Market Performance Report January 2015

Transcription

1 Market Performance Report January 2015 February 27, 2015 ISO Market Quality and Renewable Integration CAISO 250 Outcropping Way Folsom, California (916)

2 Executive Summary 1 The market performance in January 2015 is summarized as follows. In the CAISO areas, The peak loads were generally below 30,000 MW. In the day-ahead market, SDG&E prices were elevated in more than 15 days due to transmission congestion. In the FMM market, SDG&E prices were elevated in more than ten days due to transmission congestion. In the RTD market, SDG&E prices were elevated in a couple of days due to transmission congestion. The congestion rent for interties edged down to $10.04 million from $10.08 million in December. Most of the congestion rents accrued on NOB (26 percent) and MALIN500 (73 percent). The congestion revenue rights market experienced revenue deficit, with improving revenue adequacy level at percent. The monthly average ancillary service cost to load decreased slightly to $0.247/MWh in January from $0.251/MWh in December. There was no scarcity event this month. The cleared virtual supply and virtual demand moved closer in January. The profits from convergence bidding declined to $0.23 million from $1.16 million in December. The bid cost recovery in January decreased to $3.82 million from $8.05 million in December. The real-time energy offset cost decreased to -$6.46 million in January from -$2.72 million in December. The real-time congestion offset cost increased to $2.36 million from $2.11 million in December. The volume of exceptional dispatch rose to 57,666 MWh in January from 26,507 MWh in December. The monthly average of total exceptional dispatch volume (MWh) as a percentage of load increased to 0.33 percent from 0.14 percent in December. In the EIM areas, The prices were relatively stable in both FMM and RTD in January. RTIEO, RTCO, and BCR were $9.37 million, -$1.26 million, and $2.97 million respectively. 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 39

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 Rents on Interties... 9 Congestion Rents on Branch Groups and Market Scheduling Limits... 9 Congestion Revenue Rights Ancillary Services IFM (Day-Ahead) Average Price Ancillary Service Cost to Load Scarcity Events Convergence Bidding Indirect Market Performance Metrics Bid Cost Recovery Real-time Imbalance Offset Costs Market Software Metrics Market Disruption Manual Market Adjustment Exceptional Dispatch Energy Imbalance Market Market Performance Report Page 3 of 39

4 MW Market Characteristics Loads The peak loads for CAISO in January were generally below 30,000 MW. Figure 1: System Peak Load 35,000 30,000 25,000 20,000 15,000 10,000 5,000 0 Market Performance Report Page 4 of 39

5 $/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 Figure 2: Day-Ahead Simple Average LAP Prices (All Hours) PGE SCE SDGE VEA Table 1: Day-Ahead Transmission Constraints DLAP Date Transmission Constraint SDG&E January 8, 12- SERRANO -SERRANO -500 XFMR, 17, 20-24, SXTAP2 -MISSION -230kV LINE Real-Time Prices 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 2. Market Performance Report Page 5 of 39

6 Frequency 1-Dec $/MWh Figure 3: FMM Simple Average LAP Prices (All Hours) PGE SCE SDGE VEA Table 2: FMM Transmission Constraints DLAP Date Transmission Constraint SCE, SDG&E, VEA January 9 PATH26_N-S SDG&E January 6-7, 12 SERRANO -SERRANO -500 XFMR SDG&E January 13-14, 16-17, 20-22, 26 SERRANO -SERRANO -500 XFMR, SXTAP2 -MISSION -230kV LINE Figure 4 below shows the daily frequency of positive price spikes and negative prices by price range for the default LAPs FMM. The cumulative frequency of prices above $250/MWh was 0.64 percent in January, rising from 0.20 percent in December. Figure 4: Daily Frequency of FMM LAP Positive Price Spikes and Negative Prices 5.0% 0.0% -5.0% -10.0% -15.0% -20.0% -25.0% -30.0% <=-$250 $(-100, -250] $(-40,-100] $(-20,-40] $(0,-20] $[250,500) $[500,750) $[750,1000) $[1000,3000] Market Performance Report Page 6 of 39

