Market Performance Report January 2014

Transcription

1 Market Performance Report January 2014 February 25, 2014 ISO Market Quality and Renewable Integration CAISO 250 Outcropping Way Folsom, California (916)

2 Executive Summary 1 The market performance in January 2014 is summarized as follows. The peak loads were generally low due to warmer weather. In the day-ahead market, the DLAP prices were generally stable. In the real-time market, VEA price was depressed on January 22 due to transmission congestion. Total congestion rent for interties in January continued to decrease to $4.96 million from $5.31 million in December. Most of the congestion rents accrued on NOB (14 percent) and Palo Verde (71 percent) interties. The congestion revenue rights market experienced revenue deficit, with revenue adequacy level at percent. The monthly average ancillary service cost to load dropped to $0.19/MWh in January from $0.27/MWh in December. There was no scarcity event in January. The cleared virtual demand and supply were generally lower than December level. The profits from convergence bidding decreased to $0.07 million in January from $6.24 million in December. Total bid cost recovery payment in January declined to $6.27 million from $8.71 million in December. Total volume of exceptional dispatch in January dropped to 6,957 MWh from 105,558 MWh in December. The monthly average of total exceptional dispatch volume (MWh) as a percentage of load fell to 0.04 percent in January from 0.53 percent in December. 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 Market Performance Report Page 2 of 22

3 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... 7 Congestion Rents on Interties... 7 Congestion Rents on Branch Groups and Market Scheduling Limits... 7 Congestion Revenue Rights... 9 Ancillary Services IFM (Day-Ahead) Average Price Ancillary Service Cost to Load Scarcity Events Convergence Bidding Indirect Market Performance Metrics Bid Cost Recovery Market Software Metrics Market Disruption Manual Market Adjustment Exceptional Dispatch Market Performance Report Page 3 of 22

4 MW Market Characteristics Loads The peak loads in January were generally low, seldom exceeding 30,000 MW due to warmer weather. 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 Figure 1: System Peak Load Market Performance Report Page 4 of 22

5 $/MWh Direct Market Performance Metrics Energy Day-Ahead Prices Figure 2 shows daily prices of four DLAPs. Day-ahead prices were generally stable. The binding constraint 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) PGE SCE SDGE VEA Table 1: Day-Ahead Transmission Constraints DLAP Date Transmission Constraint VEA January 24 SLIC NGila-HWD PVDV Real-Time Prices Daily prices of the four DLAPs are shown in Figure 3. VEA price was depressed on January 24 due to transmission congestion. The binding constraint along with the associated DLAP locations and the occurrence dates are listed in Table 2. Market Performance Report Page 5 of 22

6 Frequency 1-Dec $/MWh Figure 3: RTD Simple Average LAP Prices (All Hours) PGE SCE SDGE VEA Table 2: Real-Time Transmission Constraints DLAP Date Transmission Constraint VEA January 22 SLIC NGila-HWD PVDV Figure 4 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 1.11 percent in January, decreasing from 1.65 percent in December. On January 9, the frequency of negative prices was above 10 percent driven by over generation in early morning. Figure 4: Daily Frequency of RTD LAP Positive Price Spikes and Negative Price 6.0% 4.0% 2.0% 0.0% -2.0% -4.0% -6.0% -8.0% -10.0% -12.0% <=-$250 $(-100, -250] $(-40,-100] $(-20,-40] $(0,-20] $[250,500) $[500,750) $[750,1000) $[1000,3000] Market Performance Report Page 6 of 22

