Market Performance Report January 2016

Transcription

1 Market Performance Report January 216 February 29, 216 ISO Market Quality and Renewable Integration CAISO 25 Outcropping Way Folsom, California 9563 (916)

2 Executive Summary 1 The market performance in January 216 is summarized below. The CAISO area performance, Peak loads continued to be at low levels. In the integrated forward market (IFM), SDG&E prices were elevated for a couple of days due to transmission congestion. In the fifteen-minute market (FMM) and real-time market (RTD), SCE and SDG&E prices were elevated on January 19 due to transmission congestion. The congestion rent for interties declined to $3.79 million from $7.25 million in December. Majority of the congestion rents in January accrued on NOB (14 percent) and MALIN5 (73 percent) interties. In the congestion revenue rights market, revenue adequacy was percent as compared with percent in December. The monthly average ancillary service cost to load increased to $.26/MWh in January from $.21/MWh in December. There were no scarcity events in January. The cleared virtual supply was well above the cleared virtual demand in the middle of January and late January. The profits from convergence bidding dropped to $.8 million in January from $2.81 million in December. The bid cost recovery in January inched down to $4.3 million from $4.95 million in December. The real-time energy offset cost dropped to -$.77 million in January from $2.38 million in December. The real-time congestion offset cost rose to $9.31 million in January from $3.97 million in December. The volume of exceptional dispatch increased to 5,661 MWh from 44,558 MWh in December. The monthly average of total exceptional dispatch volume as a percentage of load rose to.29 percent in January from.24 percent in December. Energy Imbalance market (EIM) performance, In the fifteen-minute market (FMM), NEVP price was elevated on January 19 due to binding EIM transfer constraint. In real-time market (RTD), PACE and NEVP prices were elevated on January 5 and 31 due to binding EIM transfer constraint. BCR, RTIEO and RTCO costs were $.67 million, $5.2 million and -$2.13 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 43

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... 9 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 Renewable Generation Curtailment Indirect Market Performance Metrics Bid Cost Recovery Real-time Imbalance Offset Costs... 3 Market Software Metrics Market Disruption Manual Market Adjustment Exceptional Dispatch Energy Imbalance Market Market Performance Report Page 3 of 43

4 MW Market Characteristics Loads Peak loads for ISO continued to be low in December. Figure 1: System Peak Load 35, 3, 25, 2, 15, 1, 5, Market Performance Report Page 4 of 43

5 $/MWh Direct Market Performance Metrics Energy Day-Ahead Prices Figure 2 shows daily prices of four default load aggregate points (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) PGE SCE SDGE VEA Table 1: Day-Ahead Transmission Constraints DLAP Date Transmission Constraint SDG&E January 11 ML6 TAP-SOUTHBAY-138kV line SDG&E January 2 MIGUEL -MIGUELMP-23 XFMR SDG&E January 21 MIGUEL -MIGUELMP-23 XFMR, MIGUEL -MIGUELMP-5 XFMR Real-Time Prices FMM daily prices of the four DLAPs are shown in Figure 3. The binding constraints along with the associated DLAP locations and the occurrence dates are listed in Table 2. Market Performance Report Page 5 of 43

6 $/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 January 19, 2 OMS PDCI_NG SCE, SDG&E January 21, 22 OMS Cry-McC_651 Figure 4 below shows the daily frequency of positive price spikes and negative prices by price range for the default LAPs in the FMM. The cumulative frequency of prices above $25/MWh continued to be.21 percent in January increasing from percent from December 215. The cumulative frequency of negative prices decreased to 1.11 percent in January from 1.71 percent in December. The frequency of negative prices was high on January 24 when the congestion on Path15 resulted in negative prices in a couple of hours. Market Performance Report Page 6 of 43

