Market Performance Report February 2014

Market Performance Report February 2014 March 26, 2014 ISO Market Quality and Renewable Integration CAISO 250 Outcropping Way Folsom, California 95630 (916) 351-4400

Executive Summary 1 The market performance in February 2014 is summarized as follows. The peak loads stayed at low levels driven by warm weather. In the day-ahead market, the DLAP prices spiked on February 6 due to high natural gas price, driven by cold weather. In the real-time market, the DLAP prices also spiked on February 6 when natural gas price was high. Total congestion rent for interties in February dropped to $3.69 million from $4.96 million in January. Most of the congestion rents accrued on PACI (36 percent), NOB (20 percent), and Palo Verde (43 percent) interties. The congestion revenue rights market experienced revenue deficit, with revenue adequacy level at 73.50 percent. The monthly average ancillary service cost to load inched up to $0.23/MWh in February from $0.19/MWh in January. Scarcity event occurred on February 6. The cleared virtual demand and supply dropped in February compared with January level. The profits from convergence increased to $1.85 million in February from $0.06 million in January. Total bid cost recovery payment in February rose to $7.35 million from $6.06 million in January. Total volume of exceptional dispatch in February increased to 90,126 MWh from 6,957 MWh in January. The monthly average of total exceptional dispatch volume (MWh) as a percentage of load rallied to 0.55 percent in February from 0.04 percent in January. 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 22

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... 12 IFM (Day-Ahead) Average Price... 12 Ancillary Service Cost to Load... 13 Scarcity Events... 13 Convergence Bidding... 14 Indirect Market Performance Metrics... 16 Bid Cost Recovery... 16 Market Software Metrics... 19 Market Disruption... 19 Manual Market Adjustment... 21 Exceptional Dispatch... 21 Market Performance Report Page 3 of 22

1 1 1 1 2 2 2 1 2 2 2 MW Market Characteristics Loads The peak loads stayed at low levels in February driven by warm weather. Figure 1: System Peak Load 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 Market Performance Report Page 4 of 22

1 1 1 1 2 2 2 1 2 2 2 $/MWh Direct Market Performance Metrics Energy Day-Ahead Prices Figure 2 shows daily prices of four DLAPs. Day-ahead prices spiked on February 6 due to high natural gas price driven by cold weather. 140 120 100 80 60 40 20 0 Figure 2: Day-Ahead Simple Average LAP Prices (All Hours) PGE SCE SDGE VEA Real-Time Prices Daily prices of the four DLAPs are shown in Figure 3. Real-time prices for all four DLAPs increased on February 6 due to natural gas limitation. On February 6, a shortage of natural gas was triggered by cold weather in much of the United States and Canada, impacting fuel supplies to Southern California power plants and reducing electricity generation. In addition, imports were lower than normal due to cold weather on February 6. All these factors, coupled with high natural gas price, resulted in high DLAP prices throughout that day. VEA price was depressed on February 18 due to transmission congestion. The binding constraint along with the associated DLAP locations and the occurrence dates are listed in Table 1. Market Performance Report Page 5 of 22

1 1 1 1 2 2 2 1 2 2 2 Frequency 1-Jan 1 1 1 1 2 2 2 1 2 2 2 $/MWh 140 120 100 80 60 40 20 0 Figure 3: RTD Simple Average LAP Prices (All Hours) PGE SCE SDGE VEA Table 1: Real-Time Transmission Constraints DLAP Date Transmission Constraint VEA February 18 SLIC 2209261 LUGOMOHV_OOS_DVRB SLIC 2209261 LUGOMOHV_OOS_EDLG 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 2.00 percent in February, increasing from 1.11 percent in January. On February 8-11 and 18-19, the frequency of negative prices was relatively high driven by over generation on those days. Figure 4: Daily Frequency of RTD LAP Positive Price Spikes and Negative Price 4.0% 2.0% 0.0% -2.0% -4.0% -6.0% -8.0% -10.0% -12.0% -14.0% -16.0% <=-$250 $(-100, -250] $(-40,-100] $(-20,-40] $(0,-20] $[250,500) $[500,750) $[750,1000) $[1000,3000] Market Performance Report Page 6 of 22