7 Thousands Congestion Congestion Rents on Interties Figure 5 below illustrates daily integrated forward market congestion rents by interties. The cumulative total congestion rent for interties in January continued to decrease to $4.96 million from $5.31 million in December. Most of the congestion rents in January accrued on NOB (14 percent) and Palo Verde (71 percent) interties. Total congestion rent on Palo Verde decreased to $3.51 million in January from $4.82 million in December. Palo Verde intertie was derated in most days of January due to the outages of North Gila-Hoodoo Wash 500 kv line, Crystal- McCullough 500 kv Line, North Gila-Hoodoo Wash 500 kv series capacitor, Devers-Red Bluff 500 kv series capacitor, and Liberty phase shifter. Figure 5: IFM Congestion Rents by Interties (Import) $800 $700 $600 $500 $400 $300 $200 $100 $0 NOB_ITC PALOVRDE_ITC COTPISO_ITC MEAD_ITC PACI_ITC VEA_ITC TRACY500_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 $0.74 million in January from $1.14 million in December. Most of the congestion rents in January accrued on SUTTEROBANION_BG (46 percent), MKTPCADLN_MSL (23 percent), and IPPUTAH_MSL (22 percent). The congestion rent on SUTTEROBANION_BG rose to $0.34 million in January from $0.01 million in December. Market Performance Report Page 7 of 22

8 Congestion Cost ($/MWh) 1-Dec Thousands Figure 6: IFM Congestion Rents by Branch Groups and Market Scheduling Limits $800 $700 $600 $500 $400 $300 $200 $100 $0 PATH15_BG SOUTHLUGO_RV_BG IPPUTAH_MSL SUTTEROBANION_BG MKTPCADLN_MSL WSTWGMEAD_MSL PATH26_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 7: Average Congestion Cost per Megawatt of Served Load Day Ahead Real Time Day-Ahead Average Real-Time Average The average congestion cost per MWh of load served in the integrated forward market edged down to $0.61/MWh in January from $0.69/MWh in December. The average congestion cost per load served in the real-time market went to -$0.10/MWh in January from -$0.64/MWh in December. Market Performance Report Page 8 of 22

9 1-Jan 3-Jan 5-Jan 7-Jan 9-Jan 11-Jan 13-Jan 15-Jan 17-Jan 19-Jan 21-Jan 23-Jan 25-Jan 27-Jan 29-Jan 31-Jan 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 January was $286,335, increasing from the average revenue deficit of 254,351 in December. Figure 8: Daily Revenue Adequacy of Congestion Revenue Rights $0.20 $0.00 -$0.20 -$0.40 -$0.60 -$0.80 -$1.00 -$1.20 OTHER 30880_HENTAP2 _230_30900_GATES 24087_MAGUNDEN_230_24153_VESTAL HUMBOLDT_IMP_NG 22192_DOUBLTTP_138_22300_FRIARS SLIC LUG0-MIRA LOMA 3 SLIC NGila-HWD PVDV NdGrp: 18624_COPPERMT_34.5_B _SYCAMORE_138_22117_CARLTHT 34540_HENRITTA_70.0_30881_HENRIE Overall, January 2012 experienced CRR revenue deficit. Revenue shortfalls were observed in 28 days this month. A nomogram (SLIC NGila-HWD PVDV) was binding for 4 days, resulting in revenue shortfall of $1.20 million. This nomogram was enforced for the outage of North Gila-Hoodoo Wash 500 kv line. A line (30880_HENTAP2 _230_30900_GATES) was binding for approximately 20 days, resulting in revenue shortfall of $4.76 million. A nomogram (SLIC LUG0-MIRA LOMA 3) was binding for approximately 15 days, resulting in revenue shortfall of $1.34 million. This nomogram was enforced for the outage of LUGO-MIRA LOMA #3 line. Market Performance Report Page 9 of 22

10 The shares of the revenue surplus and deficit accruing on various congested transmission elements for the reporting period are shown in Figure 9 and the monthly summary for CRR revenue adequacy is provided in Table 3. Figure 9: CRR Revenue Adequacy by Transmission Element 22192_DOUBLTTP 22831_SYCAMOR 34540_HENRITTA _138_22300_FRI E_138_22117_CA _70.0_30881_HE ARS _138_BR_1 RLTHT2_138_BR_ NRIETA_230_XF 1 1 _1 4 3% 2% 5% OTHER 7% SLIC NGila-HWD PVDV 14% 30880_HENTAP2 _230_30900_GAT ES _230_BR_2 _1 54% SLIC LUG0-MIRA LOMA 3 15% Revenue Shortfall, $8.71 Million SUTTEROBANION_B G 6% MKTPCADLN_MSL 2% IPPUTAH_MSL 24804_DEVERS _230_24806_MIRA 6% GE _230_BR_2 _1 8% OTHER 5% 25406_J.HINDS _230_24806_MIRA GE _230_BR_1 _1 19% SLIC MIDWAY SOL1 54% Revenue Surplus, $0.16 Million Market Performance Report Page 10 of 22

