market performance report september 2019 · 2019. 11. 13. · market performance report september...

CAISO 250 Outcropping Way Folsom, California 95630 (916) 351-4400

Market Performance Report September 2019

November 12, 2019

ISO Market Quality and Renewable Integration

Department of Market Analysis and Forecasting – California ISO September 2019

Market Performance Report of 43

Executive Summary1

The market performance in September 2019 is summarized below.

CAISO area performance,

Peak loads for ISO area trended downward with cooler weather.

Across the integrated forward market (IFM), fifteen-minute market (FMM) and real-time market (RTD), PGAE prices were depressed in a few days due to transmission congestion.

Congestion rents for interties rose to $10.09 million from $2.51 million in August. Majority of the congestion rents in September accrued on NOB (24 percent) intertie, Malin500 (32 percent) intertie and Palo Verde (39 percent) intertie.

In the congestion revenue rights (CRR) market, the balancing account for September had a surplus of approximately $10.09 million, which was allocated to measured demand.

The monthly average ancillary service cost to load increased to $0.49/MWh in September from $0.38/MWh in August. There were four scarcity events this month.

The cleared virtual demand was well above cleared supply in early and the middle of September. The profits from convergence bidding escalated to $7.24 million from $0.22 million in August.

The bid cost recovery fell to $15.10 million from $17.57 million in August.

The real-time energy offset cost rose to $5.84 million in September from $1.05 million in August. The real-time congestion cost increased to $7.47 million from $3.25 million in August.

The volume of exceptional dispatch dropped to186,255 MWh from 259,582 MWh in August. The main contributors to the monthly volume were software limitation and load forecast uncertainty. The monthly average of total exceptional dispatch volume as a percentage of load percentage was 0.84 percent in September, decreasing from 1.13 percent in August.

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.

http://www.caiso.com/market/Pages/ReportsBulletins/Default.aspx



Energy Imbalance market (EIM) performance,

In the FMM and RTD, the ELAP prices for NEVP were elevated due to limited transfer, renewable deviation, generation outage, or upward load forecast adjustment.

The monthly average prices in FMM for EIM entities (AZPS, BANCSMUD, BCHA, IPCO, NEVP, PACE, PACW, PGE and PSEI) were $29.64, $35.54, $26.07, $28.82, $35.65, $28.10, $25.75, $26.24, and $25.75 respectively.

The monthly average prices in RTD for EIM entities (AZPS, BANCSMUD, BCHA, IPCO, NEVP, PACE, PACW, PGE and PSEI) were $27.01, $34.05, $25.44, $28.02, $37.33, $26.98, $27.14, $27.99, and $26.89 respectively.

Bid cost recovery, real-time imbalance energy offset, and real-rime congestion offset costs for EIM entities (AZPS, BANCSMUD, BCHA, IPCO, NEVP, PACE, PACW, PGE and PSEI) were $0.41 million, -$3.45 million and -$2.36 million respectively.



TABLE OF CONTENTS

Executive Summary .............................................................................................. 2 Market Characteristics .......................................................................................... 5

Loads ................................................................................................................ 5 Resource Adequacy Available Incentive Mechanism ............................................ 6 Direct Market Performance Metrics ....................................................................... 7

Energy ............................................................................................................... 7 Day-Ahead Prices .......................................................................................... 7

Real-Time Prices ........................................................................................... 7 Congestion ...................................................................................................... 11

Congestion Rents on Interties...................................................................... 11

Congestion Revenue Rights ............................................................................ 12 Ancillary Services ............................................................................................ 15

IFM (Day-Ahead) Average Price .................................................................. 15

Ancillary Service Cost to Load ..................................................................... 16 Scarcity Events ............................................................................................ 16

Convergence Bidding ...................................................................................... 17

Renewable Generation Curtailment ................................................................ 18 Flexible Ramping Product ............................................................................... 19

Flexible Ramping Product Payment ............................................................. 20 Indirect Market Performance Metrics .................................................................. 21

Bid Cost Recovery ........................................................................................... 21

Real-time Imbalance Offset Costs ................................................................... 31 Market Software Metrics .................................................................................. 32

Market Disruption ......................................................................................... 32 Manual Market Adjustment .............................................................................. 34

Exceptional Dispatch ................................................................................... 34 Energy Imbalance Market ................................................................................... 36



Market Characteristics

Loads

Peak loads for ISO area trended downward with cooler weather.

Figure 1: System Peak Load

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Resource Adequacy Available Incentive Mechanism

Resource Adequacy Availability Incentive Mechanism (RAAIM) was activated on November 1, 2016 to track the performance of Resource Adequacy (RA) Resources. RAAIM is used to determine the availability of resources providing local and/or system Resource Adequacy Capacity and Flexible RA Capacity each month and then assess the resultant Availability Incentive Payments and Non-Availability Charges through the CAISO’s settlements process. Table 1 below shows the monthly average actual availability, total non-availability charge, and total availability incentive payment. Starting from May 2018, the ISO reports the system RA average actual availability and flexible RA average actual availability separately.

Table 1: Resource Adequacy Availability and Payment

Total Non-

availability

Charge

Total Availability

Incentive Payment

Average Actual

Availability

Flexible Average

Actual Availability

System Average

Actual Availability

Jan18 $921,031 -$921,031 97.67%

Feb18 $1,945,971 -$1,796,764 95.83%

Mar18 $3,151,376 -$1,589,703 93.27%

Apr18 $2,913,679 -$1,608,256 93.01%

May18 $5,621,558 -$2,346,666 92.79% 91.75%

Jun18 $4,750,039 -$2,622,844 95.08% 92.79%

Jul18 $2,707,179 -$2,892,873 94.56% 96.58%

Aug18 $3,916,827 -$2,812,434 91.29% 96.91%

Sep18 $1,438,373 -$3,186,317 98.08% 97.38%

Oct18 $2,446,741 -$2,253,949 95.33% 96.34%

Nov18 $1,476,915 -$2,025,955 97.27% 96.95%

Dec18 $1,351,560 -$2,091,639 97.68% 96.77%

Jan19 $1,430,981 -$1,430,981 98.25% 96.70%

Feb19 $1,845,678 -$1,836,610 95.76% 97.27%

Mar19 $2,343,144 -$2,163,512 96.57% 95.25%

Apr19 $3,787,853 -$2,033,788 93.77% 93.53%

May19 $2,826,675 -$2,854,841 93.31% 97.33%

Jun19 $3,331,178 -$2,083,184 92.66% 96.62%

Jul19 $1,648,195 -$2,042,559 97.03% 97.01%

Aug19 $2,229,677 -$2,738,800 97.45% 95.93%

Sep19 $3,162,021 -$2,988,545 96.77% 94.98%



Direct Market Performance Metrics

Energy

Day-Ahead Prices

Figure 2 shows daily prices of four default load aggregate points (DLAPs). Table 2 below lists the binding constraints along with the associated DLAP locations and the dates when the binding constraints resulted in relatively high or low DLAP prices.