7 $/MWh Daily prices of the four DLAPs in RTD are shown in Figure 5. The binding constraint along with the associated DLAP locations and the occurrence dates are listed in Table 3. Figure 5: RTD Simple Average LAP Prices (All Hours) PGE SCE SDGE VEA Table 3: RTD Transmission Constraints DLAP Date Transmission Constraint SDG&E January 14-17, SERRANO -SERRANO -500 XFMR, SXTAP2 -MISSION -230kV LINE Figure 6 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 2.40 percent in January, increasing from 2.35 percent in December. Market Performance Report Page 7 of 39

8 Frequency Figure 6: Daily Frequency of RTD LAP Positive Price Spikes and Negative Price 5.0% 0.0% -5.0% -10.0% -15.0% -20.0% -25.0% -30.0% <=-$250 $(-100, -250] $(-40,-100] $(-20,-40] $(0,-20] $[250,500) $[500,750) $[750,1000) $[1000,3000] Market Performance Report Page 8 of 39

9 Thousands Congestion Congestion Rents on Interties Figure 7 below illustrates daily integrated forward market congestion rents by interties. The cumulative total congestion rent for interties in January edged down to $10.04 million from $10.08 million in December. Most of the congestion rents in January accrued on NOB (26 percent) and MALIN500 (73 percent). Total congestion rent on NOB increased to $2.66 million in January from $2.07 million in December. NOB intertie was derated this month due to various outages including the outages of Celilo-Sylmar 1000 kv line and Malin-Round Mountain #2 500 kv line. The congestion rent on MALIN500 rose to $7.29 million in January from $2.21 million in December. MALIN500 is an Intertie scheduling limit (ISL), which was introduced into market on October 15, 2014 through full network model expansion. $1,400 $1,200 $1,000 $800 $600 $400 $200 $0 Figure 7: IFM Congestion Rents by Interties (Import) IID-SCE_ITC IPPUTAH_ITC MKTPCADLN_ITC PALOVRDE_ITC PARKER_ITC SUMMIT_ITC MEAD_ITC NOB_ITC MALIN500 CASCADE_ITC Congestion Rents on Branch Groups and Market Scheduling Limits Figure 8 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 dropped to $0.38 million in January from $0.62 million in December. Most of the congestion rents in January accrued on SUMMIT_BG (32 percent) and PATH15_BG (58 percent). PATH15_BG was congested on January 16, resulting in $0.22 million congestion rent. Market Performance Report Page 9 of 39

10 Congestion Cost ($/MWh) 1-Dec Thousands Figure 8: IFM Congestion Rents by Branch Groups and Market Scheduling Limits $450 $400 $350 $300 $250 $200 $150 $100 $50 $0 IID-SCE_BG SUMMIT_BG BLYTHE_BG PATH15_BG LOSBANOSNORTH_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 9 shows the daily and monthly averages for the day-ahead and real-time markets respectively. Figure 9: 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 increased to $1.81/MWh in January from $0.98/MWh in December. The average congestion cost per load served in the real-time market went to -$0.16/MWh in January from -$0.12/MWh in December. Market Performance Report Page 10 of 39

11 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 () Congestion Revenue Rights Figure 10 illustrates the daily revenue adequacy for congestion revenue rights (CRRs) broken out by transmission element. The average CRR revenue deficit in January was $78,789, decreasing from the average revenue deficit of $244,718 in December. Figure 10: Daily Revenue Adequacy of Congestion Revenue Rights $0.80 $0.60 $0.40 $0.20 -$0.20 -$0.40 -$0.60 -$0.80 -$1.00 -$1.20 HUMBOLDT_IMP_NG OTHER 24086_LUGO _500_26105_VICTORV T-133 METCALF_NG 22835_SXTAP2 _230_22504_MISSION SUMMIT_BG 30760_COBURN _230_30790_PANOCHE 32214_RIO OSO _115_32244_BRNSWKT 24138_SERRANO _500_24137_SERRANO Overall, January experienced CRR revenue deficit. Revenue shortfalls were observed in 19 days of this month. A line (32214_RIO OSO _115_32244_BRNSWKT) was binding in eight days, resulting in revenue shortfall of $0.61 million. A line (22835_SXTAP2 _230_22504_MISSION) was binding in 22 days, resulting in revenue shortfall of $1.44 million. A line (24138_SERRANO _500_24137_SERRANO) was binding in 25 days, resulting in revenue shortfall of $0.63 million. Market Performance Report Page 11 of 39

