ATC Customer Meeting · 2009. 8. 19. · Hourly and Monthly FundingNet FTR Shortfall Date of...

Midwest ISO Overview:ATC Customer Meeting

August 20, 2009

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Agenda• Overview – July 2009• Dashboard• Selected Slides• Questions

3

July 2009 OverviewOverview:

July 2009 is one of the coolest July’s on the NOAA record with an average temperature of 4.25° F below the long term July average. As a result, the Midwest ISO market was characterized by lower demand and lower prices.The peak load of 82,635 MW was set on July 28th in HE15. The average load in July was down by 1.11% from June and was 14.53% lower than July 2008.Coal prices remained steady this month; while gas prices declined slightly and oil prices rose when compared to June

Markets:Monthly hourly average Day-Ahead and Real-Time prices for July 2009 were the lowest since market start at $23.08/MWh and $22.67/MWh respectively. Both Day-Ahead and Real-Time prices were approximately 62% lower than July 2008 levels and 12% lower than June 2009 levels.Monthly average Real-Time Regulation, Spinning and Supplemental Reserve MCPs also continued to decline at $11.34/MWh, $2.70/MWh and $0.32/MWh respectively, lower than those in both May and June.

4

July 2009 Overview (cont’d)

:Net virtual profits decreased to $0.54/MWh in July, influenced by:

– A significant decline in virtual supply profits and a slight drop in virtual demand profits

– A substantial decrease in both cleared virtual demand and supplyvolumes, in contrast to the increases observed in June

– An improvement in price convergence between the Day-Ahead and Real-Time markets

Both cleared virtual demand and virtual supply volumes lag behind all other months of 2009 except for February, while virtual demand volume also lags behind March

Markets (continued)

5

July 2009 Overview (cont’d)Markets (continued):

The rate of return on investments for BUY FTRs in the Monthly FTR auction for July was a loss of 15.8%, influenced by a significant decline in the share of dollars received from the Day-Ahead market. There was a more than 50% decline in congestion collections due to lower temperatures which contributed to less demand and less congestion.

Over the past thirteen months, there has been a positive simple return on investment of 8.45%.

Operations/Reliability:On a monthly average basis, the Real-Time Unit Commitment Performance scores continued to exceed target levels.

There were three days where the daily score for all hours was below excellent or good. The performance on those days can be attributed to load forecast error resulting from thunderstorm activity, with acontributing factor on one of the days from unexpected wind generation.

July RSG for both Day-Ahead and Real-Time were lower than levels observed in June.

6

July 2009 Overview (cont’d)

Weather related input data errors as well as wide-spread thunderstorms throughout the footprint resulted in the Day-Ahead Mid-Term Load Forecast error exceeding the threshold for four days this month.

ion Services:• There was an uptick in the number interconnection requests, which is not

surprising given a deadline to get in the queue this month, but no deadline to complete milestones to continue or withdraw.The late TSR report was for 1000+ MW out of Manitoba to Minnesota and Wisconsin. Customers were involved and participated in the study, which is now moving to a facilities study.

Operations/Reliability (continued):

Transmiss

7

Dashboard

● - Expected - Concern/Monitor ▼ - Review

MetricCurrent Month

IndicatorMetric

Current Month

IndicatorJul-09 Jun-09 May-09 Apr-09 Jul-09 Jun-09 May-09 Apr-09

Absolute DA-RT Price Convergence ● ● ● ● Tie Line Error ● ● ● ●Day-Ahead Load Cleared from Real-Time ● ● ● ● Control Performance - BAAL ● ● ● ●Monthly Average Virtual Profitability ● ● ● ● Control Performance - CPS1 ● ● ● ●

FTR Funding ● ● ● ▼ Control Performance - CPS1 (12 month rolling) ● ● ● ●

FTR Monthly (BUY) Auction Profitability TBD NA NA NA Unit Commitment Efficiency ● ● ● ●Headroom ● ● ● ● ARS Deployment ● ● ● ●Real-Time Unit Commitment Performance - All Hours ● ● ● ● NERC Violations ● ● ● ●

Real-Time Unit Commitment Performance - Peak Hour ● ● ● ● Fuel Normalized RSG per RT MWH Served ● ● ● ●

