TEAC9

TEAC9May 23, 2002

Sheraton Hotel

Springfield, Massachusetts

TEAC9 Agenda• Welcoming Remarks• Transmission Studies

• Technical Session• Upgrade Projects

• Reliability Analysis• Congestion Analysis

New England Transmission Studies

Presented to TEAC

May 23, 2002

Rich Kowalski

RTEP Geographic Scope(2002-2006)

HQ

SEMARI

NORSWCT

BHE

ME

NB

BOST

NH

SME

CMA/NEMA

Adequate

Locked In

Marginal

Deficient

Reliable and Economic Supply:

WMA

VT

NY

CT

Long Mountain Breakers

• Added 2-345kV breakers (4T and 9T)

• Eliminated possibility of “stuck” breaker taking out both the 398 and 352 lines or both the 321 and 352 lines

• These contingencies responsible for the SWCT voltage-limited import capability

Capacitor Additions

• Add 25.2 MVARs @ Rocky River Substation• Add 25.2 MVARs @ Stony Hill Substation• Provides reactive correction to maintain voltage• Normally switched on during periods of high load• Area was susceptible to voltage collapse following

certain contingencies

Glenbrook StatCom• A dynamic reactive compensation device• Provides dynamic, fast-acting reactive

power to maintain constant voltage levels• Works well in an area where the level of

capacitors needed during a contingency to maintain voltage would create high voltage problems during normal operation (Norwalk-Stamford area)

Breaker Conversions• IPT = Independent Pole Tripping = the ability of a single

pole or phase to trip (open) independently of the other poles

• There’s a greater likelihood of the system remaining stable if two phases of a line can remain energized under a line-to-ground fault scenario as compared to the entire line being taken out of service

• 2 breakers @ West Medway have been converted to IPT operation

• Conversions to IPT operation are underway at Sherman Road and Millbury

• 4 breakers at West Walpole to be converted

Interface Changes Considered

Interface

From Limit MW

To Limit MW Date

SWCT Capacitors/Breakers 1700 1850 May-02SWCT Glen Brook Upgrade 1850 2150 May-04SWCT Phase 1 2150 2450 Dec-04SWCT Phase 2 2450 3000 Jan-06East/West study results 2150 950 Jan-02East/West IPT breakers 950 2100 Jun-02SEMA/RI IPT breakers 1600 2200 Jun-02SEMA IPT breakers 1150 1450 Jun-02

Note: Various combinations of interface constraints will be tested in sensitivity cases

RTEP02 Technical Session

• Session Description

• Scheduled for June 17, 2002– 9:30 A.M.– Nation Grid Offices– Energy Institute

Load Forecast UpdateDavid J. Ehrlich

RTEP Assumptions - LoadExhibit 1a: NEPOOL Net Energy for Load History and Forecast (GWH)

RTEP01 (2001 CELT 01-06) vs RTEP02 (2002 CELT 02-06)

106742

111742

116742

121742

126742

131742

136742

141742

1995 1997 1999 2001 2003 2005

RTEP01 RTEP02

RTEP Assumptions - LoadExhibit 1b: NEPOOL Net Energy for Load History and Forecast (GWH)


0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

1996 1998 2000 2002 2004 2006

An

nu

al P

erce

nt

Ch

ang

es

RTEP01 RTEP02

RTEP Assumptions - LoadExhibit 1c: NEPOOL Summer Peak Load History and Forecast (MW)


19618

20618

21618

22618

23618

24618

25618

26618

1995 1997 1999 2001 2003 2005

RTEP01 RTEP02

RTEP Assumptions - Load

Exhibit 1d: NEPOOL Summer Peak Load History and Forecast (MW)RTEP01 (2001 CELT 01-06) vs RTEP02 (2002 CELT 02-06)

1.2

1.7

2.2

2.7

3.2

3.7

4.2

1996 1998 2000 2002 2004 2006

An

nu

al P

erc

en

t C

ha

ng

es

RTEP01 RTEP02

RTEP Assumptions - Load

Exhibit 1e: NEPOOL Winter Peak Load History and Forecast (MW)RTEP01 (2001 CELT 01-06) vs RTEP02 (2002 CELT 02-06)