12 The shares of the revenue surplus and deficit accruing on various congested transmission elements for the reporting period are shown in Figure 11 and the monthly summary for CRR revenue adequacy is provided in Table 4. Figure 11: CRR Revenue Adequacy by Transmission Element 30760_COBURN _230_30790_PAN OCHE _230_BR_1 _1 13% 24086_LUGO _500_26105_VIC TORVL_500_BR_1 OTHER _1 6% 3% HUMBOLDT_IMP _NG 3% 22835_SXTAP2 _230_22504_MIS SION _230_BR_1 _1 41% T-133 METCALF_NG 15% 24138_SERRANO _500_24137_SER RANO _230_XF_1 _P 19% Revenue Shortfall, $3.54 Million 33200_LARKIN _115_33204_POTRE RO _115_BR_2 _1 5% SUMMIT_BG 6% 31090_HMBLT BY_60.0_31100_EEL RIVR_60.0_BR_1 _1 4% PATH15_BG 3% OTHER24138_SERRANO 9% _500_24137_SERRA NO _230_XF_2 _P 6% 32214_RIO OSO _115_32244_BRNS WKT2_115_BR_2 _1 67% Revenue Surplus, $0.90 Million Market Performance Report Page 12 of 39

13 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, 1.67 percent was used to cover the cost of exemptions for existing rights. The net total congestion revenues in January were in deficit by $2.44 million, in comparison to the deficit of $7.47 million in December. The auction revenues credited to the balancing account for January were $9.29 million. The balancing account for January had a surplus of approximately $6.85 million, which will be allocated to measured demand. Table 4: CRR Revenue Adequacy Statistics IFM Congestion Rents $32,163, Existing Right Exemptions -$536, Available Congestion Revenues $31,626, CRR Payments $34,069, CRR Revenue Adequacy -$2,442, Revenue Adequacy Ratio 92.83% Annual Auction Revenues $4,682, Monthly Auction Revenues $4,612, CRR Settlement Rule Allocation to Measured Demand $6,852, Market Performance Report Page 13 of 39

14 $/MW Ancillary Services IFM (Day-Ahead) Average Price Table 5 shows the monthly IFM average ancillary service procurements and the monthly average prices. In January the monthly average procurement declined for regulation down. 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 Jan $5.69 $3.46 $3.34 $0.10 Dec $5.54 $3.72 $3.39 $0.10 Percent Change 0.09% -0.28% 2.34% 2.16% 2.75% -6.99% -1.55% -1.64% The monthly average prices decreased for regulation down, spinning, and nonspinning reserves in January. Figure 12 shows the daily IFM average ancillary service prices. The daily average prices for spinning reserve followed an upward trend in January. Figure 12: IFM (Day-Ahead) Ancillary Service Average Price Non-Spinning Regulation Down Regulation Up Spinning Market Performance Report Page 14 of 39

15 $/MWh Ancillary Service Cost to Load The monthly average cost to load decreased slightly to $0.247/MWh in January from $0.251/MWh in December. Figure 13: System (Day-Ahead and Real-Time) Average Cost to Load $0.40 $0.35 $0.30 $0.25 $0.20 $0.15 $0.10 $0.05 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 was no scarcity event this month. Market Performance Report Page 15 of 39

16 $/MWh 1-Dec MW Convergence Bidding Figure 14 below shows the daily average volume of cleared virtual bids in IFM for virtual supply and virtual demand. The cleared virtual supply and virtual demand moved closer in January Figure 14: 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 15 shows the energy prices (namely the energy component of the LMP) in IFM, HASP, FMM, and RTD Figure 15: IFM, HASP, FMM, and RTD Prices IFM HASP FMM RTD Market Performance Report Page 16 of 39

