monthly state of the market report november 2010

Monthly State of the Market Report

November 2010

Published December 17, 2010

SPP Market Monitoring Unit

Table of Contents

Executive Summary .....................................................................................................................................2

Metrics ..........................................................................................................................................................3

Figure 1 – SPP EIS Price Contour Map ...........................................................................................3

Figure 2 – Congestion by Shadow Price Impact – November 2010 ................................................4

Figure 3 – Congestion by Shadow Price Impact – Previous 12 months ..........................................5

Figure 4 – Breached and Binding Flowgates by Interval ................................................................6

Figure 5 – LIP / Gas Cost Comparison ............................................................................................7

Figure 6 – Average Hourly Price by Market Participant – November 2010 ...................................8

Figure 7 – Average Hourly Price by Market Participant – Previous 12 months .............................9

Figure 8 – Regional Monthly Prices ..............................................................................................10

Figure 9 – Energy Generation by Fuel Type .................................................................................11

Figure 10 – Wind Generation & Capacity .....................................................................................12

Figure 11 – Fuel on the Margin .....................................................................................................13

Figure 12 – EIS Settlements - GWh ..............................................................................................14

Figure 13 – EIS Settlements - $ .....................................................................................................15

Figure 14 – Depth of Energy Market for Resources Only – by Status ..........................................16

Figure 15 – Ramp per 100 MW of Online Capacity ......................................................................17

Figure 16 – Monthly Summary of Market Ramp Rate Deficiency ...............................................18

Figure 16a – Timing of Up Ramp Deficiency Intervals ................................................................19

Figure 17 – Dispatchable Range ....................................................................................................20

Figure 18 – Transmission Owner Revenue ....................................................................................21

Figure 19 – Average Transmission Reservations and Schedules ..................................................22

Figure 20 – RNU Components ......................................................................................................23

DISCLAIMER

The data and analysis in this report are provided for informational purposes only and shall not be considered or relied upon as market

advice or market settlement data. The Southwest Power Pool Market Monitoring Unit (SPP MMU) makes no representation or

warranties of any kind, express or implied, with respect to the accuracy or adequacy of the information contained herein.

The SPP MMU shall have no liability to recipients of this information or third parties for the consequences arising from errors or

discrepancies in this information, or for any claim, loss or damage of any kind or nature whatsoever arising out of or in connection

with (i) the deficiency or inadequacy of this information for any purpose, whether or not known or disclosed to the authors, (ii) any

error or discrepancy in this information, (iii) the use of this information, or (iv) a loss of business or other consequential loss or

damage whether or not resulting from any of the foregoing.

Copyright © 2010 by Southwest Power Pool, Inc. All rights reserved.

Southwest Power Pool, Inc. SPP Market Monitoring Unit

Monthly State of the Market Report 2 November 2010

Executive Summary

Wind generation in the SPP Market footprint for November 2010 was at an all-time high, surpassing

the wind generation totals experienced in spring of 2010 (Figure 10). However, the wind capacity

factor of 42% was lower than the all-time high in April 2010 due to new wind resources coming into

the market. Although the SPP market has gained just over 350 MW of additional wind capacity

since the spring, some of these units are still not in commercial operation.

Even though the total system generation in November was nearly the same as October, gas

generation dropped to only 15% of total generation (Figure 9). This is the lowest percentage since

the start of the EIS market.

During November the Up Ramp Deficiencies increased, which appears to be attributed to fewer

resources being online and offering ramp to the market, along with an increase in residential lighting

load. Figure 16a shows the timing of Up Ramp Deficiencies over the past 13 months. In November

2010, most Up Ramp Deficiency intervals were clustered around two daily peak times for winter

months – from 6 – 7 a.m. and from 5 – 6 p.m. Another cluster of Up Ramp Deficiencies occurs

around 10 p.m. when on-peak schedules expire, which then places high ramp demands over a very

short period of time.

