Market Performance Report May 2014 June 30, 2014 ISO Market Quality and Renewable Integration CAISO 250 Outcropping Way Folsom, California 95630 (916) 351-4400
Executive Summary 1 The market performance in May 2014 is summarized as follows. Fifteen-minute market (FMM) started on May 1, 2014. The peak load exceeded 35,000 MW for a few days in the middle of this month driven by high temperature. In the day-ahead market, there were a few price spikes due to transmission congestion. In the FMM market, VEA prices were low on two days due to transmission congestion. In the RTD market, the DLAP prices dropped on May 23 due to over generation. Total congestion rent for interties in May decreased to $29.42 million from $54.36 million in April. Most of the congestion rents accrued on PACI (46 percent) and NOB (38 percent) interties. The congestion revenue rights market experienced revenue deficit, with revenue adequacy level at 93.16 percent. The monthly average ancillary service cost to load inched up to $0.33/MWh in May from $0.28/MWh in April. There were no scarcity events in May. The cleared virtual demand was below virtual supply in most days of May. The profits from convergence bidding decreased to $0.83 million in May from $4.52 million in April. Total bid cost recovery payment in May rose to $9.72 million from $8.97 million in April. Real-time energy offset cost dropped to $7.13 million in May from $14.94 million in April. Real-time congestion offset cost declined to $7.81 million in May from $20.81 million in April. Total volume of exceptional dispatch in May increased to 169,152 MWh from 38,394 MWh in April. The monthly average of total exceptional dispatch volume (MWh) as a percentage of load increased to 0.86 percent in May from 0.23 percent in April. 1 This report contains the highlights of the reporting period. For a more detailed explanation of the technical characteristics of the metrics included in this report please download the Market Performance Metric Catalog, which is available on the CAISO web site at http://www.caiso.com/market/pages/reportsbulletins/default.aspx. Market Performance Report Page 2 of 24
TABLE OF CONTENTS Executive Summary... 2 Market Characteristics... 4 Loads... 4 Direct Market Performance Metrics... 5 Energy... 5 Day-Ahead Prices... 5 Real-Time Prices... 5 Congestion Rents on Interties... 8 Congestion Rents on Branch Groups and Market Scheduling Limits... 8 Congestion Revenue Rights... 10 Ancillary Services... 13 IFM (Day-Ahead) Average Price... 13 Ancillary Service Cost to Load... 14 Scarcity Events... 14 Convergence Bidding... 15 Indirect Market Performance Metrics... 17 Bid Cost Recovery... 17 Real-time Imbalance Offset Costs... 20 Market Software Metrics... 21 Market Disruption... 21 Manual Market Adjustment... 23 Exceptional Dispatch... 23 Market Performance Report Page 3 of 24
1 1 1 2 2 2 1 1 2 2 2 MW Market Characteristics Loads The peak load exceeded 35,000 MW for a few days in the middle of this month driven by high temperature. Figure 1: System Peak Load 45,000 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 Market Performance Report Page 4 of 24