7 $/MWh 1-Dec Frequency Figure 4: Daily Frequency of FMM LAP Positive Price Spikes and Negative Prices 1.% 5.%.% -5.% -1.% -15.% -2.% -25.% <=-$25 $(-1, -25] $(-4,-1] $(-2,-4] $(,-2] $[25,5) $[5,75) $[75,1) $[1,3] RTD daily prices of the four DLAPs are shown in Figure 5. The binding constraint along with the associated DLAP locations and the occurrence dates are listed in Table 3. On January 5, all four DLAPs prices spiked driven by load upward adjustment and resource outage. On January 31, all four DLAPs prices spiked due to load upward adjustment and wind and solar deviation Figure 5: RTD Simple Average LAP Prices (All Hours) PGE SCE SDGE VEA Table 3: RTD Transmission Constraints DLAP Date Transmission Constraint SCE, SDG&E January 19 OMS PDCI_NG Market Performance Report Page 7 of 43

8 Frequency Figure 6 below shows the daily frequency of positive price spikes and negative prices by price range for the default LAPs in RTD. The cumulative frequency of prices above $25/MWh increased to.66 percent in January from. 24 percent in December. The cumulative frequency of negative prices dropped to 1.78 percent in January from 2.9 percent in November. January 24 saw high frequency of negative prices when the congestion on Path15 resulted in negative price spikes in the middle of the day. Figure 6: Daily Frequency of RTD LAP Positive Price Spikes and Negative Price 1.% 5.%.% -5.% -1.% -15.% -2.% -25.% <=-$25 $(-1, -25] $(-4,-1] $(-2,-4] $(,-2] $[25,5) $[5,75) $[75,1) $[1,3] Market Performance Report Page 8 of 43

9 Thousands Congestion Congestion Rents on Interties Figure 7 below illustrates the daily integrated forward market congestion rents by interties. The cumulative total congestion rent for interties in January declined to $3.79 million from $7.25 million in December. Majority of the congestion rents in January accrued on NOB (14 percent) and MALIN5 (73 percent) interties. Total congestion rent on NOB increased to $.51 million in January from $ million in December. The congestion rent on MALIN5 increased to $2.77 million in January from $2.46 million in December. MALIN5 was derated this month due to various outages including the outage of Malin-Round Mountain #1 5 kv line and Olinda-Tracy 5 kv line. $4, $3,5 $3, $2,5 $2, $1,5 $1, $5 $ Figure 7: IFM Congestion Rents by Interties (Import) MEAD_ITC MKTPCADLN_ITC PALOVRDE_ITC WSTWGMEAD_ITC IPPUTAH_ITC MALIN5 CASCADE_ITC COTPISO_ITC NOB_ITC BLYTHE_ITC Congestion Rents on Branch Groups and Market Scheduling Limits Figure 8 illustrates the IFM congestion rents on selected branch groups and market scheduling limits. Total congestion rents for branch groups and market scheduling limits rose to $1.94 million in January from $ in December. IID_SCE_BG was derated this month mainly driven the outage of Coachella Valley-Mirage 22 kv line. Market Performance Report Page 9 of 43

10 Congestion Cost ($/MWh) 1-Dec Thousands Figure 8: IFM Congestion Rents by Branch Groups and Market Scheduling Limits $35 $3 $25 $2 $15 $1 $5 $ IID-SCE_BG PATH26_BG BLYTHE_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 $1.4/MWh in January from $. 94/MWh in December. The average congestion cost per load served in the real-time market went to -$.54/MWh in January from -$.22/MWh in December. Market Performance Report Page 1 of 43

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 1 illustrates the daily revenue adequacy for congestion revenue rights (CRRs) broken out by transmission element. The average CRR revenue deficit in January dropped to $184,864 from the average revenue deficit of $396,66 in December. Figure 1: Daily Revenue Adequacy of Congestion Revenue Rights $.2 $.1 $. -$.1 -$.2 -$.3 -$.4 -$.5 -$.6 -$.7 OTHER 2416_BARRE _23_24154_VILLA P 22464_MIGUEL _23_22472_MIGUELM 22462_ML6 TAP_138_22772_SOUTHBA OMS P15 HARD 24138_SERRANO _5_24137_SERRANO OMS McC-Vic_ _MOSSLD _23_379_PANOCHE OMS PDCI_NG IID-SCE_BG Overall, January experienced CRR revenue deficit. Revenue shortfalls were observed in most days of this month. A nomogram (OMS McC-Vic_651) was binding in four days, resulting in revenue shortfall of $1.9 million. A line (2416_BARRE _23_24154_VILLA P) was binding in 17 days, resulting in revenue shortfall of $.91 million. A branch group (IID-SCE_BG) was binding in 12 days, resulting in revenue shortfall of $.81 million. Market Performance Report Page 11 of 43