Due to one specific ramp deficiency event, all market participants received the high LIP of $294.34

for the month (Figure 6). This occurs due a ramp rate deficiency during a period of no congestion,

causing all market participants to settle at the same LIP. This $294 LIP is also the 12 month high for

many market participants (Figure 7).

The highest area of congestion during November was concentrated in the Texas Panhandle,

specifically around the Randall County Interchange – Palo Duro flowgate (Figure 1). This flowgate

had an average hourly shadow price over $100/MWh and was congested over 71% of all intervals

(Figure 2). The loading on this flowgate is due to typical north-south flow on the western edge of

the SPP footprint. Due to work being done in the area, system configuration changes has caused this

flowgate load up before other flowgates in the area are impacted.

The Dispatchable Range offered by resources made a sharp drop this month after experiencing a

short-term increasing trend since June 2010 (Figure 17). The overall trend for this metric continues

to decrease and continues to be an area of concern for the Market Monitoring Unit.



Metrics

Figure 1 – SPP EIS Price Contour Map

November 2010

12 Month EIS Price Contour Map

500 kV

345 kV

230 kV

161 kV

138 kV

115 kV

69 kV

Oklahoma City

Tulsa

500 kV

345 kV

230 kV

161 kV

138 kV

115 kV

69 kV

Oklahoma City

Tulsa

Kansas City

area

Texas Panhandle

SE Kansas



Figure 2 – Congestion by Shadow Price Impact – November 2010

Region Flowgate Name Flowgate Location (kV)

[Control Area]

Average

Hourly

Shadow

Price

($/MWh)

Total %

Intervals

(Breached

or Binding)

Detailed Description

Texas

Panhandle

RANPALAMASWI

Randall County - Palo Duro

(115) ftlo Amarillo – Swisher (230) [SPS]

$ 100.87 71.1%

Congestion due to high N-S flow. Breaches generally occur in this area with high fluctuating wind along

with limited transmission capability available.

TEMP12_16700 Tolk – Tuco (230) ftlo Tolk –

Yoakum (230) $ 3.91 4.6%

ELKXFRTUCOKU

Elk City XFR (230/138)

[CSWS] ftlo Tuco – Oklaunion (345) [SPS-

CSWS]

$ 1.61 3.1%

Kansas City

Area

IATXFRIATSTR

Iatan XFR () [KCPL] ftlo Lake Road – Iatan – Stranger

(345) KCPL] $ 14.79 5.4%

Heavy North – South flow from Nebraska into Kansas

with high external impacts and high market flow in the

Kansas City load pocket.

IASCLKNASJHA

Iatan – Stranger Creek (345)[KCPL] ftlo Lake Road

– Nashua (161), St. Joe –

Hawthorne (345) [GMOC-KCPL]

$ 4.38 2.4%

TEMP17_16702

TWA – Roanridge (161) ftlo Stranger – Craig (345)

[KCPL] $ 3.70 0.3%

SE Kansas

TEMP10_16663

Neosho – Columbus [WR-

EDE] (161) ftlo Asbury –

Purcell [EDE] (161) $ 6.24 4.0%

Due to the outages of: 161 kV transmission line in the region.

NEOCOLNEODEL

Neosho - Columbus [WR-

EDE] (161) ftlo Neosho -

Delaware (345) [WR-CSWS] $ 6.55 2.0%

SW Nebraska GENTLMREDWIL Gentleman – Red Willow

(345) [NPPD] $ 5.59 13.1%

Congestion in Kansas City with the addition of

multiple 345 kV transmission line outages over the

month that caused additional flow and external flow on

the flowgate.

SW Kansas HOLPLYHOLSPE

Holcomb – Plymell Switch (115) ftlo Holcomb -

Spearville (345) [SECI] $ 1.46 0.3%

345 kV transmission line tripped for a day that caused

additional flow on the flowgate.