1 1 1 1 2 2 2 1 2 2 2 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 February declined to $3.69 million from $4.96 million in January. Most of the congestion rents in February accrued on PACI (36 percent), NOB (20 percent), and Palo Verde (43 percent) interties. Total congestion rent on Palo Verde decreased to $1.58 million in February from $3.51 million in January. Palo Verde intertie was derated in February due to the outages of Devers-Valley #1 500kV line, Crystal-Navajo 500 kv line, and Devers- Red Bluff 500 kv series capacitor. The congestion rent on PACI increased to $1.33 million in February from $0.41 million in January. PACI was derated in February due to various outages including the outages of TRACY 500 KV series capacitor, John Day-Grizzly #1 500 kv line, and Celilo #3 and #4 converters. $1,000 $900 $800 $700 $600 $500 $400 $300 $200 $100 $0 Figure 5: IFM Congestion Rents by Interties (Import) NOB_ITC PALOVRDE_ITC TRACY500_ITC PACI_ITC MEAD_ITC SUMMIT_ITC COTPISO_ITC CASCADE_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 rose to $1.78 million in February from $$0.74 million in January. Most of the congestion rents in February accrued on IPPDCADLN_BG (43 percent) and IPPUTAH_MSL (42 percent). The congestion rent on IPPDCADLN_BG rose to $0.76 million in February from $0 in January. Market Performance Report Page 7 of 22

1 1 1 1 2 2 2 1 2 2 2 Congestion Cost ($/MWh) 1-Jan 1 1 1 1 2 2 2 1 2 2 2 Thousands Figure 6: IFM Congestion Rents by Branch Groups and Market Scheduling Limits $300 $250 $200 $150 $100 $50 $0 IPPUTAH_MSL MKTPCADLN_MSL PATH26_BG SDGE_CFEIMP_BG SUTTEROBANION_BG WSTWGMEAD_MSL IPPDCADLN_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 4.0 3.0 2.0 1.0 0.0-1.0-2.0 Day Ahead Real Time Day-Ahead Average Real-Time Average The average congestion cost per MWh of load served in the integrated forward market edged up to $0.62/MWh in February from $0.61/MWh in January. The average congestion cost per load served in the real-time market went to -$0.06/MWh in February from -$0.10/MWh in January. Market Performance Report Page 8 of 22

1-Feb 3-Feb 5-Feb 7-Feb 9-Feb 11-Feb 13-Feb 15-Feb 17-Feb 19-Feb 21-Feb 23-Feb 25-Feb 27-Feb 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 February was $126,774, decreasing from the average revenue deficit of 286,335 in January. Figure 8: Daily Revenue Adequacy of Congestion Revenue Rights $0.20 $0.10 $0.00 -$0.10 -$0.20 -$0.30 -$0.40 -$0.50 -$0.60 -$0.70 OTHER 25406_J.HINDS _230_24806_MIRAGE 22500_MISSION _138_22117_CARLTHT 22831_SYCAMORE_138_22124_CHCARIT IPPDCADLN_BG 24016_BARRE _230_25201_LEWIS 25201_LEWIS _230_24137_SERRANO SLIC 2259906 BELOTA-RIVRBK SOL-1 22831_SYCAMORE_138_22117_CARLTHT 30881_HENRIETA_230_34430_HENRETT Overall, February experienced CRR revenue deficit. Revenue shortfalls were observed in 22 days this month. A nomogram (SLIC 2259906 BELOTA-RIVRBK SOL-1) was binding for nine days, resulting in revenue shortfall of $0.81 million. This nomogram was enforced for the planned outage of Bellota-Riverbank line. A line (25201_LEWIS _230_24137_SERRANO) was binding on February 18, resulting in revenue shortfall of $0.58 million. Market Performance Report Page 9 of 22