Figure 2: Day-Ahead Simple Average LAP Prices (All Hours)

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PGAE SCE SDGE VEA

Table 2: Day-Ahead Transmission Constraints

DLAP Date Transmission Constraint

PGAE September 4, 5 MIDWAY-WIRLWIND 500 kV line

VEA September 24 BARRE-LEWIS-230 kV line, EAGLROCK-GOULD-230 kV line, J.HINDS2-MIRAGE-230 kV line

VEA September 25 BARRE-LEWIS-230 kV line, DEVERS-VSTA-230 kV line, J.HINDS2-MIRAGE-230 kV line

Real-Time Prices

FMM daily prices of the four DLAPs are shown in

Figure 3. Table 3 lists the binding constraints along with the associated DLAP locations and the dates when the binding constraints resulted in relatively high or low DLAP prices. September 3 saw price spikes for all four DLAPs due to upward load adjustment, reduction of net imports, generation outage and



renewable deviation. Price spikes also occurred on September 4 driven by upward load adjustment.

Figure 3: FMM Simple Average LAP Prices (All Hours)

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PGAE SCE SDGE VEA

Table 3: FMM Transmission Constraints


PGAE September 3 MIDWAY-WIRLWIND-500 kV line

PGAE September 4 MIDWAY-WIRLWIND-500 kV line, VINCENT-VINCENT-500 kV XFMR, MIDWAY-VINCENT-500 kV line

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 $250/MWh increased to 0.64 percent in September from 0.03 percent in August. The cumulative frequency of negative prices increased to 0.81 percent in September from 0 percent in August.



Figure 4: Daily Frequency of FMM LAP Positive Price Spikes and Negative Prices

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<=-$250 $(-100, -250] $(-40,-100] $(-20,-40] $(0,-20] $[250,500) $[500,750) $[750,1000) >=$1000

RTD daily prices of the four DLAPs are shown in Figure 5. Table 4 lists the binding constraints along with the associated DLAP locations and the dates when the binding constraints resulted in relatively high or low DLAP prices. On September 4, the prices for all four DLAPs spiked due to upward load adjustment and renewable deviation. September 5 saw prices spikes driven by upward load adjustment, reduction of net import, and renewable deviation.

Figure 5: RTD Simple Average LAP Prices (All Hours)

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PGAE SCE SDGE VEA

Table 4: RTD Transmission Constraints




PGAE September 4,5 MIDWAY-VINCENT-500 kV line,

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 $250/MWh inched down to 0.43 percent in September from 0.49 percent in August. The cumulative frequency of negative prices rose to 1.27 percent in September from 0.02 percent in August.

Figure 6: Daily Frequency of RTD LAP Positive Price Spikes and Negative Price

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<=-$250 $(-100, -250] $(-40,-100] $(-20,-40] $(0,-20] $[250,500) $[500,750) $[750,1000) >=$1000



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 September rose to $10.09 million from $2.51 million in August. Majority of the congestion rents in September accrued on NOB (24 percent) intertie, Malin500 (32 percent) intertie and Palo Verde (39 percent). The congestion rent on NOB increased to $2.44 million in September from $1.81 million in August. The congestion rent on Malin500 rose to $3.18 million in September from $0.66 million in August. The congestion rent on Palo Verde increased to $3.96 million in September from $0.04 million in August.

Figure 7: IFM Congestion Rents by Interties (Import)

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MALIN500_ISL NOB_ITC CFE_ITC IID-SDGE_ITC PALOVRDE_ITC

IPPUTAH_ITC STANDIFORD_ITC MEAD_ITC SUMMIT_ITC WSTWGMEAD_ITC



Average Congestion Cost per Load Served

This metric quantifies the average congestion cost for serving one megawatt of load in the ISO system. Figure 8 shows the daily and monthly averages for the day-ahead and real-time markets respectively.

Figure 8: Average Congestion Cost per Megawatt of Served Load

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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 $2.02/MWh in September from $0.74/MWh in August. The average congestion cost per load served in the real-time market decreased to -$0.37/MWh in September from -$0.15/MWh in August.

Congestion Revenue Rights

Congestion revenue rights auction efficiency 1B became in effect on January 1, 2019. It includes key changes related to the congestion revenue rights settlements process:

Targeted reduction of congestion revenue rights payouts on a constraint by constraint basis.

Distribute congestion revenues to the extent that CAISO collected the requisite revenue on the constraint over the month. That is, implement a pro-rata funding for CRRs.

Allow surpluses on one constraint in one hour to offset deficits on the same constraint in another hour over the course of the month.

Only distribute surpluses to congestion revenue rights if the surplus is collected on a constraint that the congestion revenue right accrued a deficit, and only up to the full target payment value of the congestion revenue right.

Distribute remaining surplus revenue at the end of the month, which are associated with constraints that collect more surplus over the month than deficits, to measured demand.



Figure 9 illustrates the CRR notional value in the corresponding month for the various transmission elements that experienced congestion during the month. CRR notional value is calculated as the product of CRR implied flow and constraint shadow price in each hour per constraint and CRR.