0%

20%

40%

60%

80%

100%

$0

$20

$40

$60

$80

$100

%T

ota

l In

terv

als

Co

ng

este

d

Avera

ge H

ou

rly S

had

ow

Pri

ce

($/M

Wh

)

Average Hourly Shadow Price ($/MWh) % Total Intervals Congested



Figure 3 – Congestion by Shadow Price Impact – Previous 12 months

Region Flowgate Name Flowgate Location (kV)

Average

Hourly

Shadow

Price

($/MWh)

Total %

Intervals

(Breached or

Binding)

Projects Expected to Provide Some

Positive Mitigation

(Estimated In Service Date –

Upgrade Type)

Texas

Panhandle

OSGCANBUSDEA

Osage Switch - Canyon East [SPS]

[(115) ftlo Bushland - Deaf Smith [SPS] (230)

$ 26.76 17.7%

1. Tuco Int. – Woodward 345 kV line (May 2014 - Balanced Portfolio)

2. Castro County Int. – Newhart 115 kV line (April

2015 - Regional Reliability)

RANPALAMASWI

Randall County - Palo Duro (115)

ftlo Amarillo – Swisher (230)

[SPS] $20.24 12.3%

1. Rebuild Randall Co–Palo Duro 115 kV line (April

2014 - no NTC but is Sponsored)

2. Tuco Int. – Woodward 345 kV line (May 2014 - Balanced Portfolio)

3. Swisher Co. Int. – Newhart 230 kV line (April 2015

- Regional Reliability)

SE

Oklahoma LONSARPITVAL

Lone Oak to Sardis [CSWS] (138)

ftlo Pittsburg – Valiant [CSWS] (345)

$ 11.98 2.9% 1. Sunnyside – Hugo – Valliant 345 kV line (April

2012 - Transmission Service)

SE Kansas NEOCOLNEOMOR

Neosho - Columbus [WR-EDE]

(161) ftlo Neosho - Morgan (345)

[WR-AECI] $ 11.52 2.1%

1. Rose Hill – Sooner – Cleveland 345 kV lines (Dec

2012 – Regional Reliability/Balanced Portfolio) 2. Two Woodward – Medicine Lodge – Wichita 345

kV lines (Dec 2014 - Priority Projects)

Kansas City Area

PLAKCISTRCRA

Platte City – KCI (161)[GMOC] ftlo Stranger Creek – Craig (115)

[KCPL] $ 9.27 1.4%

1. Iatan – Nashua 345 kV line (June 2015 - Balanced

Portfolio)

2. Nebraska City – Maryville – Sibley 345 kV line (June 2017 - Priority Projects)

LAKALASTJHAW

Lake Road – Alabama [GMOC]

(161) ftlo St. Joe – Hawthorn [GMOC] (345)

$ 9.09 1.5%

1. Axtell–Post Rock–Spearville 345 kV line, two

Spearville – Comanche – Woodward 345 kV lines, and two Comanche – Medicine Lodge – Wichita

345 kV lines (12/31/2014 - Balanced

Portfolio/Priority Projects) 2. Iatan – Nashua 345 kV line (June 2015 - Balanced

Portfolio)

3. Nebraska City – Maryville – Sibley 345 kV line (June 2017 - Priority Projects)

LAKALAIATSTR

Lake Road – Alabama [GMOC]

(161) ftlo Iatan to Stranger Creek [KCPL] (345)

$ 8.61 2.1% Same as LAKALASTJHAW above

Wichita

Area ELPFARWICWDR

El Paso – Farber [WR] (138) ftlo

Wichita – Woodring [WR-OGE] (345)

$ 7.50 5.0%

1. Rose Hill – Sooner 345 kV line (June 2012 -

Regional Reliability)

2. Two Woodward – Comanche Co. – Medicine Lodge – Wichita 345 kV lines (Dec 2014 - Priority

Projects)

SW Kansas HOLPLYHOLSPE

Holcomb – Plymell Switch [SECI]

(115) ftlo Holcomb - Spearville [SECI] (345)

$ 6.15 1.9% 1. Rebuild Holcomb – Plymell Switch 115 kV line

(Dec 2011 - Regional Reliability)