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 2. Figure 9: CRR Revenue Adequacy by Transmission Element 30881_HENRIETA _230_34430_HEN RETTA_115_XF_3 22831_SYCAMOR 7% E_138_22117_CA RLTHT2_138_BR_ 1 _1 7% 22500_MISSION _138_22117_CAR LTHT2_138_BR_1 _1 7% SLIC 2259906 BELOTA-RIVRBK SOL-1 27% IPPDCADLN_BG 13% OTHER 20% 25201_LEWIS _230_24137_SER RANO _230_BR_1 _1 19% Revenue Shortfall, $2.96 Million 22192_DOUBLTTP_1 38_22300_FRIARS _138_BR_1 _1 15% 22820_SWEETWTR_ 69.0_22476_MIGUE LTP_69.0_BR_1 _1 4% IPPUTAH_MSL 11% SUTTEROBANION_B G 1% OTHER 1% 22831_SYCAMORE_ 138_22124_CHCARI TA_138_BR_1 _1 40% 25406_J.HINDS _230_24806_MIRA GE _230_BR_1 _1 28% Revenue Surplus, $0.66 Million Market Performance Report Page 10 of 22

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, 3.27 percent was used to cover the cost of exemptions for existing rights. The net total congestion revenues in February were in deficit by $3.55 million, in comparison to the deficit of $8.88 million in December. The auction revenues credited to the balancing account for February were $5.31 million. The balancing account for February had a surplus of approximately $1.79 million, which will be allocated to measured demand. Table 2: CRR Revenue Adequacy Statistics Concept Amount IFM Congestion Rents $10,177,971.73 Existing Right Exemptions -$332,324.19 Available Congestion Revenues $9,845,647.54 CRR Payments $13,395,324.89 CRR Revenue Adequacy -$3,549,677.35 Revenue Adequacy Ratio 73.50% Annual Auction Revenues $2,329,694.13 Monthly Auction Revenues $2,976,670.76 CRR Settlement Rule $33,771.38 Allocation to Measured Demand $1,790,458.91 Market Performance Report Page 11 of 22

1 1 1 1 2 2 2 1 2 2 2 $/MW Ancillary Services IFM (Day-Ahead) Average Price Table 3 shows the monthly IFM average ancillary service procurements and the monthly average prices. In February the monthly average procurement decreased for regulation up, spinning, and non-spinning reserve. Table 3: 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 Feb-14 331 321 761 754 $5.11 $4.26 $1.67 $0.10 Jan-14 332 321 767 768 $4.81 $3.26 $1.89 $0.09 Percent Change -0.42% 0.07% -0.77% -1.78% 6.43% 30.53% -11.45% 14.63% The monthly average prices increased for regulation up, regulation down, and non-spinning reserve in February. Figure 10 shows the daily IFM average ancillary service prices. The regulations down average prices in February were relatively high compared with January. Figure 10: IFM (Day-Ahead) Ancillary Service Average Price 10 9 8 7 6 5 4 3 2 1 0 Non-Spinning Regulation Down Regulation Up Spinning Market Performance Report Page 12 of 22

1 1 1 1 2 2 2 1 2 2 2 $/MWh Ancillary Service Cost to Load The monthly average cost to load inched up to $0.23/MWh in February from $0.19/MWh in January. The average cost to load increased on February 6 due to high opportunity cost of energy, which can be attributed to natural gas limitation and lower than normal imports driven by cold weather condition. Figure 11: System (Day-Ahead and Real-Time) Average Cost to Load $1.00 $0.90 $0.80 $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. On February 6, ancillary services scarcity pricing was triggered in the NP26 expanded ancillary service region in the real-time pre-dispatch (RTPD) market for hour ending 17 and in the hourahead scheduling process (HASP) market for hour ending 18 and 19. The NP26 expanded ancillary service region was activated on February 6, 2014 due to gas supply concerns in Southern California. Market Performance Report Page 13 of 22

1 1 1 1 2 2 2 1 2 2 2 $/MWh 1-Jan 1 1 1 1 2 2 2 1 2 2 2 MW Convergence Bidding Figure 12 below shows the daily average volume of cleared virtual bids in IFM for virtual supply and virtual demand. In February, the cleared virtual demand and virtual supply were generally lower than January level. 3000 2500 Figure 12: 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 13 shows the energy prices (namely the energy component of the LMP) in IFM, HASP, and RTD. The prices in the three markets spiked on February 6 due to the gas issue discussed in previous section. 300 250 200 Figure 13: IFM, HASP, and RTD Prices 150 100 50 0 IFM HASP RTD Market Performance Report Page 14 of 22