Figure 9: Daily CRR Notional Value by Transmission Element

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22192_DOUBLTTP_138_22300_FRIARS _138_BR_1 _1 24016_BARRE _230_25201_LEWIS _230_BR_1 _124156_VINCENT _500_24155_VINCENT _230_XF_3 24804_DEVERS _230_24901_VSTA _230_BR_2 _225201_LEWIS _230_24137_SERRANO _230_BR_2 _1 30060_MIDWAY _500_29402_WIRLWIND_500_BR_1 _27820_TL 230S_OVERLOAD_NG MALIN500_ISLNOB_ITC PALOVRDE_ITCOther(negative) Other(positive)

Figure 10 illustrates the daily CRR offset value in the corresponding month for the transmission elements that experienced congestion during the month.

Figure 10: Daily CRR Offset Value by Transmission Element

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22192_DOUBLTTP_138_22300_FRIARS _138_BR_1 _1 22256_ESCNDIDO_69.0_22724_SANMRCOS_69.0_BR_1 _122886_SUNCREST_230_22885_SUNCREST_500_XF_2 _P 24016_BARRE _230_25201_LEWIS _230_BR_1 _124804_DEVERS _230_24901_VSTA _230_BR_2 _2 30060_MIDWAY _500_29402_WIRLWIND_500_BR_1 _130060_MIDWAY _500_29402_WIRLWIND_500_BR_1 _2 7750_D-VISTA1_OOS_CP6_NGMALIN500_ISL PALOVRDE_ITCOther(deficit) Other(surplus)



CRR offset value is the difference between the revenue collected from the day-ahead congestion and CRR notional value. It is also calculated in each hour per constraint and CRR. A positive CRR offset value represents surplus and a negative CRR offset value represents shortfall. The shares of the CRR payment 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 5.

Figure 11: CRR Payment by Transmission Element

24016_BARRE _230_25201_LEWIS _230_BR_1 _1

20%24156_VINCENT

_500_24155_VINCENT _230_XF_3

6%

24804_DEVERS _230_24901_VSTA _230_BR_2

_2

5%

25201_LEWIS _230_24137_SERRANO

_230_BR_2 _1

7%

30060_MIDWAY _500_29402_WIRLWIND_500_B

R_1 _2

5%

34112_EXCHEQUR_115_34116_LE GRAND_115_BR_1 _1

3%

7820_TL 230S_OVERLOAD_NG6%

MALIN500_ISL10%

NOB_ITC6%

Other23%

PALOVRDE_ITC9%

Net monthly balancing surplus in September was $5.82 million. The auction revenues credited to the balancing account for September was $4.28 million. As a result, the balancing account for September had a surplus of approximately $10.09 million, which was allocated to measured demand.

Table 5: CRR Revenue Adequacy Statistics

Row Description Formula Amount

1 CRR Notional Value $41,767,339

2 CRR Deficit -$6,784,305

3 CRR Settlement Rule -$33,503

4 CRR Adjusted Payment $34,949,531

5 CRR Surplus $6,569,926

6 Monthly Auction Revenue $1,907,937

7 Annual Auction Revenue $2,369,006

8 CRR Daily Balancing Account $3,524,693

9 Net Monthly Balancing Surplus row 5 + row 8 - (row 6 + row 7) $5,817,676

10 Allocation to Measured Demand row 6 + row 7 + row9 $10,094,619



Ancillary Services

IFM (Day-Ahead) Average Price

Table 6 shows the monthly IFM average ancillary service procurements and the monthly average prices. In September the monthly average procurement decreased for regulation down, spinning and non-spinning reserves.

Table 6: IFM (Day-Ahead) Monthly Average Ancillary Service Procurement

Reg Up Reg Dn Spinning Non-Spinning Reg Up Reg Dn Spinning Non-Spinning

Sep-19 332 365 897 901 $9.36 $6.13 $5.83 $1.75

Aug-19 317 380 937 931 $8.52 $4.13 $5.27 $1.05

Percent Change 4.75% -3.89% -4.23% -3.28% 9.86% 48.57% 10.63% 65.98%

Average Procurred Average Price

The monthly average prices rose for all four types of ancillary services in September. Figure 12 shows the daily IFM average ancillary service prices. The prices for regulation up, regulation down and non-spinning were relatively higher on September 4-5 and 24- 25 due to high opportunity cost if energy.

Figure 12: IFM (Day-Ahead) Ancillary Service Average Price

0

2

4

6

8

10

12

14

16

18

20

1-A

ug

3-A

ug

5-A

ug

7-A

ug

9-A

ug

11

-Au

g

13

-Au

g

15

-Au

g

17

-Au

g

19

-Au

g

21

-Au

g

23

-Au

g

25

-Au

g

27

-Au

g

29

-Au

g

31

-Au

g

2-S

ep

4-S

ep

6-S

ep

8-S

ep

10

-Se

p

12

-Se

p

14

-Se

p

16

-Se

p

18

-Se

p

20

-Se

p

22

-Se

p

24

-Se

p

26

-Se

p

28

-Se

p

30

-Se

p

$/M

W

Non-Spinning Regulation Down Regulation Up Spinning



Ancillary Service Cost to Load

The monthly average cost to load increased to $0.49/MWh in September from $0.38/MWh in August. On September 3-4 and 24-25, the average cost increased due to high prices for regulation up, regulation down and non-spinning in day-ahead market.

Figure 13: System (Day-Ahead and Real-Time) Average Cost to Load

$0.00

$0.20

$0.40

$0.60

$0.80

$1.00

$1.20

1-A

ug

3-A

ug

5-A

ug

7-A

ug

9-A

ug

11

-Au

g

13

-Au

g

15

-Au

g

17

-Au

g

19

-Au

g

21

-Au

g

23

-Au

g

25

-Au

g

27

-Au

g

29

-Au

g

31

-Au

g

2-S

ep

4-S

ep

6-S

ep

8-S

ep

10

-Se

p

12

-Se

p

14

-Se

p

16

-Se

p

18

-Se

p

20

-Se

p

22

-Se

p

24

-Se

p

26

-Se

p

28

-Se

p

30

-Se

p

$/M

Wh

Spinning Non-Spinning Regulation Down Regulation Up Monthly Average

Scarcity Events

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. The scarcity events in September are shown in the table below.