1 1 1 2 2 2 1 1 2 2 2 $/MWh Direct Market Performance Metrics Energy Day-Ahead Prices Figure 2 shows daily prices of four DLAPs. The binding constraints along with the associated DLAP locations and the occurrence dates are listed in Table 1. Figure 2: Day-Ahead Simple Average LAP Prices (All Hours) 80 70 60 50 40 30 20 10 0 PGE SCE SDGE VEA Table 1: Day-Ahead Transmission Constraints DLAP Date Transmission Constraint SDG&E May 14-16 7820_TL 230S_OVERLOAD_NG VEA May 15 T-135 VICTVLUGO_DVRB_NG. VEA May 23 SLIC 2237207 TL50002 DVRB Real-Time Prices Fifteen minute market (FMM) started on May 1, 2014. The energy prices in FMM were also used for settlement. Daily prices of the four DLAPs in FMM are shown in Figure 3. The binding constraint along with the associated DLAP locations and the occurrence dates are listed in Table 3. Market Performance Report Page 5 of 24
1 1 1 2 2 2 1 1 2 2 2 $/MWh 1 1 2 2 2 $/MWh Figure 3: FMM Simple Average LAP Prices (All Hours) 80 70 60 50 40 30 20 10 0 PGE SCE SDGE VEA Table 2: FMM Transmission Constraints DLAP Date Transmission Constraint SDG&E May 14 7820_TL230S_OVERLOAD_NG. VEA May 23 SLIC 2237207 TL50002 DVRB VEA May 29 SLIC 2249785 ELDORADO-LUGO_1_NG Daily prices of the four DLAPs in RTD are shown in Figure 4. May 23 saw low prices for all four DLAPs due to over generation, which was driven by load forecast reduction and wind deviation. The binding constraint along with the associated DLAP locations and the occurrence dates are listed in Table 3. 120 100 80 Figure 4: RTD Simple Average LAP Prices (All Hours) 60 40 20 0 PGE SCE SDGE VEA Market Performance Report Page 6 of 24
1 1 1 2 2 2 1 1 2 2 2 Frequency Table 3: RTD Transmission Constraints DLAP Date Transmission Constraint PG&E May 10 PATH15_S-N VEA May 29 SLIC 2249785 ELDORADO-LUGO_1_NG. Figure 5 below shows the daily frequency of positive price spikes and negative prices by price range for the default LAPs in the five-minute real-time market. The cumulative frequency of prices above $250/MWh was 7.44 percent in May, increasing from 6.28 percent in April. High frequency of negative prices occurred on May 23 due to over generation driven by wind deviation and load forecast reduction. Figure 5: Daily Frequency of RTD LAP Positive Price Spikes and Negative Price 10.0% 5.0% 0.0% -5.0% -10.0% -15.0% -20.0% -25.0% -30.0% -35.0% <=-$250 $(-100, -250] $(-40,-100] $(-20,-40] $(0,-20] $[250,500) $[500,750) $[750,1000) $[1000,3000] Market Performance Report Page 7 of 24
1 1 1 2 2 2 1 1 2 2 2 Thousands Congestion Congestion Rents on Interties Figure 6 below illustrates daily integrated forward market congestion rents by interties. The cumulative total congestion rent for interties in May decreased to $29.42 million from $54.36 million in April. Most of the congestion rents in May accrued on PACI (46 percent) and NOB (38 percent) interties. Total congestion rent on PACI declined to $13.64 million in May from $33.25 million in April. PACI intertie was derated in May due to various outages including the outages of John Day-Grizzly #2 500 kv line, Grizzly-Malin #2 500 kv line, Captain Jack-Olinda 500 kv line, and Gates-Midway 500 kv line. The congestion rent on NOB decreased to $11.30 million in May from $12.01 million in April. NOB was derated in May due to various outages including the outages of Tesla-Tracy 500 kv line, Round Mountain-Cottonwood #1 230 kv line, Captain Jack-Olinda 500 kv line, and Gates-Midway 500 kv line. $3,500 $3,000 $2,500 $2,000 $1,500 $1,000 $500 $0 Figure 6: IFM Congestion Rents by Interties (Import) NOB_ITC PACI_ITC TRACY500_ITC CASCADE_ITC PALOVRDE_ITC IID-SCE_ITC ADLANTO-SP_ITC MEAD_ITC Congestion Rents on Branch Groups and Market Scheduling Limits Figure 6 illustrates congestion rents on selected branch groups and market scheduling limits in the integrated forward market. Total congestion rents for branch groups and market scheduling limits decreased to $1.72 million in May from $4.37 million in April. Most of the congestion rents in May accrued on SOUTHLUGO_RV_BG (6 percent) and PATH15_BG (87 percent). The congestion rent on PATH15_BG dropped to $1.49 million in May from $2.94 million in April. Market Performance Report Page 8 of 24