11 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, 3.00 percent was used to cover the cost of exemptions for existing rights. The net total congestion revenues in January were in deficit by $8.88 million, in comparison to the deficit of $7.88 million in December. The auction revenues credited to the balancing account for January were $5.85 million. The balancing account for January had a net deficit of approximately $2.94 million, which will be allocated to measured demand. Table 3: CRR Revenue Adequacy Statistics Concept Amount IFM Congestion Rents $11,294, Existing Right Exemptions -$338, Available Congestion Revenues $10,956, CRR Payments $19,832, CRR Revenue Adequacy -$8,876, Revenue Adequacy Ratio 55.24% Annual Auction Revenues $2,547, Monthly Auction Revenues $3,299, CRR Settlement Rule $91, Allocation to Measured Demand -$2,938, Market Performance Report Page 11 of 22

12 $/MW Ancillary Services IFM (Day-Ahead) Average Price Table 4 shows the monthly IFM average ancillary service procurements and the monthly average prices. In January the monthly average procurement increased for regulation up, spinning, and non-spinning reserve Table 4: 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 Jan $4.81 $3.26 $1.89 $0.09 Dec $6.07 $3.75 $2.53 $0.20 Percent Change 2.02% -0.18% 4.08% 3.11% % % % % The monthly average prices declined for all four types of ancillary services in January. Figure 10 shows the daily IFM average ancillary service prices. The regulations up average prices were relatively high on January 6, 7, and 27 due to high opportunity cost of energy Figure 10: IFM (Day-Ahead) Ancillary Service Average Price Non-Spinning Regulation Down Regulation Up Spinning Market Performance Report Page 12 of 22

13 $/MWh Ancillary Service Cost to Load The monthly average cost to load dropped to $0.19/MWh in January from $0.27/MWh in December. Figure 11: System (Day-Ahead and Real-Time) Average Cost to Load $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $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. In January, there was no scarcity event. Market Performance Report Page 13 of 22

14 $/MWh 1-Dec MW Convergence Bidding Figure 12 below shows the daily average volume of cleared virtual bids in IFM for virtual supply and virtual demand. In January, the cleared virtual demand was below virtual supply and both of them were generally lower than December level Figure 12: Cleared Virtual Bids 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 13 shows the energy prices (namely the energy component of the LMP) in IFM, HASP, and RTD Figure 13: IFM, HASP, and RTD Prices IFM HASP RTD Market Performance Report Page 14 of 22

15 Profit (Thousands) Figure 14 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 $0.07 million in January from $6.24 million in December. $2,500 $2,000 Figure 14: Convergence Bidding Profits $1,500 $1,000 $500 $0 -$500 Market Performance Report Page 15 of 22

16 2-Dec 4-Dec 6-Dec 8-Dec 10-Dec 12-Dec 14-Dec 16-Dec 18-Dec 20-Dec 22-Dec 24-Dec 26-Dec 28-Dec 30-Dec 1-Jan 3-Jan 5-Jan 7-Jan 9-Jan 11-Jan 13-Jan 15-Jan 17-Jan 19-Jan 21-Jan 23-Jan 25-Jan 27-Jan 29-Jan Millions Indirect Market Performance Metrics Bid Cost Recovery Figure 15 shows the daily uplift costs due to exceptional dispatch payments (charge codes CC6488, CC6482, and CC6470). The monthly uplift costs in January declined to $0.09 million from $0.97 million in December. $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 -$0.20 -$0.40 Figure 15: Exceptional Dispatch Uplift Costs Figure 16 shows the allocation of bid cost recovery payment in the IFM, RUC and RTM markets. The total bid cost recovery for January declined to $6.27 million from $8.71 million in December. Out of the total monthly bid cost recovery payment for the three markets in January, the IFM market contributed 46 percent, RTM contributed 29 percent and RUC contributed 25 percent of the total bid cost recovery payment. Market Performance Report Page 16 of 22