17 Profit (Thousands) Figure 16 shows the profits that convergence bidders receive from convergence bidding. The total profits from convergence bidding declined to $0.23 million in January from $1.16 million in December. Figure 16: Convergence Bidding Profits $500 $400 $300 $200 $100 $0 -$100 -$200 -$300 Market Performance Report Page 17 of 39

18 Indirect Market Performance Metrics Bid Cost Recovery Figure 17 shows the daily uplift costs due to exceptional dispatch payments. The monthly uplift costs in January increased to $108,812 from $94,100 in December. $0.08 $0.07 $0.06 $0.05 $0.04 $0.03 $0.02 $0.01 -$0.01 Figure 17: Exceptional Dispatch Uplift Costs Figure 18 shows the allocation of bid cost recovery payment in the IFM, RUC and RTM markets. The total bid cost recovery for January decreased to $3.82 million from $8.05 million in December. Out of the total monthly bid cost recovery payment for the three markets in January, the IFM market contributed 10 percent, RTM contributed 86 percent, and RUC contributed 4 percent of the total bid cost recovery payment. Market Performance Report Page 18 of 39

19 Dec $0.80 $0.70 $0.60 $0.50 $0.40 $0.30 $0.20 $0.10 Figure 18: Bid Cost Recovery Allocation IFM RUC RTM Figure 19 and Figure 20 show the daily and monthly BCR cost by local capacity requirement area (LCR) respectively. Figure 21 and Figure 22 show the daily and monthly BCR cost by utility distribution company (UDC) respectively Figure 19: Bid Cost Recovery Allocation by LCR $0.80 $0.70 $0.60 $0.50 $0.40 $0.30 $0.20 $0.10 Bay Area Fresno Humboldt LA Basin NCNB Other San Diego-IV Sierra Stockton Big Creek-Ventura Kern Market Performance Report Page 19 of 39

20 Bay Area Big Creek-Ventura Fresno Humboldt LA Basin NCNB Other San Diego-IV Sierra Stockton Bay Area Big Creek-Ventura Fresno Humboldt Kern LA Basin NCNB Other San Diego-IV Sierra Stockton Figure 20: Monthly Bid Cost Recovery Allocation by LCR $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 Dec-14 Jan-15 IFM RUC RTM Figure 21: Bid Cost Recovery Allocation by UDC $0.80 $0.70 $0.60 $0.50 $0.40 $0.30 $0.20 $0.10 PGAE SCE SDGE Other NCPA Market Performance Report Page 20 of 39

21 NCPA Other PGAE SCE SDGE NCPA Other PGAE SCE SDGE Figure 22: Monthly Bid Cost Recovery Allocation by UDC $5.00 $4.50 $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 Dec-14 Jan-15 IFM RUC RTM Figure 23 shows the cost related to BCR by type in RUC. The RUC cost in January was mostly driven by minimum load cost. $90,000 $80,000 $70,000 $60,000 $50,000 $40,000 $30,000 $20,000 $10,000 $0 Figure 23: Cost in RUC RUC_MLC RUC_SUC Market Performance Report Page 21 of 39

22 Bay Area Big Creek-Ventura Fresno Humboldt LA Basin NCNB Other San Diego-IV Sierra Stockton Bay Area Big Creek-Ventura Fresno Humboldt Kern LA Basin NCNB Other San Diego-IV Sierra Stockton 1-Dec Figure 24 and Figure 25 show the daily and monthly cost related to BCR by type and LCR in RUC respectively. Figure 26 and Figure 27 show the daily and monthly cost related to BCR by type and UDC in RUC respectively Figure 24: Cost in RUC by LCR $0.09 $0.08 $0.07 $0.06 $0.05 $0.04 $0.03 $0.02 $0.01 Bay Area Fresno Humboldt LA Basin NCNB Other San Diego-IV Sierra Stockton Big Creek-Ventura Kern Figure 25: Monthly Cost in RUC by LCR $0.30 $0.25 $0.20 $0.15 $0.10 $0.05 Dec-14 Jan-15 ruc_mlc ruc_suc Market Performance Report Page 22 of 39