1 1 1 2 2 2 1 1 2 2 2 Congestion Cost ($/MWh) 1-Apr 1 1 1 2 2 2 1 1 2 2 2 Thousands Figure 7: IFM Congestion Rents by Branch Groups and Market Scheduling Limits $700 $600 $500 $400 $300 $200 $100 $0 IPPDCADLN_BG IPPUTAH_MSL PATH15_BG SYLMAR_SIM_MSL MKTPCADLN_MSL LOSBANOSNORTH_BG SDGE_CFEIMP_BG Average Congestion Cost per Load Served This metric quantifies the average congestion cost for serving one megawatt of load in the ISO system. Figure 7 shows the daily and monthly averages for the day-ahead and real-time markets respectively. Figure 8: Average Congestion Cost per Megawatt of Served Load 8.0 6.0 4.0 2.0 0.0-2.0-4.0-6.0 Day Ahead Real Time Day-Ahead Average Real-Time Average The average congestion cost per MWh of load served in the integrated forward market rose to $2.91/MWh in May from $3.72/MWh in April. The average congestion cost per load served in the real-time market went to -$0.40/MWh in May from -$1.18/MWh in April. Market Performance Report Page 9 of 24
1 1 2 2 2 Revenue Adequacy (Millions) Congestion Revenue Rights Figure 8 illustrates the daily revenue adequacy for congestion revenue rights (CRRs) broken out by transmission element. The average CRR revenue deficit in May was $133,170, decreasing from the average revenue deficit of $982,634 in April. Figure 9: Daily Revenue Adequacy of Congestion Revenue Rights $2.50 $2.00 $1.50 $1.00 $0.50 $0.00 -$0.50 -$1.00 -$1.50 24086_LUGO _500_26105_VICTORV 33020_MORAGA _115_30550_MORAGA OTHER SLIC 2206489_PVCR_Out_EDLG 30875_MC CALL _230_30880_HENTAP2 SLIC 2237207 TL50002 DVRB SLIC 2348190 PITTSBURG PP SOL-1 SLIC 2249785 ELDORADO-LUGO_1_NG 24016_BARRE _230_25201_LEWIS PATH15_BG Overall, May experienced CRR revenue deficit. Revenue shortfalls were observed in 21 days of this month. A line (33020_MORAGA_115_30550_MORAGA) was binding for sixteen days, resulting in revenue shortfall of $1.19 million.. A line (24086_LUGO _500_26105_VICTORV) was binding for twenty one days, resulting in revenue shortfall of $0.69 million. Market Performance Report Page 10 of 24
The shares of the revenue surplus and deficit accruing on various congested transmission elements for the reporting period are shown in Figure 10 and the monthly summary for CRR revenue adequacy is provided in Table 4. Figure 10: CRR Revenue Adequacy by Transmission Element 24086_LUGO _500_26105_VIC TORVL_500_BR_1 _1 8% SLIC 2249785 ELDORADO- LUGO_1_NG 9% 24016_BARRE _230_25201_LEW IS _230_BR_1 _1 6% OTHER 41% PATH15_BG 11% SLIC 2237207 TL50002 DVRB 11% 33020_MORAGA _115_30550_MO RAGA _230_XF_1 _P 14% Revenue Shortfal, $8.21 Million 34116_LE GRAND_115_34134 _WILSONAB_115_B 30880_HENTAP2 R_1 _1 _230_30900_GATES 6% _230_BR_2 _1 10% OTHER 5% 30900_GATES _230_30970_MIDW AY _230_BR_1 _1 3% 6110_TM_BNK_FLO _TMS_DLO_NG 3% 30875_MC CALL _230_30880_HENTA P2 _230_BR_1 _1 16% SLIC 2348190 PITTSBURG PP SOL- 1 57% Revenue Surplus, $3.91 Million Market Performance Report Page 11 of 24