Date Hour Ending

Interval Ancillary Service

Region Shortfall

(MW) Percentage of Requirement

September 27 6 1 Regulation Down

SP26_EXP 0.39 0.31%


NP26_EXP 6.59 6.70%


SP26_EXP 2.25 2.19%


SP26_EXP 1.46 1.41%



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 demand was well above cleared supply in early and the middle of September.

Figure 14: Cleared Virtual Bids

0

500

1000

1500

2000

2500

3000

3500

4000

1-A

ug

3-A

ug

5-A

ug

7-A

ug

9-A

ug

11

-Au

g1

3-A

ug

15

-Au

g1

7-A

ug

19

-Au

g2

1-A

ug

23

-Au

g2

5-A

ug

27

-Au

g2

9-A

ug

31

-Au

g2

-Se

p4

-Se

p6

-Se

p8

-Se

p1

0-S

ep

12

-Se

p1

4-S

ep

16

-Se

p1

8-S

ep

20

-Se

p2

2-S

ep

24

-Se

p2

6-S

ep

28

-Se

p3

0-S

ep

MW

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

0

20

40

60

80

100

120

140

160

1-A

ug

3-A

ug

5-A

ug

7-A

ug

9-A

ug

11

-Au

g

13

-Au

g

15

-Au

g

17

-Au

g

19

-Au

g

21

-Au

g

23

-Au

g

25

-Au

g

27

-Au

g

29

-Au

g

31

-Au

g

2-S

ep

4-S

ep

6-S

ep

8-S

ep

10

-Se

p

12

-Se

p

14

-Se

p

16

-Se

p

18

-Se

p

20

-Se

p

22

-Se

p

24

-Se

p

26

-Se

p

28

-Se

p

30

-Se

p

$/M

Wh

IFM HASP FMM RTD



Figure 16 shows the profits that convergence bidders receive from convergence bidding. The total profits from convergence bidding in September escalated to $7.24 million from $0.22 million in August. The profit spiked on September 3 and 4 due to high prices in real-time market.

Figure 16: Convergence Bidding Profits

-$1,000

-$500

$0

$500

$1,000

$1,500

$2,000

$2,500

$3,000

$3,500

$4,0001

-Au

g3

-Au

g5

-Au

g7

-Au

g9

-Au

g1

1-A

ug

13

-Au

g1

5-A

ug

17

-Au

g1

9-A

ug

21

-Au

g2

3-A

ug

25

-Au

g2

7-A

ug

29

-Au

g3

1-A

ug

2-S

ep

4-S

ep

6-S

ep

8-S

ep

10

-Se

p1

2-S

ep

14

-Se

p1

6-S

ep

18

-Se

p2

0-S

ep

22

-Se

p2

4-S

ep

26

-Se

p2

8-S

ep

30

-Se

p

Pro

fit

(Th

ou

sa

nd

s)

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 RTD. Figure 18 shows the monthly wind and solar VERs (variable energy resource) curtailment by resource type in RTD. Economic curtailment is defined as the resource’s dispatch upper limit minus its RTD 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. Self-schedule curtailment is defined as the resource’s self-schedule minus its RTD schedule when RTD 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 show, the renewable curtailment increased in September. The majority of the curtailment was economic and local.



Figure 17: Renewable Curtailment by Reason

0

50,000

100,000

150,000

200,000

250,000

Ja

n-1

8

Fe

b-1

8

Ma

r-1

8

Ap

r-1

8

Ma

y-1

8

Ju

n-1

8

Ju

l-1

8

Au

g-1

8

Se

p-1

8

Oct

-18

No

v-1

8

De

c-1

8

Ja

n-1

9

Fe

b-1

9

Ma

r-1

9

Ap

r-1

9

Ma

y-1

9

Ju

n-1

9

Ju

l-1

9

Au

g-1

9

Se

p-1

9

MW

h

Economic Local Economic System Exceptional Dispatch Local

Exceptional Dispatch System Self Schedule Local Self Schedule System

Figure 18: Renewable Curtailment by Resource Type

0

50,000

100,000

150,000

200,000

250,000

Ja

n-1

8

Fe

b-1

8

Ma

r-1

8

Ap

r-1

8

Ma

y-1

8

Ju

n-1

8

Ju

l-1

8

Au

g-1

8

Se

p-1

8

Oct

-18

No

v-1

8

De

c-1

8

Ja

n-1

9

Fe

b-1

9

Ma

r-1

9

Ap

r-1

9

Ma

y-1

9

Ju

n-1

9

Ju

l-1

9

Au

g-1

9

Se

p-1

9

MW

h

Economic wind Exceptional Dispatch Wind Self Schedule Wind

Economic Solar Exceptional Dispatch Solar Self Schedule Solar

Flexible Ramping Product

On November 1, 2016 the ISO implemented two market products in the 15-minute and 5-minute markets: Flexible Ramping Up and Flexible Ramping Down uncertainty awards. These products provide additional upward and downward flexible ramping capability to account for uncertainty due to demand and renewable forecasting errors. In addition, the existing flexible ramping sufficiency test was extended to ensure feasible ramping capacity for real-time interchange schedules.



Flexible Ramping Product Payment

Figure 19 shows the flexible ramping up and down uncertainty payments. Flexible ramping up uncertainty payment increased to $179,626 in September from $147,017 in August. Flexible ramping down uncertainty payment edged down to -$573 in September from -$851 in August.

Figure 19: Flexible Ramping Up/down Uncertainty Payment

-$20,000

-$10,000

$0

$10,000

$20,000

$30,000

$40,000

$50,000

$60,000

$70,000

$80,000

1-A

ug

3-A

ug

5-A

ug

7-A

ug

9-A

ug

11

-Au

g

13

-Au

g

15

-Au

g

17

-Au

g

19

-Au

g

21

-Au

g

23

-Au

g

25

-Au

g

27

-Au

g

29

-Au

g

31

-Au

g

2-S

ep

4-S

ep

6-S

ep

8-S

ep

10

-Se

p

12

-Se

p

14

-Se

p

16

-Se

p

18

-Se

p

20

-Se

p

22

-Se

p

24

-Se

p

26

-Se

p

28

-Se

p

30

-Se

p

Flexible Ramping Down Payment Flexible Ramping Up Payment

Figure 20 shows the flexible ramping forecast payment. Flexible ramping forecast payment rose to $139,704 this month from 79,727 observed in August.