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 22462_ML6 TAP_138_22772_ SOUTHBAY_138_ BR_1 _1 9% OMS PDCI_NG 13% 22464_MIGUEL _23_22472_MIG UELMP_ 1._XF_1 9% OTHER 25% IID-SCE_BG 13% 2416_BARRE _23_24154_VILL A PK_23_BR_1 _1 14% OMS McC-Vic_651 17% Revenue Shortfall, $6.34 Million MEAD_ITC 9% 2416_BARRE _23_2444_ELLIS _23_BR_1 _1 9% NOB_ITC 9% OTHER 25% 782_TL 23S_OVERLOAD_N G 1% 2416_BARRE _23_2444_ELLIS _23_BR_4 _1 16% NdGrp: 36412_DIABLO 2_25._B1 22% Revenue Surplus, $.58 Million Market Performance Report Page 12 of 43

13 Overall, the total amount collected from the IFM was not sufficient to cover the net payments to congestion revenue right holders and the cost of the exemption for existing rights. The revenue adequacy level was percent in January. Out of the total congestion rents, 4.19 percent was used to cover the cost of existing right exemptions. The net total congestion revenues in January were in deficit by $5.73 million, compared to the deficit of $12.28 million in December. The auction revenues credited to the balancing account for January were $8.38 million. As a result, the balancing account for January had a surplus of approximately $2.68 million, which will be allocated to measured demand. Table 4: CRR Revenue Adequacy Statistics IFM Congestion Rents $19,118,72.9 Existing Right Exemptions -$8, Available Congestion Revenues $18,318,7.24 CRR Payments $24,48, CRR Revenue Adequacy -$5,73, Revenue Adequacy Ratio 76.17% Annual Auction Revenues $1,854, Monthly Auction Revenues $6,528, CRR Settlement Rule $23,273.9 Allocation to Measured Demand $2,675, Market Performance Report Page 13 of 43

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 decreased 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 $6.47 $4.15 $3.1 $.1 Dec $5.68 $3.26 $2.44 $.9 Percent Change.37% -.57% 2.74% 2.77% 13.98% 27.8% 23.65% 11.23% The monthly average prices increased for all four types of ancillary services in January. Figure 12 shows the daily IFM average ancillary service prices. The prices for regulation up, regulation down and spinning reserves trended upward Figure 12: IFM (Day-Ahead) Ancillary Service Average Price Non-Spinning Regulation Down Regulation Up Spinning Market Performance Report Page 14 of 43

15 $/MWh Ancillary Service Cost to Load The monthly average cost to load increased to $.26/MWh in January from $.21/MWh in December. Figure 13: System (Day-Ahead and Real-Time) Average Cost to Load $.6 $.5 $.4 $.3 $.2 $.1 $. 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. The ancillary services scarcity pricing mechanism is triggered when the 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 January. Market Performance Report Page 15 of 43

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 was well above the cleared virtual demand in the middle of January and late 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, hour ahead scheduling process (HASP), FMM, and RTD Figure 15: IFM, HASP, FMM, and RTD Prices IFM HASP FMM RTD Market Performance Report Page 16 of 43

17 Profit (Thousands) Figure 16 shows the profits that convergence bidders receive from convergence bidding. The total profits from convergence bidding dropped to $.8 million in January from $2.81 million in December. $2,5 $2, Figure 16: Convergence Bidding Profits $1,5 $1, $5 $ -$5 Renewable Generation Curtailment Figure 17 below shows the monthly wind and solar VERs (variable energy resource) curtailment due to system wide condition or local congestion in FMM. Figure 18 shows the monthly wind and solar VERs (variable energy resource) curtailment by resource type in FMM. Economic curtailment is defined as the resource s dispatch upper limit minus its FMM schedule when the resource has an economic bid. Dispatch upper limit is the maximum level the resource can be dispatched to when various factors are take into account such as forecast, maximum economic bid, generation outage, and ramping capacity. Selfschedule curtailment is defined as the resource s self-schedule minus its FMM schedule when FMM schedule is lower than self-schedule. When a VER resource is exceptionally dispatched, then exceptional dispatch curtailment is defined as the dispatch upper limit minus the exceptional dispatch value. As Figure 17 and Figure 18 below indicate, the renewable curtailment declined since May 215. Most of the curtailment were economic curtailment or solar curtailment. Market Performance Report Page 17 of 43