Overall, the total amount collected from the integrated forward market was not sufficient to cover the net payments to congestion revenue right holders and the cost of the exemption for existing rights. Out of the total congestion rents, 6.40 percent was used to cover the cost of exemptions for existing rights. The net total congestion revenues in May were in deficit by $4.13 million, in comparison to the deficit of $29.48 million in April. The auction revenues credited to the balancing account for May were $7.96 million. The balancing account for May had a surplus of approximately $4.91 million, which will be allocated to measured demand. Table 4: CRR Revenue Adequacy Statistics IFM Congestion Rents $60,114,780.17 Existing Right Exemptions -$3,849,362.48 Available Congestion Revenues $56,265,417.69 CRR Payments $60,393,696.96 CRR Revenue Adequacy -$4,128,279.26 Revenue Adequacy Ratio 93.16% Annual Auction Revenues $3,637,380.36 Monthly Auction Revenues $4,323,431.47 CRR Settlement Rule $1,072,640.59 Allocation to Measured Demand $4,905,173.15 Market Performance Report Page 12 of 24
1 1 1 2 2 2 1 1 2 2 2 $/MW Ancillary Services IFM (Day-Ahead) Average Price Table 5 shows the monthly IFM average ancillary service procurements and the monthly average prices. In May the monthly average procurement increased for all four types of ancillary services. Table 5: IFM (Day-Ahead) Monthly Average Ancillary Service Procurement Average Procurred Average Price Reg Up Reg Dn Spinning Non-Spinning Reg Up Reg Dn Spinning Non-Spinning May-14 349 329 851 852 $7.88 $4.91 $4.35 $0.19 Apr-14 339 320 769 769 $6.22 $4.57 $3.14 $0.09 Percent Change 3.15% 2.64% 10.67% 10.78% 26.74% 7.43% 38.66% 96.97% The monthly average prices increased for all four types of ancillary services in May. Figure 11 shows the daily IFM average ancillary service prices. The regulations up average prices were relatively high in the first half of May. 16 14 12 10 8 6 4 2 0 Figure 11: IFM (Day-Ahead) Ancillary Service Average Price Non-Spinning Regulation Down Regulation Up Spinning Market Performance Report Page 13 of 24
1 1 1 2 2 2 1 1 2 2 2 $/MWh Ancillary Service Cost to Load The monthly average cost to load inched up to $0.33/MWh in May from $0.28/MWh in April. Figure 12: System (Day-Ahead and Real-Time) Average Cost to Load $0.70 $0.60 $0.50 $0.40 $0.30 $0.20 $0.10 $0.00 Spinning Non-Spinning Regulation Down Regulation Up Monthly Average Scarcity Events Reserve scarcity pricing is a mechanism that will allow prices for reserves and energy to rise automatically when there is inadequate supply in the market to meet the minimum procurement requirements of reserves and regulation on the ISO grid. The ancillary services scarcity pricing mechanism is triggered when the California ISO is not able to procure the target quantity of one or more ancillary services in the IFM and real-time market runs. There were no scarcity events in May. Market Performance Report Page 14 of 24
1 1 1 2 2 2 1 1 2 2 2 $/MWh 1-Apr 1 1 1 2 2 2 1 1 2 2 2 MW Convergence Bidding Figure 13 below shows the daily average volume of cleared virtual bids in IFM for virtual supply and virtual demand. The cleared virtual supply was well above the virtual demand since May 16. 3000 2500 Figure 13: Cleared Virtual Bids 2000 1500 1000 500 0 Virtual Demand Virtual Supply Convergence bidding tends to cause the day-ahead market and real-time market prices to move closer together, or converge. Figure 14 shows the energy prices (namely the energy component of the LMP) in IFM, HASP, FMM, and RTD. 120 100 80 60 40 20 0-20 Figure 14: IFM, HASP, FMM, and RTD Prices IFM HASP FMM RTD Market Performance Report Page 15 of 24
1 1 1 2 2 2 1 1 2 2 2 Profit (Thousands) Figure 15 shows the profits that convergence bidders receive from convergence bidding. The daily profit is the sum of three settlement charge codes (CC6013, CC6053, and CC6473). The total profits from convergence bidding decreased to $0.83 million in May from $4.52 million in April. $2,500 $2,000 Figure 15: Convergence Bidding Profits $1,500 $1,000 $500 $0 -$500 Market Performance Report Page 16 of 24