NE Kansas KELSENEMACON

Kelly – S. Seneca (115) [WR] ftlo

E. Manhattan – Concordia (230) [WR-SECI]

$ 4.48 2.9%

1. Rebuild Kelly – Seneca 115 kV line (Dec 2010 - Regional Reliability)

2. Axtell–Post Rock–Spearville 345 kV line, two

Spearville – Comanche – Medicine Lodge –Woodward 345 kV lines, and two Medicine Lodge –

Wichita 345 kV lines (Dec 2014 - Balanced

Portfolio/Priority Projects)



Figure 4 – Breached and Binding Flowgates by Interval

intervals Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

last 12

months

%

Breached 3.2% 6.6% 3.4% 2.6% 6.8% 10.6% 7.5% 6.1% 4.4% 7.5% 6.7% 3.4% 3.1% 5.7%

% Binding 54.7% 59.4% 41.5% 48.8% 74.4% 82.5% 68.9% 55.3% 56.5% 76.7% 72.9% 72.3% 82.1% 66.0%

Source: OBIEE/MOS

0%

5%

10%

15%

% D

isp

atc

h I

nte

rvals

Bre

ach

ed

% Intervals Breached

0%

20%

40%

60%

80%

100%

% D

isp

atc

h I

nte

rvals

Bin

din

g

% Intervals Binding



Figure 5 – LIP / Gas Cost Comparison

Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

12 month

average

Electricity

(LIP)

[$/MWh] 28.29 37.86 42.18 40.56 27.72 27.06 27.69 33.05 34.75 35.92 26.82 25.89 24.63 31.99

Gas

Panhandle

[$/MMBtu] 3.48 5.21 5.72 5.22 4.17 3.78 3.91 4.52 4.28 3.89 3.63 3.24 3.54 4.26

$20

$30

$40

$50

$2

$4

$6

$8

Ele

ctr

icit

y P

rice (

LIP

)

Gas C

ost

Gas (Panhandle) Electricity (LIP)



Figure 6 – Average Hourly Price by Market Participant – November 2010

in $ AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN KBPU KCPS KPP LESM MEAN MIDW OGE OMPA OPPM SECI SPSM TEAN WFES WRGS

Max 294 294 294 294 294 294 294 294 294 294 294 294 294 294 294 294 294 294 294 294 294 294

Avg 26 25 20 27 23 26 29 24 25 25 25 20 20 24 25 26 20 23 27 20 25 25

Min -33 -36 -365 -30 -159 -26 3 -44 -17 -21 -12 -465 -416 -50 -28 -26 -466 -80 -34 -414 -28 -10

AECC

AEPM

BEPM

EDEP

GMOC

GRDX

GSEC

INDN

KBPUKCPS KPP

LESMMEAN

MIDW

OGE OMPA

OPPM

SECI

SPSM

TEAN

WFES

WRGS24.63

$15

$20

$25

$30

$35

AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN KBPU KCPS KPP LESM MEAN MIDW OGE OMPA OPPM SECI SPSM TEAN WFES WRGS

$15

$20

$25

$30

$35

Pri

ces (

$/M

Wh

)

Market Participant

MP Average SPP Average



Figure 7 – Average Hourly Price by Market Participant – Previous 12 months

in $ AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN KBPU KCPS KPP LESM MEAN MIDW OGE OMPA OPPM SECI SPSM TEAN WFES WRGS

Max 323 346 294 532 381 330 1,169 294 294 294 294 294 294 304 299 301 294 294 1,199 294 302 294

Avg 34 33 26 36 30 33 36 32 32 32 31 26 26 30 33 33 26 31 35 26 33 31

Min -117 -103 -365 -178 -246 -161 -471 -175 -174 -174 -168 -465 -416 -238 -143 -127 -466 -198 -494 -414 -123 -171

AECCAEPM

BEPM

EDEP

GMOC

GRDX

GSEC

INDN

KBPU

KCPS

KPP

LESMMEAN

MIDW

OGE OMPA

OPPM

SECI

SPSM

TEAN

WFES

WRGS

31.99

$20

$30

$40

AECC AEPM BEPM EDEP GMOC GRDX GSEC INDN KBPU KCPS KPP LESM MEAN MIDW OGE OMPA OPPM SECI SPSM TEAN WFES WRGS

$20

$30

$40

Pri

ces (

$/M

Wh

)