18 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 MWh 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 MWh 35, 3, 25, 2, 15, 1, 5, Figure 17: Renewable Curtailment by Reason Economic Local Economic System Exceptional Dispatch Local Exceptional Dispatch System Self Schedule Local Self Schedule System 35, 3, 25, 2, 15, 1, 5, Figure 18: Renewable Curtailment by Resource Type Economic wind Exceptional Dispatch Wind Self Schedule Wind Economic Solar Exceptional Dispatch Solar Self Schedule Solar Market Performance Report Page 18 of 43

19 Thousands Indirect Market Performance Metrics Bid Cost Recovery Figure 19 shows the daily uplift costs due to exceptional dispatch payments. The monthly uplift costs in January skidded to $156,781 from $227,17 in December. Figure 19: Exceptional Dispatch Uplift Costs $7 $6 $5 $4 $3 $2 $1 $ -$1 -$2 Figure 2 shows the allocation of bid cost recovery payment in the IFM, real-time unit commitment (RUC) and RTM markets. The total bid cost recovery for January inched down to $4.3 million from $4.95 million in December. Out of the total monthly bid cost recovery payment for the three markets in January, the IFM market contributed 32 percent, RTM contributed 5 percent, and RUC contributed 18 percent of the total bid cost recovery payment. Market Performance Report Page 19 of 43

20 Dec Figure 2: Bid Cost Recovery Allocation $.5 $.45 $.4 $.35 $.3 $.25 $.2 $.15 $.1 $.5 $. IFM RUC RTM Figure 21 and Figure 22 show the daily and monthly BCR cost by local capacity requirement area (LCR) respectively. Figure 21: Bid Cost Recovery Allocation by LCR $.5 $.45 $.4 $.35 $.3 $.25 $.2 $.15 $.1 $.5 $. Bay Area LA Basin NCNB Other San Diego-IV Sierra Stockton Big Creek-Ventura Fresno Humboldt Kern Market Performance Report Page 2 of 43

21 Bay Area Big Creek-Ventura Fresno Humboldt Kern LA Basin NCNB Other San Diego-IV Sierra Stockton Bay Area Big Creek-Ventura Fresno Humboldt LA Basin NCNB Other San Diego-IV Sierra Stockton Figure 22: Monthly Bid Cost Recovery Allocation by LCR $1.8 $1.6 $1.4 $1.2 $1. $.8 $.6 $.4 $.2 $. Dec-15 Jan-16 IFM RUC RTM Figure 23 and Figure 24 show the daily and monthly BCR cost by utility distribution company (UDC) respectively. Figure 23: Bid Cost Recovery Allocation by UDC $.5 $.45 $.4 $.35 $.3 $.25 $.2 $.15 $.1 $.5 $. PGAE SCE SDGE NCPA Other Market Performance Report Page 21 of 43

22 NCPA Other PGAE SCE SDGE NCPA Other PGAE SCE SDGE $2.5 Figure 24: Monthly Bid Cost Recovery Allocation by UDC $2. $1.5 $1. $.5 $. Dec-15 Jan-16 IFM RUC RTM Figure 25 shows the cost related to BCR by type in RUC, which in January was mainly driven by minimum load cost and start-up cost. $25, Figure 25: Cost in RUC $2, $15, $1, $5, $ RUC_MLC RUC_SUC Market Performance Report Page 22 of 43