Day-Ahead Mid-Term Load Forecast ■ ● ● NAShort-Term Load Forecast ● ● ● NA

MetricCurrent Month

IndicatorMetric

Current Month

IndicatorJul-09 Jun-09 May-09 Apr-09 Jul-09 Jun-09 May-09 Apr-09

Application Availability ● ● ● ● Monthly Transmission Queue ● ● ● ●UDS Solution Percentage ● ● ● ● System Impact Study Performance ● ● ● ●Day-Ahead Posting Time ● ● ● ● Generation Queue Progress and Status ■ ● ● ●Transmission Settlements Accuracy ● ● ● ● Settlement Disputes ● ● ● ●

Previous 3 Month Indicators


Operational Excellence

Customer Service



8

PricingDay-Ahead and Real-Time Average Monthly LMP for Midwest ISO and PJM

$61.33

$50.20

$39.58$36.41 $36.85

$41.25$36.84

$31.93$27.58 $26.70 $25.15 $25.82

$22.67

$90.04

$70.76

$65.02

$49.33 $51.14 $49.39

$57.85

$44.31$39.53

$33.69 $32.89 $32.54 $31.58

0

10

20

30

40

50

60

70

80

90

100

Jul-08 Aug-08 Sep-08 Oct-08 Nov-08 Dec-08 Jan-09 Feb-09 Mar-09 Apr-09 May-09 Jun-09 Jul-09

$/M

Wh

MISO DAPJM DAMISO RTPJM RT

Source: Midwest ISO Market Analysis Department

Note: MISO System-Wide based on the monthly hourly average of the hubs.

9

37.4 40.048.2 45.3

31.246.3

12.922.4 15.7 17.3

27.614.710.9


Day-Ahead Congestion Collections

Normalized* Day-Ahead Market Congestion Collections$/MWh

0.580.71

0.95 0.930.64

0.86

0.25 0.240.50 0.38 0.41 0.52

0.32


Day-Ahead Market Congestion Collections$ in millions

Source: Midwest ISO Data Management Department

* Normalized using Day-Ahead load

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MISO Load* Duration Curve


*ICCP Load data

11

Day-Ahead Cleared51

.6

49.9

43.4

42.1

41.8

47.1

47.9

40.9

41.3

37.7

37.8

42.7 43.9

49.1

47.7

41.9

40.5 41.7

47.1 48.1

39.5

39.7

36.0

35.6

41.7 42.9

4.3

4.6

4.5

4.5

3.9

3.7

3.1

1.6

1.9

2.0

2.3

2.5

1.93.

9

4.2

4.0

3.8

2.9

2.4

1.7

1.4 1.9

1.7

1.6

1.8

1.5


TWh

Physical Load Physical Supply Virtual Load Virtual Supply

Day-Ahead Cleared Load Value (includes virtuals)

$ in Billions3.94 3.16 2.09 1.81 1.74 2.18 2.05 1.47 1.28 1.07 1.02 1.29 1.12

Source: Midwest ISO Market Analysis and Data Management Department

12

53.1

51.5

45.6

44.4

44.3

49.9

50.8

42.8

43.4

39.7

40.0 45

.2

45.9


TWh

Real-Time Load*

Real-Time Cleared Value

Real-Time Cleared

$ in Billions


*Real-Time Load is the sum of hourly peak UDS load.

3.54 2.76 1.86 1.61 1.64 2.06 1.84 1.34 1.15 1.02 1.01 1.20 1.06

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Midwest ISO Cleared Virtual Market Profit Index*

$5

$4

$3

$2

$1

$0

$1

$2

$3

$4

$5


Inde

x ($

/MW

h)

Decrement Increment Market Index Threshold Upper Limit STD Lower Limit STD

Virtual Profitability Determined by:-Hedging-LMP Variation between DA & RT

Threshold + Daily Average STD = 2.44

Threshold - Daily Average STD = -1.80

Threshold of $0.32/MWh

Mo.StdDev 2.64 1.24 1.59 1.36 1.61 2.78 2.49 1.57 2.39 2.12 2.71 2.61 1.19

Monthly Average Gross Virtual Profitability

• Threshold is the average of monthly indices from Jan08-Dec08• Daily Average STD is from Jul08-Jul09

*The virtual profitability market index is defined as the sum of profits/losses for all cleared virtual transactions divided by the volume (MWh) of total cleared transactions.* Virtual profits/losses are calculated by multiplying the cleared virtual MW and the imbalance between RT LMP and DA LMP for a cpnode, then summed across all cpnodes, all hours.