Figure 20: Flexible Ramping Forecast Payment

-$10,000

$0

$10,000

$20,000

$30,000

$40,000

$50,000

$60,000

$70,000

$80,000

$90,000

$100,000

1-A

ug

3-A

ug

5-A

ug

7-A

ug

9-A

ug

11

-Au

g

13

-Au

g

15

-Au

g

17

-Au

g

19

-Au

g

21

-Au

g

23

-Au

g

25

-Au

g

27

-Au

g

29

-Au

g

31

-Au

g

2-S

ep

4-S

ep

6-S

ep

8-S

ep

10

-Se

p

12

-Se

p

14

-Se

p

16

-Se

p

18

-Se

p

20

-Se

p

22

-Se

p

24

-Se

p

26

-Se

p

28

-Se

p

30

-Se

p

Flexible Ramping Forecast Payment



Indirect Market Performance Metrics

Bid Cost Recovery

Figure 21 shows the daily uplift costs due to exceptional dispatch payments. The monthly uplift costs in September inched up to $1.17 million from $1.05 million in August.

Figure 21: Exceptional Dispatch Uplift Costs

-$100

$0

$100

$200

$300

$400

$500

$600

$700

1-A

ug

3-A

ug

5-A

ug

7-A

ug

9-A

ug

11

-Au

g

13

-Au

g

15

-Au

g

17

-Au

g

19

-Au

g

21

-Au

g

23

-Au

g

25

-Au

g

27

-Au

g

29

-Au

g

31

-Au

g

2-S

ep

4-S

ep

6-S

ep

8-S

ep

10

-Se

p

12

-Se

p

14

-Se

p

16

-Se

p

18

-Se

p

20

-Se

p

22

-Se

p

24

-Se

p

26

-Se

p

28

-Se

p

30

-Se

p

Th

ou

sa

nd

s

Figure 22 shows the allocation of bid cost recovery payment in the IFM, residual unit commitment (RUC) and RTM markets. The total bid cost recovery for September fell to $15.10 million from $17.57 million in August. Out of the total monthly bid cost recovery payment for the three markets in September, the IFM market contributed 45 percent, RTM contributed 45 percent, and RUC contributed 10 percent of the total bid cost recovery payment.

Figure 22: Bid Cost Recovery Allocation

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

1-A

ug

3-A

ug

5-A

ug

7-A

ug

9-A

ug

11

-Au

g

13

-Au

g

15

-Au

g

17

-Au

g

19

-Au

g

21

-Au

g

23

-Au

g

25

-Au

g

27

-Au

g

29

-Au

g

31

-Au

g

2-S

ep

4-S

ep

6-S

ep

8-S

ep

10

-Se

p

12

-Se

p

14

-Se

p

16

-Se

p

18

-Se

p

20

-Se

p

22

-Se

p

24

-Se

p

26

-Se

p

28

-Se

p

30

-Se

p

Millio

ns

IFM RUC RTM



Figure 23 and Figure 24 show the daily and monthly BCR cost by local capacity requirement area (LCR) respectively.

Figure 23: Bid Cost Recovery Allocation by LCR

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.00

1-A

ug

3-A

ug

5-A

ug

7-A

ug

9-A

ug

11

-Au

g

13

-Au

g

15

-Au

g

17

-Au

g

19

-Au

g

21

-Au

g

23

-Au

g

25

-Au

g

27

-Au

g

29

-Au

g

31

-Au

g

2-S

ep

4-S

ep

6-S

ep

8-S

ep

10

-Se

p

12

-Se

p

14

-Se

p

16

-Se

p

18

-Se

p

20

-Se

p

22

-Se

p

24

-Se

p

26

-Se

p

28

-Se

p

30

-Se

p

Mill

ion

s

Bay Area Big Creek-Ventura Fresno Humboldt

LA Basin NCNB Other San Diego-IV

Sierra Stockton Kern

Figure 24: Monthly Bid Cost Recovery Allocation by LCR

-$2.0

$0.0

$2.0

$4.0

$6.0

$8.0

$10.0

$12.0

Ba

y A

rea

Big

Cre

ek-

Ventu

ra

Fre

sno

Hu

mb

old

t

Ke

rn

LA

Ba

sin

NC

NB

Oth

er

Sa

n D

ieg

o-I

V

Sie

rra

Sto

ckto

n

Ba

y A

rea

Big

Cre

ek-

Ventu

ra

Fre

sno

Hu

mb

old

t

Ke

rn

LA

Ba

sin

NC

NB

Oth

er

Sa

n D

ieg

o-I

V

Sie

rra

Aug-19 Sep-19

Mill

ion

s

IFM RUC RTM



Figure 25 and Figure 26 show the daily and monthly BCR cost by utility distribution company (UDC) respectively.

Figure 25: Bid Cost Recovery Allocation by UDC

$0.00

$0.50

$1.00

$1.50

$2.00

$2.50

$3.001

-Au

g

3-A

ug

5-A

ug

7-A

ug

9-A

ug

11

-Au

g

13

-Au

g

15

-Au

g

17

-Au

g

19

-Au

g

21

-Au

g

23

-Au

g

25

-Au

g

27

-Au

g

29

-Au

g

31

-Au

g

2-S

ep

4-S

ep

6-S

ep

8-S

ep

10

-Se

p

12

-Se

p

14

-Se

p

16

-Se

p

18

-Se

p

20

-Se

p

22

-Se

p

24

-Se

p

26

-Se

p

28

-Se

p

30

-Se

p

Mill

ion

s

Other PGAE SCE NCPA SDGE

Figure 26: Monthly Bid Cost Recovery Allocation by UDC

-$2.0

$0.0

$2.0

$4.0

$6.0

$8.0

$10.0

$12.0

$14.0

$16.0

NC

PA

Oth

er

PG

AE

SC

E

SD

GE

NC

PA

Oth

er

PG

AE

SC

E

SD

GE

Aug-19 Sep-19

Mill

ion

s

IFM RUC RTM



Figure 27 shows the cost related to BCR by cost type in RUC.