Market Participant

For 12 months ending November 2010

MP Average SPP Average



Figure 8 – Regional Monthly Prices

Region Average Price Maximum

Price Minimum Price Volatility

Average On-

Peak Price

Average

Off-Peak

Price

SPP $ 24.63 $ 294.34 $ -51.69 75% $ 29.45 $ 20.41

MISO $ 27.61 $ 129.74 $ -18.82 53% $ 33.19 $ 22.73

ERCOT $ 23.40 $ 469.71 $ -25.54 118% $ 27.95 $ 19.42

Note: This table is a “rough comparison” because of inherent differences in the structure of the three markets and also because of the differences in how prices for SPP, MISO, and ERCOT are calculated. For SPP, load weighted averages are used, while the data from MISO and ERCOT are not load weighted. Volatility is measured by the Coefficient of Variation, which is the standard deviation across all hours divided by the average of all hours.

$0

$10

$20

$30

$40

$50

$60

Nov 09 Dec 09 Jan 10 Feb 10 Mar 10 Apr 10 May 10 Jun 10 Jul 10 Aug 10 Sep 10 Oct 10 Nov 10

$/M

Wh

SPP MISO ERCOT

0%

50%

100%

150%

200%

Nov 09 Dec 09 Jan 10 Feb 10 Mar 10 Apr 10 May 10 Jun 10 Jul 10 Aug 10 Sep 10 Oct 10 Nov 10

Regional Price Volatility

SPP Volatility

MISO Volatility

ERCOT Volatility



Figure 9 – Energy Generation by Fuel Type

in GWh Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

Coal 11,294 12,952 12,198 11,317 11,277 9,828 10,871 12,542 13,373 14,167 11,716 10,309 10,889

Gas 2,646 3,943 4,459 3,630 2,858 2,931 3,859 5,934 6,846 7,748 4,535 3,691 2,427

Nuclear 519 1,556 1,814 1,664 1,599 1,716 1,819 1,718 1,802 1,800 1,770 1,392 1,789

Wind 840 849 747 502 1,069 1,091 909 939 768 770 867 870 1,132

Hydro 180 95 147 166 169 160 185 200 227 124 121 75 95

Other 13 12 13 17 21 17 17 22 19 21 20 21 20

Total 15,492 19,407 19,378 17,296 16,993 15,743 17,661 21,356 23,034 24,630 19,029 16,358 16,352

by % Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

12

month

average

Coal 73% 67% 63% 65% 66% 62% 62% 59% 58% 58% 62% 63% 67% 63%

Gas 17% 20% 23% 21% 17% 19% 22% 28% 30% 31% 24% 23% 15% 23%

Nuclear 3% 8% 9% 10% 9% 11% 10% 8% 8% 7% 9% 9% 11% 9%

Wind 5% 4% 4% 3% 6% 7% 5% 4% 3% 3% 5% 5% 7% 5%

Hydro 1% 0% 1% 1% 1% 1% 1% 1% 1% 1% 1% 0% 1% 1%

Other 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Source: OBIEE/MOS

0

5,000

10,000

15,000

20,000

25,000

Nov 08

Dec 08

Jan 09

Feb 09

Mar 09

Apr 09

May 09

Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

Jul 10

Aug 10

Sep 10

Oct 10

Nov 10

Gen

era

tio

n (

GW

h)

Other Hydro Wind Nuclear Gas Coal



Figure 10 – Wind Generation & Capacity

Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

Capacity

(MW) 3,202 3,313 3,313 3,313 3,313 3,381 3,381 3,402 3,402 3,402 3,402 3,735 3,735

Generation

(GWh) 840 849 747 502 1,069 1,091 909 945 768 770 867 870 1,132

Capacity

Factor 36% 34% 30% 23% 43% 45% 36% 39% 30% 30% 35% 31% 42%

# of

Resources 49 51 51 51 51 53 53 54 54 54 54 57 57

Source: OBIEE/MOS

0

500

1,000

1,500

2,000

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Win

d G

en

era

tio

n (

GW

h)

