENESEE NMPC CAPITAL NMPC MOHAWK VLY NMPC CENTRAL NYSEG NORTH RG&E GENESEE CENT HUD HUDSON VLY NYSEG CAPITAL NMPC NORTH 7 December 215 Local Reliability Commitment Hours Monthly DARU & SRE Hours NMPC WEST O&R HUDSON VLY NMPC CENTRAL DUNKIRK 2 - ARR-74 MONGAUP HYD - ARR- INDECK OSWEGO - ARR-76 23

25 $35 TCC & Day Ahead Market Selected Internal Path Congestion TCC Monthly Reconfiguration Auction vs. Monthly DAM Average with Autumn 215 Centralized TCC Auction Six-Month Average $3 $25 $2 $/MW-Hour $15 $1 $5 $ ($5) West-Dunwoodie TCC Auction Dunwoodie-LI TCC Auction Dunwoodie-NYC TCC Auction West-Dunwoodie DAM Congestion Dunwoodie-LI DAM Congestion Dunwoodie-NYC DAM Congestion TCC & Day Ahead Market West to Dunwoodie Path Congestion TCC Monthly Reconfiguration Auction vs. Monthly DAM Average with Autumn 215 Centralized TCC Auction Six-Month Average $45 $35 $/MW-Hour $25 $15 $5 ($5) ($15) West-Central TCC Auction Central-Capital TCC Auction Capital-Hud VL TCC Auction Hud VL-Dunwoodie TCC Auction West-Central DAM Congestion Central-Capital DAM Congestion Capital-Hud VL DAM Congestion Hud VL-Dunwoodie DAM Congestion 24

26 TCC & Day Ahead Market Selected External Path Congestion TCC Monthly Reconfiguration Auction vs. Monthly DAM Average with Autumn 215 Centralized TCC Auction Six-Month Average $5 ($5) $/MW-Hour ($15) ($25) ($35) ($45) PJM-Central TCC Auction NE-Central TCC Auction OH-Central TCC Auction HQ-Central TCC Auction PJM-Central DAM Congestion NE-Central DAM Congestion OH-Central DAM Congestion HQ-Central DAM Congestion 25

27 ICAP Spot Market Clearing Price $/kw-month Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 LI NYC GHIJ NYCA UCAP Sales Capacity (GW) Jan-15 Feb-15 Mar-15 Apr-15 May-15 Jun-15 Jul-15 Aug-15 Sep-15 Oct-15 Nov-15 Dec-15 Jan-16 ROS - Gens Sold ROS - Externals ROS - Exports ROS - SCR Sold NYC - Gen Sold NYC - SCR Sold LI - Gen Sold LI - SCR Sold GHI - Gen Sold GHI - SCR Sold LI - Gen Unsold LI - SCR Unsold NYC - Gen Unsold NYC - SCR Unsold ROS - Gen Unsold ROS - SCR Unsold GHI - Gen Unsold GHI - SCR Unsold 26