1 1 1 2 2 2 1 1 2 2 2 Millions Indirect Market Performance Metrics Bid Cost Recovery Figure 16 shows the daily uplift costs due to exceptional dispatch payments (charge codes CC6488, CC6482, and CC6470). The monthly uplift costs in May increased to $1.16 million from $0.25 million in April, driven by increased exceptional dispatch in May $0.14 $0.12 $0.10 $0.08 $0.06 $0.04 $0.02 $0.00 -$0.02 Figure 16: Exceptional Dispatch Uplift Costs Figure 17 shows the allocation of bid cost recovery payment in the IFM, RUC and RTM markets. The total bid cost recovery for May increased to $9.72 million from $8.97 million in April. Out of the total monthly bid cost recovery payment for the three markets in May, the IFM market contributed 18 percent, RTM contributed 74 percent and RUC contributed 8 percent of the total bid cost recovery payment. Market Performance Report Page 17 of 24
1 1 1 2 2 2 1 1 2 2 2 1-Apr 1 1 1 2 2 2 1 1 2 2 2 Millions $1.40 $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 ($0.20) Figure 17: Bid Cost Recovery Allocation IFM RUC RTM Figure 18 shows the bid cost recovery allocation in RUC. The RUC cost in May was mostly driven by minimum load cost. The monthly average BCR allocation in May increased to $32,747, increasing from $20,794 in April. $400,000 $350,000 $300,000 $250,000 $200,000 $150,000 $100,000 $50,000 $0 -$50,000 Figure 18: Bid Cost Recovery Allocation in RUC RUC_MLC RUC_CAP_COST RUC_SUC Market Performance Report Page 18 of 24
1 1 1 2 2 2 1 1 2 2 2 Millions 1-Apr 1 1 1 2 2 2 1 1 2 2 2 Millions Figure 19 shows the bid cost recovery allocation in RTD. The minimum load cost and energy cost contributed largely to the BCR in May. The monthly average BCR allocation in May was approximately $217,348, higher than $178,189 in April. $3.0 $2.5 $2.0 $1.5 Figure 19: Bid Cost Recovery Allocation in RTD $1.0 $0.5 $0.0 -$0.5 -$1.0 RT_AS_COST RT_ENERGY RT_MLC RT_SUC RT_TRANSITION_COST RT_PUMP_COST Figure 20 shows the bid cost recovery allocation in IFM. The monthly average BCR allocation in May declined to $53,651 from $99,147 in April. The Minimum Load Cost and energy cost contributed largely to the BCR in IFM in May. $3.0 $2.5 $2.0 Figure 20: Bid Cost Recovery Allocation in IFM $1.5 $1.0 $0.5 $0.0 -$0.5 IFM_AS_BID_COST IFM_ENERGY IFM_MLC IFM_SUC IFM_TRANSITION_COST IFM_PUMP_COST Market Performance Report Page 19 of 24
1 1 1 2 2 2 1 1 2 2 2 $Millions Real-time Imbalance Offset Costs Figure 21 shows the daily real-time energy and congestion imbalance offset costs. Real-time energy offset cost dropped to $7.13 million in May from $14.94 million in April. Real-time congestion offset cost declined to $7.81 million in May from $20.81 million in April. The sum of energy and congestion offset costs decreased by approximately 60 percent in May compared with April. 6 5 4 Figure 21: Real-Time Energy and Congestion Imbalance Offset 3 2 1 0-1 RT_ENGY_OFFSET RT_CONG_OFFSET Market Performance Report Page 20 of 24