1 1 1 1 2 2 2 1 2 2 2 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 increased to $1.85 million in February from $0.06 million in January. $600 $400 Figure 14: Convergence Bidding Profits $200 $0 -$200 -$400 -$600 -$800 Market Performance Report Page 15 of 22

1 1 1 1 2 2 2 1 2 2 2 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 February rose to $2.19 million from $0.09 million in January. On February 6, the uplift cost was approximately $1.76 million, mainly driven by the exceptional dispatches issued due to natural gas limitation in Southern California. $2.00 $1.80 $1.60 $1.40 $1.20 $1.00 $0.80 $0.60 $0.40 $0.20 $0.00 -$0.20 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 February increased to $7.35 million from $6.06 million in January. Out of the total monthly bid cost recovery payment for the three markets in February, the IFM market contributed 18 percent, RTM contributed 66 percent and RUC contributed 16 percent of the total bid cost recovery payment. Market Performance Report Page 16 of 22

1 1 1 1 2 2 2 1 2 2 2 1-Jan 1 1 1 1 2 2 2 1 2 2 2 Millions $0.80 $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 February was mostly driven by minimum load cost (MLC). The monthly average BCR allocation in February was approximately $41,107, decreasing from $48,314 in January. $250,000 Figure 17: Bid Cost Recovery Allocation in RUC $200,000 $150,000 $100,000 $50,000 $0 RUC_MLC RUC_CAP_COST RUC_SUC Market Performance Report Page 17 of 22

1 1 1 1 2 2 2 1 2 2 2 Millions 1-Jan 1 1 1 1 2 2 2 1 2 2 2 Millions Figure 18 shows the bid cost recovery allocation in RTD. The minimum load cost (MLC) and energy cost contributed largely to the BCR in February. The monthly average BCR allocation in February was approximately $162,371, higher than $56,092 in January. $2.0 Figure 18: Bid Cost Recovery Allocation in RTD $1.5 $1.0 $0.5 $0.0 -$0.5 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 February dropped to $27,516 from $91,163 in January. The Minimum Load Cost (MLC) and energy cost contributed largely to the BCR in IFM in February. $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

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 4 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 February 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 25 market disruptions in February. Type of CAISO Market Table 4: 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 1 2 0 Real-Time Unit Commitment Interval 2 1 0 Real-Time Unit Commitment Interval 3 2 0 Real-Time Unit Commitment Interval 4 3 0 Real-Time Dispatch 17 0 On February 9, there were one HASP, three RTD, and two RTUC disruptions due to bids transfer failure. 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

1 1 1 1 2 2 2 1 2 2 2 12 10 8 6 4 2 0 Figure 20: Frequency of Market Disruption HASP RTUC RTD Market Performance Report Page 20 of 22

1 1 1 1 2 2 2 1 2 2 2 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 February rose to 90,126 MWh from 6,957 MWh in January. The exceptional dispatch volume on February 6 and 7 totaled approximately 39,000 MWh, mainly driven by the natural gas shortage in Southern California. Figure 21: Total Exceptional Dispatch Volume (MWh) by Market Type 20 15 10 5 0-5 -10-15 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 February were driven by transmission outage (19 percent), load forecast uncertainty (16 percent), and conditions beyond the control of the CAISO (47percent). 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 21 of 22

1 1 1 1 2 2 2 1 2 2 2 1-Jan 1 1 1 1 2 2 2 1 2 2 2 Thousands MWh Per Day 25 Figure 22: Total Exceptional Dispatch Volume (MWh) by Reason 20 15 10 5 0 Unit Testing Load Forecast Uncertainty Market Disruption Planned Transmission Outage and Constraint Conditions beyond the control of the CAISO Unplanned Outage Software Limitation Other Reliability Requirement Figure 23 shows the total exceptional dispatch volume as a percent of load, along with the monthly average. The monthly average percentage rallied to 0.55 percent in February from 0.04 percent in January. February 6 saw high average percentage, which also resulted from the natural gas limitation issue. 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