23 NCPA Other PGAE SCE SDGE NCPA Other PGAE SCE SDGE 1-Dec Figure 26: Cost in RUC by UDC $0.09 $0.08 $0.07 $0.06 $0.05 $0.04 $0.03 $0.02 $0.01 PGAE SCE SDGE Other NCPA Figure 27: Monthly Cost in RUC by UDC $0.35 $0.30 $0.25 $0.20 $0.15 $0.10 $0.05 Dec-14 Jan-15 ruc_mlc ruc_suc Market Performance Report Page 23 of 39

24 Dec Figure 28 shows the cost related to BCR by type in RT. The minimum load cost and energy cost contributed largely to the RT cost in January. $0.7 $0.6 $0.5 $0.4 $0.3 $0.2 $0.1 $0.0 -$0.1 -$0.2 -$0.3 -$0.4 Figure 28: Cost in RT RT_AS_COST RT_MLC RT_SUC RT_ENERGY RT_TRANSITION_COST RT_PUMP_COST Figure 29 and Figure 30 show the daily and monthly cost related to BCR by type and LCR in RT respectively. Figure 31 and Figure 32 show the daily and monthly cost related to BCR by type and UDC in RT respectively $0.70 $0.60 $0.50 $0.40 $0.30 $0.20 $0.10 -$0.10 -$0.20 -$0.30 Figure 29: Cost in RT by LCR Bay Area Fresno Humboldt LA Basin NCNB Other San Diego-IV Sierra Stockton Big Creek-Ventura Kern Market Performance Report Page 24 of 39

25 Bay Area Big Creek-Ventura Fresno Humboldt LA Basin NCNB Other San Diego-IV Sierra Stockton Bay Area Big Creek-Ventura Fresno Humboldt Kern LA Basin NCNB Other San Diego-IV Sierra Stockton Figure 30: Monthly Cost in RT by LCR $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 ($0.50) ($1.00) Dec-14 Jan-15 rt_energy rt_mlc rt_suc rt_as_cost rt_transition_cost rt_pump_cost $0.70 $0.60 $0.50 $0.40 $0.30 $0.20 $0.10 -$0.10 -$0.20 Figure 31: Cost in RT by UDC PGAE SCE SDGE Other NCPA Market Performance Report Page 25 of 39

26 NCPA Other PGAE SCE SDGE NCPA Other PGAE SCE SDGE Figure 32: Monthly Cost in RT by UDC $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 ($0.50) ($1.00) ($1.50) Dec-14 Jan-15 rt_energy rt_mlc rt_suc rt_as_cost rt_transition_cost rt_pump_cost Figure 33 shows the cost related to BCR by type in IFM. The Minimum Load cost and energy cost contributed largely to the cost in IFM in January. $4.0 $3.5 $3.0 $2.5 $2.0 $1.5 $1.0 $0.5 $0.0 -$0.5 Figure 33: Cost in IFM IFM_SUC IFM_ENERGY IFM_MLC IFM_TRANSITION_COST IFM_AS_BID_COST Market Performance Report Page 26 of 39

27 Bay Area Big Creek-Ventura Fresno Humboldt LA Basin NCNB Other San Diego-IV Sierra Stockton Bay Area Big Creek-Ventura Fresno Humboldt Kern LA Basin NCNB Other San Diego-IV Sierra Stockton 1-Dec Figure 34 and Figure 35 show the daily and monthly cost related to BCR by type and location in IFM respectively. Figure 36 and Figure 37 show the daily and monthly cost related to BCR by type and UDC in IFM respectively. Figure 34: Cost in IFM by LCR $4.00 $3.50 $3.00 $2.50 $2.00 $1.50 $1.00 $0.50 Bay Area Fresno Humboldt LA Basin NCNB Other San Diego-IV Sierra Stockton Big Creek-Ventura Kern Figure 35: Monthly Cost in IFM by LCR $16.00 $14.00 $12.00 $10.00 $8.00 $6.00 $4.00 $2.00 Dec-14 Jan-15 ifm_energy ifm_mlc ifm_suc ifm_as_bid_cost ifm_transition_cost Market Performance Report Page 27 of 39