Win

d C

ap

acit

y (M

W)

Wind Capacity (MW) Wind Generation (GWh)



Figure 11 – Fuel on the Margin

Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

last 12

months

Other 0.0% 0.3% 0.1% 0.0% 0.2% 0.5% 0.9% 0.3% 0.0% 0.2% 0.6% 0.2% 0.3% 0.3%

Coal 39.5% 31.9% 29.9% 25.6% 41.9% 43.8% 46.6% 40.4% 32.0% 33.5% 40.7% 35.5% 44.4% 37.2%

Gas 60.5% 67.9% 70.0% 74.4% 57.8% 55.7% 52.5% 59.3% 68.0% 66.3% 58.7% 64.4% 55.4% 62.5%

Source: OBIEE/MOS

Note:

During non-congested periods, one resource sets the price for the entire market.

During congested periods, the market is effectively segmented into several sub-areas,

each with its own marginal resource. Each congested interval counts the same as a

non-congested period, but the marginal fuel type for each sub-area is represented

proportionally in the congested period.

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al

Co

al Co

al

Co

al C

oal

Gas

Gas

Gas

Gas

Gas G

as

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas

Gas G

as

Gas

Gas

0%

20%

40%

60%

80%

100%



Figure 12 – EIS Settlements - GWh

in GWh Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

Resource EI 2,483 2,840 2,805 2,159 2,565 2,597 2,770 2,980 3,004 3,098 2,817 2,486 2,527

Load EI 546 642 623 532 551 550 582 669 748 699 638 594 617

Scheduled

Transaction 27,970 35,158 35,469 31,864 30,644 27,817 31,477 38,975 42,303 45,290 34,216 29,275 29,175

Total Energy 31,000 38,641 38,896 34,555 33,760 30,964 34,829 42,625 46,056 49,087 37,671 32,355 32,319

by % Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

Last 12

Months

Resource EI 8.0% 7.3% 7.2% 6.2% 7.6% 8.4% 8.0% 7.0% 6.5% 6.3% 7.5% 7.7% 7.8% 7.2%

Load EI 1.8% 1.7% 1.6% 1.5% 1.6% 1.8% 1.7% 1.6% 1.6% 1.4% 1.7% 1.8% 1.9% 1.6%

Scheduled

Transactions 90.2% 91.0% 91.2% 92.2% 90.8% 89.8% 90.4% 91.4% 91.9% 92.3% 90.8% 90.5% 90.3% 91.1%

Totals may not equal 100% due to rounding.

0%

5%

10%

15%

20%

25%

0

10,000

20,000

30,000

40,000

50,000

EIS

Tra

nsacti

on

s a

s %

of

To

tal

GW

h

Scheduled Transactions (GWh) Load EI GWh Resource EI GWh % EIS Transactions



Figure 13 – EIS Settlements - $

in million $ Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

12 Month

Average

Resource EI 70 107 122 87 76 73 77 97 103 109 79 64 61 88

Load EI 16 26 28 23 17 17 17 23 27 27 18 16 16 21

Total EI 85 133 150 111 93 90 95 121 130 136 107 80 77 109

$0

$100

$200

Mil

lio

ns

Resource EI Load EI



Figure 14 – Depth of Energy Market for Resources Only – by Status

in GWh Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

Market Dispatch 12,733 15,490 15,139 13,699 13,020 11,758 13,450 16,613 18,648 20,095 14,790 12,583 12,007

Self-Dispatch 534 470 407 336 399 326 328 749 585 647 559 269 215

Nuclear 514 1,561 1,832 1,675 1,614 1,734 1,821 1,723 1,807 1,803 1,770 1,393 1,798

Manual

(intermittent) 922 898 833 573 1,175 1,181 1,027 1,058 896 886 971 963 1,233

Manual (other) 811 1,052 1,369 1,119 974 908 1,122 1,334 1,213 1,317 1,039 1,242 1,223