Figure 27: Cost in RUC

$0.00

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

$0.35

$0.40

$0.45

1-A

ug

3-A

ug

5-A

ug

7-A

ug

9-A

ug

11

-Au

g

13

-Au

g

15

-Au

g

17

-Au

g

19

-Au

g

21

-Au

g

23

-Au

g

25

-Au

g

27

-Au

g

29

-Au

g

31

-Au

g

2-S

ep

4-S

ep

6-S

ep

8-S

ep

10

-Se

p

12

-Se

p

14

-Se

p

16

-Se

p

18

-Se

p

20

-Se

p

22

-Se

p

24

-Se

p

26

-Se

p

28

-Se

p

30

-Se

p

Millio

ns

RUC_MINIMUM_LOAD_COST RUC_STARTUP_COST

Figure 28 and Figure 29 show the daily and monthly cost related to BCR by type and LCR in RUC respectively.

Figure 28: Cost in RUC by LCR

$0.0

$0.1

$0.1

$0.2

$0.2

$0.3

$0.3

$0.4

$0.4

$0.5

1-A

ug

3-A

ug

5-A

ug

7-A

ug

9-A

ug

11

-Au

g

13

-Au

g

15

-Au

g

17

-Au

g

19

-Au

g

21

-Au

g

23

-Au

g

25

-Au

g

27

-Au

g

29

-Au

g

31

-Au

g

2-S

ep

4-S

ep

6-S

ep

8-S

ep

10

-Se

p

12

-Se

p

14

-Se

p

16

-Se

p

18

-Se

p

20

-Se

p

22

-Se

p

24

-Se

p

26

-Se

p

28

-Se

p

30

-Se

p

Mill

ion

s






Figure 29: Monthly Cost in RUC by LCR

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

Ba

y A

rea

Big

Cre

ek-

Ventu

ra

Fre

sno

Hu

mb

old

t

Ke

rn

LA

Ba

sin

NC

NB

Oth

er

Sa

n D

ieg

o-I

V

Sie

rra

Sto

ckto

n

Ba

y A

rea

Big

Cre

ek-

Ventu

ra

Fre

sno

Hu

mb

old

t

Ke

rn

LA

Ba

sin

NC

NB

Oth

er

Sa

n D

ieg

o-I

V

Sie

rra

Sto

ckto

n

Aug-19 Sep-19

Mill

ion

s

ruc_minimum_load_cost ruc_startup_cost

Figure 30 and Figure 31 show the daily and monthly cost related to BCR by type and UDC in RUC respectively.

Figure 30: Cost in RUC by UDC

$0.0

$0.1

$0.1

$0.2

$0.2

$0.3

$0.3

$0.4

$0.4

$0.5

1-A

ug

3-A

ug

5-A

ug

7-A

ug

9-A

ug

11

-Au

g

13

-Au

g

15

-Au

g

17

-Au

g

19

-Au

g

21

-Au

g

23

-Au

g

25

-Au

g

27

-Au

g

29

-Au

g

31

-Au

g

2-S

ep

4-S

ep

6-S

ep

8-S

ep

10

-Se

p

12

-Se

p

14

-Se

p

16

-Se

p

18

-Se

p

20

-Se

p

22

-Se

p

24

-Se

p

26

-Se

p

28

-Se

p

30

-Se

p

Mill

ion

s




Figure 31: Monthly Cost in RUC by UDC

$0.0

$0.5

$1.0

$1.5

$2.0

$2.5

$3.0

NC

PA

Oth

er

PG

AE

SC

E

SD

GE

NC

PA

Oth

er

PG

AE

SC

E

SD

GE

Aug-19 Sep-19

Mill

ion

s

ruc_minimum_load_cost ruc_startup_cost

Figure 32 shows the cost related to BCR in real time by cost type. Minimum load cost contributed largely to the real time cost this month.

Figure 32: Cost in Real Time

-$0.4

-$0.2

$0.0

$0.2

$0.4

$0.6

$0.8

$1.0

$1.2

$1.4

1-A

ug

3-A

ug

5-A

ug

7-A

ug

9-A

ug

11

-Au

g

13

-Au

g

15

-Au

g

17

-Au

g

19

-Au

g

21

-Au

g

23

-Au

g

25

-Au

g

27

-Au

g

29

-Au

g

31

-Au

g

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ep

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Millio

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RT_AS_COST RT_ENERGY RT_MINIMUM_LOAD_COST

RT_STARTUP_COST RT_TRANSITION_COST RT_PUMP_COST



Figure 33 and Figure 34 show the daily and monthly cost related to BCR by type and LCR in real time respectively.

Figure 33: Cost in Real Time by LCR

-$0.6

-$0.4

-$0.2

$0.0

$0.2

$0.4

$0.6

$0.8

$1.0

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Figure 34: Monthly Cost in Real Time by LCR

-$1

$0

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$2

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rt_energy rt_minimum_load_cost rt_startup_cost rt_as_cost rt_transition_cost rt_pump_cost



Figure 35 and Figure 36 show the daily and monthly cost related to BCR by type and UDC in Real Time respectively.

Figure 35: Cost in Real Time by UDC

-$0.4

-$0.2

$0.0

$0.2

$0.4

$0.6

$0.8

$1.0

$1.2

$1.4

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Figure 36: Monthly Cost in Real Time by UDC

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rt_energy rt_minimum_load_cost rt_startup_cost rt_as_cost rt_transition_cost rt_pump_cost



Figure 37 shows the cost related to BCR in IFM by cost type.

Figure 37: Cost in IFM

-$0.2$0.0$0.2$0.4$0.6$0.8$1.0$1.2$1.4$1.6$1.8$2.0

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IFM_AS_BID_COST IFM_MINIMUM_LOAD_COST IFM_STARTUP_COST

IFM_ENERGY IFM_TRANSITION_COST IFM_PUMP_COST

Figure 38 and Figure 39 show the daily and monthly cost related to BCR by type and location in IFM respectively.