28 NCPA Other PGAE SCE SDGE NCPA Other PGAE SCE SDGE 1-Dec $4.00 $3.50 $3.00 Figure 36: Cost in IFM by UDC $2.50 $2.00 $1.50 $1.00 $0.50 PGAE SCE SDGE Other NCPA Figure 37: Monthly Cost in IFM by UDC Dec-14 Jan-15 ifm_energy ifm_mlc ifm_suc ifm_as_bid_cost ifm_transition_cost Market Performance Report Page 28 of 39

29 $ Real-time Imbalance Offset Costs Figure 38 shows the daily real-time energy and congestion imbalance offset costs. Real-time energy offset cost decreased to -$6.46 million in January from -$2.72 million in December. Real-time congestion offset cost increased to $2.36 million in January from $2.11 million in December. 1.5 Figure 38: Real-Time Energy and Congestion Imbalance Offset RT_ENGY_OFFSET RT_CONG_OFFSET Market Performance Report Page 29 of 39

30 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 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 this month. The ISO markets include IFM, RUC, fifteen-minute market (FMM) and RTD processes. Figure 39 shows the frequency of IFM, HASP (FMM interval 2), FMM (intervals 1, 3 and 4), and RTD failures. There were a total of 53 market disruptions in January. 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 FMM Interval FMM Interval FMM Interval Real-Time Dispatch 38 0 On January 2, one HASP, three FMM, and 13 RTD disruptions occurred 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 30 of 39

31 Figure 39: Frequency of Market Disruption HASP FMM RTD Market Performance Report Page 31 of 39

32 Thousands MWh Per Day Manual Market Adjustment Exceptional Dispatch Figure 40 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 increased to 57,666 MWh from 26,507 MWh in December. High volume of exceptional dispatch occurred on January due to transmission outage. Figure 40: Total Exceptional Dispatch Volume (MWh) by Market Type Day-Ahead Real-Time INC Real-Time DEC Figure 41 shows the volume of the exceptional dispatch broken out by reason. 3 The majority of the exceptional dispatch volumes in January were driven by planned transmission outage and constraint (87 percent) and start-up instructions (5 percent). 3 For details regarding the reason of exceptional dispatch please read the white paper on exceptional dispatch published on the ISO website: Market Performance Report Page 32 of 39

33 Dec Thousands MWh Per Day Figure 41: Total Exceptional Dispatch Volume (MWh) by Reason Planned Transmission Outage and Constraint Voltage Support Operating Procedure Number and Constraint Market Disruption Other Other Reliability Requirement Incomplete or Inaccurate Transmission Start-Up Instructions Fast Start Unit Management Figure 42 shows the total exceptional dispatch volume as a percent of load, along with the monthly average. The monthly average percentage rose to 0.33 percent in January from 0.14 percent in December, driven by high volume of exceptional dispatch in the middle of this month due to transmission outage. 1.80% 1.60% 1.40% 1.20% 1.00% 0.80% 0.60% 0.40% 0.20% 0.00% Figure 42: Total Exceptional Dispatch as Percent of Load Percent Monthly Average Market Performance Report Page 33 of 39

34 $/MWh Energy Imbalance Market On November 1, 2014, the California Independent System Operator Corporation (CAISO) and Portland based PacifiCorp fully activated the Energy Imbalance Market (EIM). This real-time market is the first of its kind in the West. The Energy Imbalance Market allows balancing authorities outside of the CAISO balancing authority area to voluntarily take part in the imbalance energy portion of the CAISO locational marginal price-based real-time market. PacifiCorp, the CAISO, and market participants participated in market simulations prior to the start of the Energy Imbalance Market on November 1, including parallel production from October 1 to November 1. EIM covers six western states: California, Oregon, Washington, Utah, Idaho and Wyoming. It can bring many benefits to the West such as cost savings, improving the efficiency of dispatching resources, facilitating the renewable integration, more reliability, etc. Figure 43 show daily simple average ELAP prices for PacifiCorp east (PACE) and PacifiCorp West (PACW) for all hours in FMM. The prices for PACE and PACW in FMM were generally quiet in January. PACW price was depressed on January 24 due to the binding EIM transfer constraint between PACE and PACW Figure 43: EIM Simple Average LAP Prices (All Hours) in FMM PACE PACW Figure 48 show daily simple average ELAP prices for PacifiCorp east (PACE) and PacifiCorp West (PACW) for all hours in RTD. PACW prices were depressed on January 18 and due to the binding EIM transfer constraint between PACE and PACW. Market Performance Report Page 34 of 39