Market Software Metrics Market performance can be confounded by software issues, which vary in severity levels with the failure of a market run being the most severe. Market Disruption A market disruption is an action or event that causes a failure of an ISO market, related to system operation issues or system emergencies. 2 Pursuant to section 7.7.15 of the ISO tariff, the ISO can take one or more of a number of specified actions in the event of a market disruption, to prevent a market disruption, or to minimize the extent of a market disruption. Table 6 lists the number of market disruptions and the number of times that the ISO removed bids (including self-schedules) in any of the following markets in May. The ISO markets include IFM, RUC, fifteen-minute market (FMM) and RTD processes. Figure 22 shows the frequency of IFM, HASP (FMM interval 2), FMM (intervals 1, 3 and 4), and RTD failures. There were a total of 111 market disruptions in May. Type of CAISO Market Table 6: Summary of Market Disruption Market Disruption or Reportable Events Removal of Bids (including Self-Schedules) Day-Ahead IFM 0 0 RUC 0 0 Real-Time FMM Interval 1 6 0 FMM Interval 2 6 0 FMM Interval 3 7 0 FMM Interval 4 5 0 Real-Time Dispatch 87 0 On May 1, 30 RTD, ten FMM, and four HASP disruptions occurred due to Spring release. There were one FMM and four RTD disruptions on the same day due to application problem. 2 These system operation issues or system emergencies are referred to in Sections 7.6 and 7.7, respectively, of the ISO tariff. Market Performance Report Page 21 of 24
1 1 2 2 2 Figure 22: Frequency of Market Disruption 60 50 40 30 20 10 0 HASP FMM RTD Market Performance Report Page 22 of 24
1 1 1 2 2 2 1 1 2 2 2 Thousands MWh Per Day Manual Market Adjustment Exceptional Dispatch Figure 23 shows the daily volume of exceptional dispatches, broken out by market type: day-ahead, real-time incremental dispatch and real-time decremental dispatch. Generally, all day-ahead exceptional dispatches are unit commitments at the resource physical minimum. The real-time exceptional dispatches are among one of the following types: i) a unit commitment at physical minimum, ii) an incremental dispatch above the day-ahead schedule, and iii) a decremental dispatch below the day-ahead schedule. The total volume of exceptional dispatch in May increased to 169,152 MWh from 38,394 MWh in April. Figure 23: Total Exceptional Dispatch Volume (MWh) by Market Type 20 15 10 5 0-5 -10 Day-Ahead Real-Time INC Real-Time DEC Figure 24 shows the volume of the exceptional dispatch broken out by reason. 3 The majority of the exceptional dispatch volumes in May were driven by planned transmission outage and constraint (40 percent), incomplete or inaccurate transmission (14 percent), load forecast uncertainty (15 percent), and conditions beyond the control of the CAISO (7 percent). 3 For details regarding the reason of exceptional dispatch please read the white paper on exceptional dispatch published on the ISO website: http://www.caiso.com/1c89/1c89d76950e00.html. For the description of the operating procedure, please read the operating procedures index list at http://www.caiso.com/documents/operatingprocedureindex.pdf. Market Performance Report Page 23 of 24
1 1 1 2 2 2 1 1 2 2 2 1-Apr 1 1 1 2 2 2 1 1 2 2 2 Thousands MWh Per Day 20 18 16 14 12 10 8 6 4 2 0 Figure 24: Total Exceptional Dispatch Volume (MWh) by Reason Load Forecast Uncertainty Unit Testing Conditions beyond the control of the CAISO Software Limitation Other Load Pull Planned Transmission Outage and Constraint Other Reliability Requirement Incomplete or Inaccurate Transmission Figure 25 shows the total exceptional dispatch volume as a percent of load, along with the monthly average. The monthly average percentage increased to 0.86 percent in May from 0.23 percent in April. 3.00% 2.50% 2.00% 1.50% 1.00% 0.50% 0.00% Figure 25: Total Exceptional Dispatch as Percent of Load Percent Monthly Average Market Performance Report Page 24 of 24