23 Bay Area Big Creek-Ventura Fresno Humboldt Kern LA Basin NCNB Other San Diego-IV Sierra Stockton Bay Area Big Creek-Ventura Fresno Humboldt LA Basin NCNB Other San Diego-IV Sierra Stockton 1-Dec Figure 26 and Figure 27 show the daily and monthly cost related to BCR by type and LCR in RUC respectively. $.25 $.2 $.15 Figure 26: Cost in RUC by LCR $.1 $.5 $. Bay Area LA Basin NCNB Other San Diego-IV Sierra Stockton Big Creek-Ventura Fresno Humboldt Kern Figure 27: Monthly Cost in RUC by LCR $.7 $.6 $.5 $.4 $.3 $.2 $.1 $. Dec-15 Jan-16 ruc_mlc ruc_suc Market Performance Report Page 23 of 43

24 NCPA Other PGAE SCE SDGE NCPA Other PGAE SCE SDGE 1-Dec Figure 28 and Figure 29 show the daily and monthly cost related to BCR by type and UDC in RUC respectively. $.25 Figure 28: Cost in RUC by UDC $.2 $.15 $.1 $.5 $. $.7 $.6 $.5 PGAE SCE SDGE NCPA Other Figure 29: Monthly Cost in RUC by UDC $.4 $.3 $.2 $.1 $. Dec-15 Jan-16 ruc_mlc ruc_suc Market Performance Report Page 24 of 43

25 Dec Figure 3 shows the cost related to BCR by type in real time. Minimum load cost and energy cost contributed mostly to the real time cost in January. $.6 $.5 $.4 $.3 $.2 $.1 $. -$.1 -$.2 -$.3 -$.4 Figure 3: Cost in Real Time RT_ENERGY RT_MLC RT_SUC RT_AS_COST RT_TRANSITION_COST RT_PUMP_COST Figure 31 and Figure 32 show the daily and monthly cost related to BCR by type and LCR in RT respectively. $.6 $.5 $.4 $.3 $.2 $.1 $. -$.1 -$.2 -$.3 -$.4 Figure 31: Cost in Real Time by LCR Bay Area LA Basin NCNB Other San Diego-IV Sierra Stockton Big Creek-Ventura Fresno Humboldt Kern Market Performance Report Page 25 of 43

26 Bay Area Big Creek-Ventura Fresno Humboldt Kern LA Basin NCNB Other San Diego-IV Sierra Stockton Bay Area Big Creek-Ventura Fresno Humboldt LA Basin NCNB Other San Diego-IV Sierra Stockton Figure 32: Monthly Cost in Real Time by LCR $3. $2. $1. $. ($1.) ($2.) ($3.) Dec-15 Jan-16 rt_energy rt_mlc rt_suc rt_as_cost rt_transition_cost rt_pump_cost Figure 33 and Figure 34 show the daily and monthly cost related to BCR by type and UDC in Real Time respectively. Figure 33: Cost in Real Time by UDC $.6 $.5 $.4 $.3 $.2 $.1 $. -$.1 -$.2 -$.3 -$.4 PGAE SCE SDGE NCPA Other Market Performance Report Page 26 of 43

27 NCPA Other PGAE SCE SDGE NCPA Other PGAE SCE SDGE $4. $3. $2. Figure 34: Monthly Cost in Real Time by UDC $1. $. ($1.) ($2.) ($3.) Dec-15 Jan-16 rt_energy rt_mlc rt_suc rt_as_cost rt_transition_cost rt_pump_cost Figure 35 shows the cost related to BCR by type in IFM. Minimum Load cost and energy cost contributed mostly to the cost in IFM in January. $1.4 $1.2 $1. $.8 $.6 $.4 $.2 $. -$.2 Figure 35: Cost in IFM IFM_PUMP_COST IFM_MLC IFM_ENERGY IFM_SUC IFM_TRANSITION_COST IFM_AS_BID_COST Market Performance Report Page 27 of 43

28 Bay Area Big Creek-Ventura Fresno Humboldt Kern LA Basin NCNB Other San Diego-IV Sierra Stockton Bay Area Big Creek-Ventura Fresno Humboldt LA Basin NCNB Other San Diego-IV Sierra Stockton 1-Dec Figure 36 and Figure 37 show the daily and monthly cost related to BCR by type and location in IFM respectively. Figure 36: Cost in IFM by LCR $1.4 $1.2 $1. $.8 $.6 $.4 $.2 $. Bay Area LA Basin NCNB Other San Diego-IV Sierra Stockton Big Creek-Ventura Fresno Humboldt Kern Figure 37: Monthly Cost in IFM by LCR $4. $3.5 $3. $2.5 $2. $1.5 $1. $.5 $. ($.5) Dec-15 Jan-16 ifm_energy ifm_mlc ifm_suc ifm_as_bid_cost ifm_transition_cost ifm_pump_cost Market Performance Report Page 28 of 43