Other (6) 4 (2) (7) (9) (4) (8) (6) (5) (2) (9) (19) (19)

TOTAL 15,549 19,475 19,578 17,395 17,174 15,903 17,741 21,470 23,144 24,745 19,121 16,431 16,457

by % of total

Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

Last 12

Months

Market

Dispatch 82% 80% 77% 79% 76% 74% 76% 77% 81% 81% 78% 77% 73% 78%

Self-Dispatch 3% 2% 2% 2% 2% 2% 2% 3% 3% 3% 3% 2% 1% 2%

Nuclear 3% 8% 9% 10% 9% 11% 10% 8% 8% 7% 8% 8% 11% 8%

Manual

(intermittent) 6% 5% 4% 3% 7% 7% 6% 5% 4% 4% 5% 6% 7% 5%

Manual (other) 5% 5% 7% 6% 6% 6% 6% 6% 5% 5% 6% 8% 7% 6%

Other 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Note: May not total to 100% due to rounding. Source: MOS

-

5,000

10,000

15,000

20,000

25,000

GW

h P

rod

ucti

on

Other Manual (other) Manual (intermittent) Nuclear Self-Dispatch Market Dispatch



Figure 15 – Ramp per 100 MW of Online Capacity

Offered and Available to the EIS Market

Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

12 month

average

MW / Minute /

100 MW of

Online Capacity 0.83 0.80 0.81 0.79 0.79 0.79 0.80 0.88 0.94 0.96 0.85 0.83 0.83 0.84

Average Online

Capacity (GW)

per Interval 27.2 31.9 32.5 31.6 28.6 27.6 30.8 37.6 38.8 40.9 34.2 29.7 26.6 32.6

-

10

20

30

40

0.5

0.6

0.7

0.8

0.9

1.0

1.1

1.2

1.3

1.4

Avera

ge O

nli

ne C

ap

acit

y (

GW

) p

er

Inte

rval

MW

/ M

inu

te /

100 M

W o

f O

nli

ne C

ap

acit

y

Available Online Capacity MW / Min Offered / 100 MW of Online Capacity



Figure 16 – Monthly Summary of Market Ramp Rate Deficiency

Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

12 month

average

UP Ramp

Deficiency

Intervals 43 35 25 22 11 2 16 6 1 14 9 10 66 18

DOWN Ramp

Deficiency

Intervals 5 0 0 0 3 16 35 14 0 8 8 4 6 8

Total Ramp

Deficiency

Intervals 48 35 25 22 14 18 51 20 1 22 17 14 72 26

% of Total

Market

Dispatch

Intervals

0.6% 0.4% 0.3% 0.3% 0.2% 0.2% 0.6% 0.2% 0.0% 0.2% 0.2% 0.2% 0.8% 0.3%

MW Ramp

Available per

Minute 224 256 263 249 227 219 254 331 365 393 290 245 221 276

-

40

80

120

160

200

240

280

320

360

400

-

20

40

60

80

100

MW

Ram

p A

vail

ab

le p

er

Min

ute

Ram

p D

efi

cie

ncy I

nte

rvals

UP Ramp Deficiency Intervals DOWN Ramp Deficiency Intervals Total MW Ramp Available per Minute



Figure 16a – Timing of Up Ramp Deficiency Intervals

Past 13 months

November 2010

00010203040506070809101112131415161718192021222300

Nov-09 Dec-09 Jan-10 Feb-10 Mar-10 Apr-10 May-10 Jun-10 Jul-10 Aug-10 Sep-10 Oct-10 Nov-10 Dec-10

Hour

00010203040506070809101112131415161718192021222300

11/1/10

11/2/10

11/3/10

11/4/10

11/5/10

11/6/10

11/7/10

11/8/10

11/9/10

11/10/10

11/11/10

11/12/10

11/13/10

11/14/10

11/15/10

11/16/10

11/17/10

11/18/10

11/19/10

11/20/10

11/21/10

11/22/10

11/23/10

11/24/10

11/25/10

11/26/10

11/27/10

11/28/10

11/29/10

11/30/10

Hour



Figure 17 – Dispatchable Range

Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

last 12

mo

Average 39.2% 37.8% 36.9% 36.2% 36.2% 35.4% 37.4% 34.7% 36.6% 36.0% 37.6% 38.4% 35.0% 36.5%

Dispatchable Range is calculated as the average dispatachable range available (in

MW) divided by the average of the daily peak demand (MW) for the month.