Source: Midwest ISO Market Pricing Department

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($8.00)

($6.00)

($4.00)

($2.00)

$0.00

$2.00

$4.00

$6.00

$8.007/

17/

27/

37/

47/

57/

67/

77/

87/

97/

107/

117/

127/

137/

147/

157/

167/

177/

187/

197/

207/

217/

227/

237/

247/

257/

267/

277/

287/

297/

307/

31

Date

$/M

Wh

Daily Cleared Index Threshold July Market Index*

Threshold of $0.32/MWh

July Market Index of $0.54/MWh

Daily Gross Virtual Cleared Profitability

Source: Midwest ISO Market Pricing Department

• Threshold is the average of monthly indices from Jan08-Dec08

Peak Day: 7/28/2009 Peak Hour = HE 15

*The virtual profitability market index is defined as the sum of profits/losses for all cleared virtual transactions divided by the volume (MWh) of total cleared transactions.

15

37.5

36.1

47.5

44.8

30.6

47.3

14.6

11.2

22.1

16.8

18.2

27.2

14.1

27.5

17.7

5.3

1.8

13.7

3.74.1

1.8

2.7

3.5

1.9

2.7 10.3

0.8

0

10

20

30

40

50

60

70

Jul2008

Aug Sep Oct Nov Dec Jan2009

Feb Mar Apr May Jun Jul 12MthAvg*

YTDAvg

$ in

Millio

ns

Hourly and Monthly Funding Net FTR Shortfall

Date of Extraction: Aug 08, 2009. Values may continue to change until the S-105 is complete.

87.6% 100.0% 94.5% 81.3% 94.5% 77.5% 79.9% 73.1% 92.5% 86.2% 100.0% 97.1% 100.0% 89.7% 89.8%

FTR Funding

Source: Midwest ISO Market Analysis Department and the Market ECF Report

Monthly Funding Factor

*Aug08-Jul09

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FTR Monthly Auction (BUY) Return on Investment


Date of Extraction: Aug 08, 2009. Values may continue to change until the S-105 is complete.

The document titled “Item B4b Metrics for FTR Monthly Auction Market.pdf” is available in the March 2009 AC meeting materials.

9.1%

1.5%

18.9% 16.7%

3.1%8.2%

-10.8%-6.2%

37.0%

45.8%

12.8%

-10.3%

-15.8%

-30.0%

0.0%

30.0%

60.0%

Jul-08

Aug-08

Sep-08

Oct-08

Nov-08

Dec-08

Jan-09

Feb-09

Mar-09

Apr-09

May-09

Jun-09

Jul-09

Mon

thly

Ret

urn

on In

vest

men

t

Simple Return (Profit/Payment) Excess Return (Simple Return - Avg 30 Day to Maturity T-Bill)

Rolling Average Excess Return is 8.19%

Rolling Average Simple Return = 8.45%

Rolling Averages are based on returns during Jul 08 - Jul 09

Rolling Average Profit is $1,752,362 based on profits from Jul 08 - Jul 09

Jul-08 Aug-08 Sep-08 Oct-08 Nov-08 Dec-08 Jan-09 Feb-09 Mar-09 Apr-09 May-09 Jun-09 Jul-09FTR Count 3,277 4,046 3,928 4,708 3,951 4,002 4,281 3,968 3,912 4,199 4,044 3,769 4,176

Profit $1,909,580 $396,090 $4,036,508 $4,521,762 $545,807 $2,298,640 -$1,925,847 -$1,075,310 $5,793,671 $7,687,467 $2,111,879 -$1,832,579 -$1,686,966Volume 38,790 52,699 45,839 53,173 44,230 45,559 57,883 47,814 43,351 49,146 42,126 38,624 36,997

Congestion Rent

$35,485,792 $37,333,540 $47,229,394 $44,068,127 $30,469,725 $45,361,759 $12,500,800 $10,339,768 $22,055,465 $15,149,948 $16,507,374 $26,043,665 $14,306,475