35 Frequency 1-Dec $/MWh Figure 44: EIM Simple Average LAP Prices (All Hours) in RTD PACE PACW Figure 45 shows the daily price frequency for prices above $250/MWh and negative prices in FMM for both PACE and PACW. The cumulative frequency of prices above $250/MWh was 0 percent in January, declining from 0.07 percent in December. Figure 45: Daily Frequency of EIM LAP Positive Price Spikes and Negative Prices in FMM 2.0% 0.0% -2.0% -4.0% -6.0% -8.0% -10.0% <=-$250 $(-100, -250] $(-40,-100] $(-20,-40] $(0,-20] $[250,500) $[500,750) $[750,1000) $[1000,3000] Figure 46 shows the daily price frequency for prices above $250/MWh and negative prices in RTD for both PACE and PACW. The cumulative frequency of prices above $250/MWh was 0 percent in January, decreasing from 0.24 percent in December. Market Performance Report Page 35 of 39

36 MWh 1-Dec Frequency Figure 46: Daily Frequency of EIM LAP Positive Price Spikes and Negative Prices in RTD 5.0% 0.0% -5.0% -10.0% -15.0% -20.0% -25.0% <=-$250 $(-100, -250] $(-40,-100] $(-20,-40] $(0,-20] $[250,500) $[500,750) $[750,1000) $[1000,3000] Figure 47 shows the daily volume of EIM transfer between CAISO and PacifiCorp in FMM. Figure 48 shows the daily volume of EIM transfer between PACE and PACW in FMM. The EIM transfer from PACE to PACW increased generally in FMM in the second half of January. 7,000 6,000 5,000 4,000 3,000 2,000 1, ,000-2,000-3,000 Figure 47: EIM Transfer between CAISO and PAC in FMM CAISO to PAC PAC to CAISO Market Performance Report Page 36 of 39

37 MWh 1-Dec MWh 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, Figure 48: EIM Transfer between PACE and PACW in FMM PACE to PACW Figure 49 shows the daily volume of EIM transfer between CAISO and PacifiCorp in RTD. Figure 50 shows the daily volume of EIM transfer between PACE and PACW in RTD. The EIM transfer from PACE to PACW in RTD increased in late January. 7,000 6,000 5,000 4,000 3,000 2,000 1, ,000-2,000-3,000 Figure 49: EIM Transfer between CAISO and PAC in RTD CAISO to PAC PAC to CAISO Market Performance Report Page 37 of 39

38 Dec MWh 5,000 4,500 4,000 3,500 3,000 2,500 2,000 1,500 1, Figure 50: EIM Transfer between PACE and PACW in RTD PACE to PACW Figure 51 shows daily real-time imbalance energy offset cost (RTIEO) for PACE and PACW respectively. Total RTIEO for PACE and PACW was $9.37 million in January, decreasing from $12.20 million in December. Figure 51: EIM Real-Time Imbalance Energy Offset by Area $0.7 $0.6 $0.5 $0.4 $0.3 $0.2 $0.1 $0.0 -$0.1 -$0.2 PACE PACW Market Performance Report Page 38 of 39

39 Dec Figure 52 shows daily real-time congestion offset cost (RTCO) for PACE and PACW respectively. Total RTCO for PACE and PACW was -$1.26 million in January, increasing from -$2.44 million in December. Figure 52: EIM Real-Time Congestion Imbalance Offset by Area $0.1 $0.0 -$0.1 -$0.2 -$0.3 PACE PACW Figure 53 shows daily bid cost recovery for PACE and PACW respectively. Total BCR for PACE and PACW was $2.97 million in January, increasing from $2.25 million in December. $0.14 $0.12 $0.10 $0.08 $0.06 $0.04 $0.02 Figure 53: EIM Bid Cost Recovery by Area PACE PACW Market Performance Report Page 39 of 39