Figure 38: Cost in IFM by LCR

-$0.5

$0.0

$0.5

$1.0

$1.5

$2.0

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Figure 39: Monthly Cost in IFM by LCR

-$2$0$2$4$6$8

$10$12$14$16

Ba

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ifm_energy ifm_minimum_load_cost ifm_startup_cost ifm_as_bid_cost ifm_transition_cost ifm_pump_cost

Figure 40 and Figure 41 show the daily and monthly cost related to BCR by type and UDC in IFM respectively.

Figure 40: Cost in IFM by UDC

$0.0

$0.2

$0.4

$0.6

$0.8

$1.0

$1.2

$1.4

$1.6

$1.8

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Figure 41: Monthly Cost in IFM by UDC

-$5.0

$0.0

$5.0

$10.0

$15.0

$20.0

NC

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ifm_energy ifm_minimum_load_cost ifm_startup_cost ifm_as_bid_cost ifm_transition_cost ifm_pump_cost

Real-time Imbalance Offset Costs

Figure 42 shows the daily real-time energy and congestion imbalance offset costs. Real-time energy offset cost rose to $5.84 million in September from $1.05 million in August. Real-time congestion offset in September cost increased to $7.47 million from $3.25 million in August.

Figure 42: Real-Time Energy and Congestion Imbalance Offset

-2

-1

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1

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RT_ENGY_OFFSET RT_CONG_OFFSET



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 to prevent a market disruption, or to minimize the extent of a market disruption. Table 7 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

Table 7: Summary of Market Disruption

Type of CAISO Market Market Disruption

or Reportable

Events

Removal of Bids (including

Self-Schedules)

Day-Ahead

IFM 0 0

RUC 0 0

Real-Time

FMM Interval 1 5 0

FMM Interval 2 2 0

FMM Interval 3 7 0

FMM Interval 4 3 0

Real-Time Dispatch 66 0 Figure 43 shows the frequency of IFM, HASP (FMM interval 2), FMM (intervals 1, 3 and 4), and RTD failures. There were a total of 83 market disruptions this month. On September 23, there were one HASP, five FMM and nine RTD disruptions due to application issue.

2 These system operation issues or system emergencies are referred to in Sections 7.6 and 7.7, respectively, of the ISO tariff.



Figure 43: Frequency of Market Disruption

0

2

4

6

8

10

12

14

16

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HASP FMM RTD

Co

un

t



Manual Market Adjustment

Exceptional Dispatch

Figure 44 shows the daily volume of exceptional dispatches, broken out by market type: real-time incremental dispatch and real-time decremental dispatch. 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 September dropped to186,255 MWh from 259,582 MWh in August.

Figure 44: Total Exceptional Dispatch Volume (MWh) by Market Type

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-5

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Real-Time INC Real-Time DEC

Figure 45 shows the volume of the exceptional dispatch broken out by reason. 3

The majority of the exceptional dispatch volumes in September were driven by software limitation (54 percent), planned transmission outage (8 percent), and load forecast uncertainty (27 percent).

3 For details regarding the reasons for exceptional dispatch please read the white paper at this link: http://www.caiso.com/1c89/1c89d76950e00.html.

http://www.caiso.com/1c89/1c89d76950e00.html



Figure 45: Total Exceptional Dispatch Volume (MWh) by Reason

0

5

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25

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35

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Load Forecast Uncertainty Load Pull

Unit Testing Operating Procedure Number and Constraint

Other Reliability Requirement Planned Transmission Outage

Software Limitation Other

Figure 46 shows the total exceptional dispatch volume as a percent of load, along with the monthly average. The monthly average percentage was 0.84 percent in September, decreasing from 1.13 percent in August.

Figure 46: Total Exceptional Dispatch as Percent of Load

0.00%

0.50%

1.00%

1.50%

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Percent Monthly Average



Energy Imbalance Market

On November 1, 2014, 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, 2015, NV Energy, the Nevada-based utility successfully began participating in the western Energy Imbalance Market (EIM). On October 1, 2016, Phoenix-based Arizona Public Service (AZPS) and Puget Sound Energy (PSEI) of Washington State successfully began full participation in the western Energy Imbalance Market. On October 1, 2017, Portland General Electric Company (PGE) became the fifth western utility to successfully begin full participation in the western Energy Imbalance Market (EIM). PGE joins Arizona Public Service, Puget Sound Energy, NV Energy, PacifiCorp and the ISO, together serving over 38 million consumers in eight states: California, Arizona, Oregon, Washington, Utah, Idaho, Wyoming and Nevada. On April 4, 2018, Boise-based Idaho Power and Powerex of Vancouver, British Columbia successfully entered the western Energy Imbalance Market (EIM) today, allowing the ISO’s real-time power market to serve energy imbalances occurring within about 55 percent of the electric load in the Western Interconnection. The eight western EIM participants serve more than 42 million consumers in the power grid stretching from the border with Canada south to Arizona, and eastward to Wyoming. On April 3, 2019, Sacramento Municipal Utility District (SMUD), part of the Balancing Authority of Northern California (BANC), successfully began full participation in the Western EIM, becoming the first publicly owned agency to be an EIM entity in the Western EIM. Figure 47 shows daily simple average ELAP prices for PacifiCorp east (PACE), PacifiCorp West (PACW), NV Energy (NEVP), Arizona Public Service (AZPS), Puget Sound Energy (PSEI), Portland General Electric Company (PGE), Idaho Power (IPCO), Powerex (BCHA), and Sacramento Municipal Utility District (BANCSMUD), for all hours in FMM. On September 3 and 4, AZPS, BANCSMUD, IPCO, NEVP, and PACE prices were elevated due to upward load adjustment, reduction of net imports, generation outage and renewable deviation. NEVP price was also elevated on September 26 due to upward load adjustment and renewable deviation.



Figure 47: EIM Simple Average LAP Prices (All Hours) in FMM

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AZPS BANCSMUD BCHA IPCO NEVP PACE PACW PGE PSEI

Figure 48 shows daily simple average ELAP prices for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, and BANCSMUD for all hours in RTD. The prices were generally quiet in this month. On September 4 and 26, NEVP price was elevated due to upward load adjustment and renewable deviation.