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Wind UtilizationRegistered Capacity= 4,658 MW

Source: Midwest ISO Real-Time Operations Department

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Wind UtilizationMonthly Energy Contribution from Wind

450 484629

8601,002

1,362 1,276 1,283 1,347 1,3511,246

757 697

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000


Ene

rgy

(GW

h)

*2008 data is based on Settlements and 2009 data is actual ICCP data


Daily Energy Contribution from Wind

0

10

20

30

40

50

60

70

80

7/1

7/2

7/3

7/4

7/5

7/6

7/7

7/8

7/9

7/10

7/11

7/12

7/13

7/14

7/15

7/16

7/17

7/18

7/19

7/20

7/21

7/22

7/23

7/24

7/25

7/26

7/27

7/28

7/29

7/30

7/31

Energy (GWh)

Off‐Peak Peak

19

20.0% 21.4%

29.5%

35.3%37.4%

46.4%

39.7%42.4%

40.3% 41.7%

36.8%

22.6%20.2%

0%

10%

20%

30%

40%

50%

60%


Wind Utilization

0

20

40

60

80

100

7/1

7/2

7/3

7/4

7/5

7/6

7/7

7/8

7/9

7/10

7/11

7/12

7/13

7/14

7/15

7/16

7/17

7/18

7/19

7/20

7/21

7/22

7/23

7/24

7/25

7/26

7/27

7/28

7/29

7/30

7/31

Off-Peak Hours On-Peak HoursPeak Hour Daily Average

Daily Wind Capacity Factor*%

* Wind Capacity factor is calculated by dividing actual generation by the installed capacity.

- Weekends are considered Off-Peak.

Standard Deviationof Peak Hour CapacityFactor = 19.18

Source: Midwest ISO Real-Time Operations Department

Monthly Wind Capacity Factor*

20

Daily Average Generation Outages and De-rates

0

2,000

4,000

6,000

8,000

10,000

12,000

14,000

16,000

18,000

20,000


MW

FORCED PLANNED DERATES

Outages

* Forced Outages include Emergency, Forced and Urgent* Planned Outages include Construction, Future Equipment (MISO internal), and Maintenance

Date of Extraction for July data was Aug 6, 2009.

Source: MISO Outage Scheduler Application

*De-rates after June 1, 2009 are based on limits observed in Real-Time and may reflect normal seasonal de-rates in addition to de-rates for maintenance or other operating conditions.

21

11

0

2

Jul-09 Jun-09

0 - 60 days> 60 days

Transmission Services

143 143

148 164

31742

Jun-09 Jul-09

>19530-195< 30

150

207

150

207

00

Jul-09 Jun-09

AddedProcessedReduction

Monthly Transmission Queue Yearly Transmission Queue*

Current Month-All “Ages”• 188 total added• 170 total processed

MTEP% of project $ on-track

99.6 98.8

Q12009

Q22009

Q32009

Q42009

Completed Studies# of Requests in Study

Source: Midwest ISO Transmission Planning Department

Average days in queue: Less than 1 day

Tariff Requirement: 30 days

0

50

100

150

200

250

300

350

400

450

500

Jul2008


Feb Mar Apr May Jun Jul

Total Processed

Long Term Transmission Service Requests* (excludes abnormally difficult requests)

*June Data includes MidAmerican Transition efforts

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Transmission Services

0

50

100

150

200

250

300

350

400

450

Jul2007


Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan2009

Feb Mar Apr May Jun Jul

# of

Req

uest

s

0

10,000

20,000

30,000

40,000

50,000

60,000

70,000

80,000

90,000

100,000

Siz

e of

Que

ue (M

W)

Number of Requests Size of Queue (MW)

Generation Interconnect Queue – Progress*

0.41.38

2 1.8

4

12

9

13

Resolved New

GW Requests Target

Generation Interconnect Queue – Status*

Source: Midwest ISO Transmission Planning Department

Resolved

New

*June Data includes MidAmerican Transition efforts

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Questions

ATC Customer Meeting · 2009. 8. 19. · Hourly and Monthly FundingNet FTR Shortfall Date of...

Documents

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