29 NCPA Other PGAE SCE SDGE NCPA Other PGAE SCE SDGE 1-Dec Figure 38 and Figure 39 show the daily and monthly cost related to BCR by type and UDC in IFM respectively. $1.4 $1.2 $1. Figure 38: Cost in IFM by UDC $.8 $.6 $.4 $.2 $. PGAE SCE SDGE NCPA Other Figure 39: Monthly Cost in IFM by UDC $5 $5 $4 $4 $3 $3 $2 $2 $1 $1 $ -$1 Dec-15 Jan-16 ifm_energy ifm_mlc ifm_suc ifm_as_bid_cost ifm_transition_cost ifm_pump_cost Market Performance Report Page 29 of 43

30 $ Real-time Imbalance Offset Costs Figure 4 shows the daily real-time energy and congestion imbalance offset costs. Real-time energy offset cost dropped to -$.77 million in January from $2.38 million in December. Real-time congestion offset cost rose to $9.31 million in January from $3.97 million in December Figure 4: Real-Time Energy and Congestion Imbalance Offset RT_ENGY_OFFSET RT_CONG_OFFSET Market Performance Report Page 3 of 43

31 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 to prevent a market disruption, or to minimize the extent of a market disruption. There were a total of 37 market disruptions in January. 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, FMM and RTD processes. Type of CAISO Market Table 6: Summary of Market Disruption Market Disruption or Reportable Events Removal of Bids (including Self-Schedules) Day-Ahead IFM RUC Real-Time FMM Interval 1 5 FMM Interval 2 1 FMM Interval 3 1 FMM Interval 4 6 Real-Time Dispatch 24 Figure 41 shows the frequency of IFM, HASP (FMM interval 2), FMM (intervals 1, 3 and 4), and RTD failures. On January 2, two FMM and eight RTD disruptions occurred due to the application not being 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 31 of 43

32 Figure 41: Frequency of Market Disruption HASP FMM RTD Market Performance Report Page 32 of 43

33 Thousands MWh Per Day Manual Market Adjustment Exceptional Dispatch Figure 42 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: a unit commitment at physical minimum; an incremental dispatch above the day-ahead schedule and a decremental dispatch below the day-ahead schedule. The total volume of exceptional dispatch in January increased to 5,661 MWh from 44,558 MWh in December. Figure 42: Total Exceptional Dispatch Volume (MWh) by Market Type Day-Ahead Real-Time INC Real-Time DEC Figure 43 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 (59 percent), operating procedure number and constraint (21 percent), unit testing (9 percent), and voltage support (9 percent). 3 For details regarding the reasons for exceptional dispatch please read the white paper at this link: Market Performance Report Page 33 of 43

34 Dec Thousands MWh Per Day 12 1 Figure 43: Total Exceptional Dispatch Volume (MWh) by Reason Voltage Support Unit Testing Planned Transmission Outage and Constraint Software Limitation Other Conditions beyond the control of the CAISO Contingency Dispatch Operating Procedure Number and Constraint Incomplete or Inaccurate Transmission Figure 44 shows the total exceptional dispatch volume as a percent of load, along with the monthly average. The monthly average percentage rose to.29 percent in January from.24 percent in December. 2.% 1.8% 1.6% 1.4% 1.2% 1.%.8%.6%.4%.2%.% Figure 44: Total Exceptional Dispatch as Percent of Load Percent Monthly Average Market Performance Report Page 34 of 43