17 Dec Millions $0.70 $0.60 $0.50 $0.40 $0.30 $0.20 $0.10 Figure 16: Bid Cost Recovery Allocation $0.00 IFM RUC RTM Figure 17 shows the bid cost recovery allocation in RUC. The RUC cost in January was driven mainly by minimum load cost (MLC). The monthly average BCR allocation in RUC for January was approximately $47,684. $700,000 $600,000 $500,000 $400,000 $300,000 $200,000 $100,000 $0 Figure 17: Bid Cost Recovery Allocation in RUC RUC_MLC RUC_CAP_COST RUC_SUC Figure 18 shows the bid cost recovery allocation in RTD. The minimum load cost (MLC) and energy cost contributed largely to the BCR in January. The monthly average BCR allocation in RTD for January was approximately $55,992. Market Performance Report Page 17 of 22

18 Millions 1-Dec Millions $1.5 $1.0 $0.5 Figure 18: Bid Cost Recovery Allocation in RTD $0.0 -$0.5 -$1.0 -$1.5 RT_AS_COST RT_ENERGY RT_MLC RT_SUC RT_TRANSITION_COST Figure 19 shows the bid cost recovery allocation in IFM. The monthly average BCR allocation in IFM for January was approximately $91,831. The Minimum Load Cost (MLC) and energy cost contributed largely to the BCR in IFM in January. $2.0 $1.8 $1.6 $1.4 $1.2 $1.0 $0.8 $0.6 $0.4 $0.2 $0.0 Figure 19: Bid Cost Recovery Allocation in IFM IFM_AS_BID_COST IFM_ENERGY IFM_MLC IFM_SUC IFM_TRANSITION_COST Market Performance Report Page 18 of 22

19 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 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 5 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, real-time unit commitment (RTUC) and RTD processes. The total number of market disruptions in January was 33. Figure 20 shows the frequency of IFM, HASP (RTUC interval 2), RTUC (intervals 1, 3 and 4), and RTD failures. There were a total of 28 market disruptions in January. Type of CAISO Market Table 5: 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 Real-Time Unit Commitment Interval Real-Time Unit Commitment Interval Real-Time Unit Commitment Interval Real-Time Unit Commitment Interval Real-Time Dispatch 28 0 On January 25, there were six RTD and three RTUC disruptions due to broadcast failure. There was one HASP disruption due to application not running. 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 19 of 22

20 Figure 20: Frequency of Market Disruption HASP RTUC RTD Market Performance Report Page 20 of 22

21 Thousands MWh Per Day Manual Market Adjustment Exceptional Dispatch Figure 21 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 January dropped to 6,957 MWh from 105,558 MWh in December. Figure 21: Total Exceptional Dispatch Volume (MWh) by Market Type Day-Ahead Real-Time INC Real-Time DEC Figure 22 shows the volume of the exceptional dispatch broken out by reason. 3 The majority of the exceptional dispatch volumes in January were driven by transmission outage (43 percent), load forecast uncertainty (19 percent), market disruption (6 percent), and Conditions beyond the control of the CAISO (6percent). 3 For details regarding the reason of exceptional dispatch please read the white paper on exceptional dispatch published on the ISO website: For the description of the operating procedure, please read the operating procedures index list at Market Performance Report Page 21 of 22

22 Dec Thousands MWh Per Day Figure 22: Total Exceptional Dispatch Volume (MWh) by Reason System Energy Market Disruption Software Limitation Load Forecast Uncertainty Unit Testing Gas/Fuel Supply Limitations Transmission Outage Conditions beyond the control of the CAISO Other Figure 23 shows the total exceptional dispatch volume as a percent of load, along with the monthly average. The monthly average percentage fell to 0.04 percent in January from 0.53 percent in December. 5.00% 4.50% 4.00% 3.50% 3.00% 2.50% 2.00% 1.50% 1.00% 0.50% 0.00% Figure 23: Total Exceptional Dispatch as Percent of Load Percent Monthly Average Market Performance Report Page 22 of 22