32%

36%

40%

44%

Avg Dispatchable Range / Peak Demand Linear (Avg Dispatchable Range / Peak Demand)



Figure 18 – Transmission Owner Revenue

in millions $ JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC

2008 32.1 34.6 33.1 33.0 32.9 32.1 32.6 33.8 37.7 34.7 35.0 36.3

2009 35.7 34.2 33.4 43.8 41.0 43.1 43.4 43.7 42.7 41.3 40.0 43.5

2010 44.7 43.9 46.6 54.3 52.0 52.3 53.8 65.1 55.8 52.9 52.5

$0

$10

$20

$30

$40

$50

$60

$70

Mil

lio

ns



Figure 19 – Average Transmission Reservations and Schedules

in thousands

MWh Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

12 month

average

Average Daily

Reservations 382 445 485 496 482 469 476 536 552 534 494 484 485 495

Average Daily

Schedules 74 110 113 119 93 96 101 117 112 112 98 95 93 105

% 19% 25% 23% 24% 19% 21% 21% 22% 20% 21% 20% 20% 19% 21%

0%

10%

20%

30%

40%

50%

60%

0

100

200

300

400

500

600

Oct 08

Nov 08

Dec 08

Jan 09

Feb 09

Mar 09

Apr 09

May 09

Jun 09

Jul 09

Aug 09

Sep 09

Oct 09

Nov 09

Dec 09

Jan 10

Feb 10

Mar 10

Apr 10

May 10

Jun 10

Jul 10

Aug 10

Sep 10

Oct 10

Th

ou

san

ds M

Wh

Avg. Daily Transmission Reservations Schedules as a % of Reservations



Figure 20 – RNU Components

$ (thousands) Nov

09

Dec

09

Jan

10

Feb

10

Mar

10

Apr

10

May

10

Jun

10

Jul

10

Aug

10

Sep

10

Oct

10

Nov

10

EIS -245 -923 -1,166 1,347 589 2,617 1,564 -750 -530 -14 -686 132 -803

O/S -99 -101 -45 -26 -96 -113 -92 -101 -32 -151 -130 -44 -127

U/S -177 -257 -91 -52 -78 -112 -141 -71 -100 -140 -88 -38 -122

UDC -56 -136 -138 -81 -35 -48 -62 -98 -95 -109 -48 -29 -22

SP Loss -2 -17 -5 -6 -3 -27 -4 1 7 9 2 -12 -2

Total RNU -579 -1,434 -1,444 1,181 377 2,319 1,265 -1,018 -750 -404 -950 9 -1,078

EIS (Energy Imbalance Charge/Credit) – All energy deviations between actual generation or load and schedules are settled as (EIS).

O/S (Over-Scheduling Charge) - During any hour, if Locational Imbalance Prices diverge and a Market Participant’s Load imbalance is more than 4% (but at least 2 MW) at an applicable Settlement Location in that hour, that MP may be subject to an Over-Scheduling Charge.

U/S (Under-Scheduling Charge) - During any hour, if Locational Imbalance Prices diverge and a Market Participant’s Load imbalance is more than 4% (but at least 2 MW) at an applicable Settlement Location in that hour, that MP may be subject to an Under-Scheduling Charge.

UDC (Uninstructed Resource Deviation) – the difference between the dispatch instructions and the actual performance of a Resource.

SP Loss - Self-Provided Losses

-$4

-$2

$0

$2

$4

Mil

lio

ns

SP LOSS UDC U/S O/S EIS Total RNU

monthly state of the market report november 2010

Documents