35 $/MWh Energy Imbalance Market On November 1, 214, the California Independent System Operator Corporation (ISO) and Portland-based PacifiCorp fully activated the Energy Imbalance Market (EIM). This real-time market is the first of its kind in the West. EIM covers six western states: California, Oregon, Washington, Utah, Idaho and Wyoming. On December 1, 215, NV Energy, the Nevada-based utility successfully began participating in the western Energy Imbalance Market (EIM). With the addition of NV Energy, the EIM expands into Nevada, where the utility serves 2.4 million customers. The ISO real-time market is now in seven states, saving millions of dollars for consumers. The newly expanded marketplace enables the ISO and participants to incorporate thousands of megawatts of variable generating resources, such as wind and solar, into the power grid while reducing greenhouse emissions, and improving grid resiliency and reliability. Figure 45 shows daily simple average ELAP prices for PacifiCorp east (PACE), PacifiCorp West (PACW) and NV Energy (NEVP) for all hours in FMM. On January 19, PACE price was depressed and NEVP price was elevated, which was driven by binding EIM transfer constraint. Figure 45: EIM Simple Average LAP Prices (All Hours) in FMM PACE PACW NEVP Figure 46 shows daily simple average ELAP prices for PACE, PACW and NEVP for all hours in RTD. PACE and NEVP prices were elevated on January 5 and 31 due to binding EIM transfer constraint. Market Performance Report Page 35 of 43

36 Frequency 1-Dec $/MWh Figure 46: EIM Simple Average LAP Prices (All Hours) in RTD PACE PACW NEVP Figure 47 shows the daily price frequency for prices above $25/MWh and negative prices in FMM for PACE, PACW and NEVP. The cumulative frequency of prices above $25/MWh increased to.3 percent from percent in December. The cumulative frequency of negative prices increased to.69 percent in January from 1.24 percent in December. Figure 47: Daily Frequency of EIM LAP Positive Price Spikes and Negative Prices in FMM 2.%.% -2.% -4.% -6.% -8.% -1.% -12.% -14.% <=-$25 $(-1, -25] $(-4,-1] $(-2,-4] $(,-2] $[25,5) $[5,75) $[75,1) $[1,3] Figure 48 shows the daily price frequency for prices above $25/MWh and negative prices in RTD for PACE, PACW and NEVP. The cumulative frequency of prices above $25/MWh increased to.34 percent in January from.5 percent in December. The cumulative frequency of negative prices decreased to 1.67 percent in January from 3.2 percent in December. Market Performance Report Page 36 of 43

37 MWh 1-Dec Frequency Figure 48: Daily Frequency of EIM LAP Positive Price Spikes and Negative Prices in RTD 5.%.% -5.% -1.% -15.% -2.% <=-$25 $(-1, -25] $(-4,-1] $(-2,-4] $(,-2] $[25,5) $[5,75) $[75,1) $[1,3] Figure 49 shows the daily volume of EIM transfer between ISO and PacifiCorp in FMM. Figure 5 shows the daily volume of EIM transfer between PACE and PACW in FMM. The EIM transfer from PacifiCorp to ISO trended upward in January. The EIM transfer from PACE to PACW generally declined in this month. 6, 5, 4, 3, 2, 1, -1, -2, -3, -4, Figure 49: EIM Transfer between CAISO and PAC in FMM CAISO to PACW PACW to CAISO Market Performance Report Page 37 of 43

38 MWh 1-Dec MWh Figure 5: EIM Transfer between PACE and PACW in FMM 5, 4,5 4, 3,5 3, 2,5 2, 1,5 1, 5 PACE to PACW Figure 51 shows the daily volume EIM transfer between CAISO and NEVP in FMM. Figure 52 shows the daily volume EIM transfer between PACE and NEVP in FMM. Most EIM transfer between PACE and NEVP was from PACE to NEVP. 6, 4, 2, -2, -4, -6, -8, -1, -12, -14, Figure 51: EIM Transfer between CAISO and NEVP in FMM CAISO to NEVP NEVP to CAISO Market Performance Report Page 38 of 43