Figure 48: EIM Simple Average LAP Prices (All Hours) in RTD

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AZPS BANCSMUD BCHA IPCO NEVP PACE PACW PGE PSEI

Figure 49 shows the daily price frequency for prices above $250/MWh and negative prices in FMM for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, and BANCSMUD. The cumulative frequency of prices above $250/MWh edged up to 0.38 percent in September from 0.35 percent in August. The cumulative frequency of negative prices increased to 0.53 percent in September from 0 percent in August.



Figure 49: Daily Frequency of EIM LAP Positive Price Spikes and Negative Prices in FMM

-8%

-6%

-4%

-2%

0%

2%

4%

6%

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<=-$250 $(-100, -250] $(-40,-100] $(-20,-40] $(0,-20] $[250,500) $[500,750) $[750,1000) >=$1000

Figure 50 shows the daily price frequency for prices above $250/MWh and negative prices in RTD for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCOBCHA,

and BANCSMUD. The cumulative frequency of prices above $250/MWh fell to 0.33 percent in September from 0.54 from in August. The cumulative frequency of negative prices increased to 0.77 percent in September from 0.06 percent in August.

Figure 50: Daily Frequency of EIM LAP Positive Price Spikes and Negative Prices in RTD

-10%

-8%

-6%

-4%

-2%

0%

2%

4%

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cy

<=-$250 $(-100, -250] $(-40,-100] $(-20,-40] $(0,-20] $[250,500) $[500,750) $[750,1000) >=$1000



Figure 51 shows daily real-time imbalance energy offset cost (RTIEO) for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, and BANCSMUD respectively. Total RTIEO inched up to -$3.45 million in September from -$3.69 million in August.

Figure 51: EIM Real-Time Imbalance Energy Offset by Area

-$0.8

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BCHA IPCO BANCSMUD AZPS NEVP PACE PACW PGE PSEI

Figure 52 shows daily real-time congestion offset cost (RTCO) for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, and BANCSMUD respectively. Total RTCO decreased to -$2.36 million in September from $0.14 million in August.

Figure 52: EIM Real-Time Congestion Imbalance Offset by Area

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Figure 53 shows daily bid cost recovery for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, and BANCSMUD respectively. Total BCR declined to $0.41 million in September from $0.59 million in August.

Figure 53: EIM Bid Cost Recovery by Area

$0.00

$0.02

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$0.161

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Figure 54 shows the flexible ramping up uncertainty payment for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, and BANCSMUD respectively. Total flexible ramping up uncertainty payment in September slipped to $95,459 from $96,165 in august.

Figure 54: Flexible Ramping Up Uncertainty Payment

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PSEI PGE IPCO PACW NEVP BANCSMUD AZPS PACE BCHA



Figure 55 shows the flexible ramping down uncertainty payment for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, and BANCSMUD respectively. Total flexible ramping down uncertainty payment in September dropped to -$6,235 from -$3,207 in August.

Figure 55: Flexible Ramping Down Uncertainty Payment

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Figure 56 shows the flexible ramping forecast payment for PACE, PACW, NEVP, AZPS, PSEI, PGE, IPCO, BCHA, and BANCSMUD respectively. Total forecast payment in September decreased to -$84,737 from $49,187 in August.

Figure 56: Flexible Ramping Forecast Payment

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The ISO’s Energy Imbalance Market Business Practice Manual4 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 bids5. The EIM dispatches to support transfers into the ISO were documented in Figure 57 and Table 8 below.

Figure 57: Percentage of EIM Transfer into ISO by Fuel Type

0%

10%

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100%

Ja

n-1

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Coal Gas Non_Emitting

4 See the Energy Imbalance Market Business Practice Manual for a description of the methodology for making this determination, which begins on page 42 -- http://bpmcm.caiso.com/Pages/BPMDetails.aspx?BPM=Energy Imbalance Market. 5 A submitted bid may reflect that a resource is not available to support EIM transfers to California.



Table 8: EIM Transfer into ISO by Fuel Type

Month Coal (%) Gas (%) Non-Emitting (%) Total

Jan-17 0.00% 69.88% 30.12% 100%

Feb-17 0.00% 36.42% 63.58% 100%

Mar-17 0.00% 13.37% 86.63% 100%

Apr-17 0.00% 15.47% 84.53% 100%

May-17 0.00% 18.47% 81.53% 100%

Jun-17 0.00% 21.42% 78.58% 100%

Jul-17 0.00% 36.08% 63.92% 100%

Aug-17 0.00% 59.20% 40.80% 100%

Sep-17 0.00% 45.94% 54.06% 100%

Oct-17 0.00% 24.85% 75.15% 100%

Nov-17 0.00% 11.57% 88.43% 100%

Dec-17 0.00% 15.36% 84.64% 100%

Jan-18 0.00% 9.12% 90.88% 100%

Feb-18 0.00% 15.20% 84.80% 100%

Mar-18 0.16% 25.00% 74.84% 100%

Apr-18 0.00% 0.14% 99.86% 100%

May-18 0.00% 1.09% 98.91% 100%

Jun-18 0.00% 2.89% 97.11% 100%

Jul-18 0.00% 25.04% 74.96% 100%

Aug-18 0.00% 35.87% 64.13% 100%

Sep-18 0.00% 35.50% 64.50% 100%

Oct-18 0.00% 24.51% 75.49% 100%

Nov-18 1.16% 53.81% 45.03% 100%

Dec-18 2.00% 57.77% 40.23% 100%

Jan-19 0.46% 53.87% 45.67% 100%

Feb-19 5.60% 58.13% 36.28% 100%

Mar-19 1.07% 55.40% 43.52% 100%

Apr-19 1.15% 47.18% 51.67% 100%

May-19 2.22% 34.75% 63.03% 100%

Jun-19 3.47% 35.32% 61.21% 100%

Jul-19 0.49% 47.74% 51.77% 100%

Aug-19 0.56% 48.55% 50.89% 100%

Sep-19 1.77% 50.01% 48.22% 100%

market performance report september 2019 · 2019. 11. 13. · market performance report september...

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