39 MWh 1-Dec MWh 12, 1, 8, 6, 4, 2, -2, -4, -6, -8, Figure 52: EIM Transfer between PACE and NEVP in FMM NEVP to PACE PACE to NEVP Figure 53 shows the daily volume of EIM transfer between ISO and PacifiCorp in RTD. Figure 54 shows the daily volume of EIM transfer between PACE and PACW in RTD. The EIM transfer from PacifiCorp to ISO followed an upward trend in January. The EIM transfer from PACE to PACW decreased generally in January. 6, 4, 2, Figure 53: EIM Transfer between CAISO and PAC in RTD -2, -4, -6, CAISO to PACW PACW to CAISO Market Performance Report Page 39 of 43

40 MWh 1-Dec MWh 6, 5, 4, Figure 54: EIM Transfer between PACE and PACW in RTD 3, 2, 1, PACE to PACW Figure 55 shows the daily volume EIM transfer between ISO and NEVP in RTD. Figure 56 shows the daily volume EIM transfer between PACE and NEVP in RTD. Most EIM transfer between PACE and NEVP was from PACE to NEVP. 1, 8, 6, 4, 2, -2, -4, -6, -8, Figure 55: EIM Transfer between CAISO and NEVP in RTD CAISO to NEVP NEVP to CAISO Market Performance Report Page 4 of 43

41 Dec MWh 12, 1, 8, 6, 4, 2, -2, -4, -6, Figure 56: EIM Transfer between PACE and NEVP in RTD NEVP to PACE PACE to NEVP Figure 57 shows daily real-time imbalance energy offset cost (RTIEO) for PACE, PACW, and NEVP respectively. Total RTIEO was $5.2 million in January, increasing from $4.85 million in December. Figure 57: EIM Real-Time Imbalance Energy Offset by Area $2.5 $2. $1.5 $1. $.5 $. -$.5 -$1. -$1.5 PACE PACW NEVP Figure 58 shows daily real-time congestion offset cost (RTCO) for PACE, PACW, and NEVP respectively. Total RTCO skidded to -$2.13 million in January from -$.89 million in December. Market Performance Report Page 41 of 43

42 Dec $.3 $.2 $.1 $. -$.1 -$.2 -$.3 -$.4 -$.5 -$.6 -$.7 -$.8 Figure 58: EIM Real-Time Congestion Imbalance Offset by Area PACE PACW NEVP Figure 59 shows daily bid cost recovery for PACE, PACW, and NEVP respectively. Total BCR edged down to $.67 million in January from $.78 million in December. $.25 Figure 59: EIM Bid Cost Recovery by Area $.2 $.15 $.1 $.5 $. PACE PACW NEVP Market Performance Report Page 42 of 43

43 The ISO s Energy Imbalance Market Business Practice Manual 4 describes the methodology for determining whether an EIM participating resource is dispatched to support transfers to serve California load. The methodology ensures that the dispatch considers the combined energy and associated marginal greenhouse gas (GHG) compliance cost based on submitted bids 5. In the first two months of EIM operations (November and December 214), EIM startup issues related to processing GHG bid adder resulted in the dispatch of coal generation to support transfers into California. Once the adders were properly accounted for, beginning in January 215, almost all of the EIM dispatches to support transfers into the ISO were from resources other than coal, as documented in Table 7 below. Table 7: EIM Transfer into ISO by Fuel Type Month Coal (%) Gas (%) Non-Emitting (%) Total 14-Nov 3.66% 11.11% 85.23% 1% 14-Dec 24.18% 1.78% 65.4% 1% 15-Jan.7% 6.22% 93.71% 1% 15-Feb.32% 87.72% 11.96% 1% 15-Mar.48% 97.94% 1.58% 1% 15-Apr.12% 64.56% 35.32% 1% 15-May.% 84.38% 15.62% 1% 15-Jun.% 72.95% 27.5% 1% 15-Jul.% 65.16% 34.84% 1% 15-Aug.2% 86.48% 13.51% 1% 15-Sep.% 92.27% 7.73% 1% 15-Oct.1% 99.9%.% 1% 15-Nov.% 25.25% 74.75% 1% 1.% 15.79% 84.21% 1%.% 28.97% 71.3% 1% 4 See the Energy Imbalance Market Business Practice Manual for a description of the methodology for making this determination, which begins on page Imbalance Market. 5 A submitted bid may reflect that a resource is not available to support EIM transfers to California. Market Performance Report Page 43 of 43