18563

19563

20563

21563

22563

23563

1995 1997 1999 2001 2003 2005

RTEP01 RTEP02

RTEP Assumptions - LoadExhibit 1f: NEPOOL Winter Peak Load History and Forecast (MW)


-1.0

-0.5

0.0

0.5

1.0

1.5

2.0

2.5

3.0

1996 1998 2000 2002 2004 2006

An

nu

al P

erce

nt

Ch

ang

es

RTEP01 RTEP02

RTEP01 Sub-AreasAs Percent of Sum of Sub-Areas

N-CT 58.5SW-CT 21.5

NorSt 20.0

RTEP01 CompaniesAs a Percent of Sub-Areas

CL&P:N-CT 62.4

CL&P:SW-CT18.4

CL&P:NorSt 19.1

CMEEC:N-CT 68.2CMEEC:SW-CT

21.4

CMEEC:NorSt 10.3

UI:SW-CT 83.2

UI:NorSt 16.8

Sub-Areas as Percent of NEPOOLRTEP01 & Revised RTEP01

R1:N-CT 12.9

R1:SW-CT 10.0

R1:NorSt 4.4

RR1:N-CT 13.8

RR1:SW-CT 8.5

RR1:NorSt 5.0

Sub-Areas as Percent of NEPOOLRevised RTEP01 & RTEP02

RR1:N-CT 13.8

RR1:SW-CT 8.5

RR1:NorSt 5.0 R2:N-CT 13.3

R2:SW-CT 9.2

R2:NorSt 4.7

2002 Coincident Summer Peaks (MW)

2002 Coincident Summer Peaks (MW)

0 500

1000 1500 2000 2500

3000 3500 4000

4500 5000

BH

E

C-M

E

S-M

E

NH

VT

Bost

CN

EM

A

W-M

A

SE

MA

RI

N-C

T

SW

-CT

NO

RS

T

RTEP01 RTEP02

2002 Coincident Winter Peaks (MW)

2002 Coincident Winter Peaks (MW)

0

500

1000

1500

2000

2500

3000

3500

4000

4500

BH

E

C-M

E

S-M

E

NH

VT

Bost

CN

EM

A

W-M

A

SE

MA

RI

N-C

T

SW

-CT

NO

RS

T

RTEP01 RTEP02

RTEP02 2002 SUMMER PEAK LOAD FORECASTS

RTEP02 2002 SUMMER PEAK LOAD FORECASTS

389

1056

598

15241214

4676

20011845

23042009

3215

2233

1136

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

BH

E

C-M

E

S-M

E

NH

VT

Bost

CN

EM

A

W-M

A

SE

MA

RI

N-C

T

SW

-CT

NO

RS

T

RTEP02 2002 WINTER PEAK LOAD FORECASTS

RTEP02 2002 WINTER PEAK LOAD FORECASTS

344

1008

547

14241184

3978

19521706

20941889

2749

1739

857

0

500

1000

1500

2000

2500

3000

3500

4000

4500

BH

E

C-M

E

S-M

E

NH

VT

Bost

CN

EM

A

W-M

A

SE

MA

RI

N-C

T

SW

-CT

NO

RS

T

RTEP02 SUMMER PEAK LOAD FORECASTS AS A PERCENT OF NEPOOL

RTEP02 SUMMER PEAK LOAD FORECASTSAS A PERCENT OF NEPOOL

1.6

4.4

2.5

6.35

19.3

8.37.6

9.58.3

13.3

9.2

4.7

0

2

4

6

8

10

12

14

16

18

20

BH

E

C-M

E

S-M

E

NH

VT

Bost

CN

EM

A

W-M

A

SE

MA

RI

N-C

T

SW

-CT

NO

RS

T

RTEP02 WINTER PEAK LOAD FORECASTS AS A PERCENT OF NEPOOL

RTEP02 WINTER PEAK LOAD FORECASTSAS A PERCENT OF NEPOOL

1.6

4.7

2.5

6.65.5

18.5

9.17.9

9.88.8

12.8

8.1

4

0

2

4

6

8

10

12

14

16

18

20

BH

E

C-M

E

S-M

E

NH

VT

Bost

CN

EM

A

W-M

A

SE

MA

RI

N-C

T

SW

-CT

NO

RS

T

RTEP02 2002 NET ENERGY FOR LOAD (GWH)

RTEP02 2002 NET ENERGY FOR LOAD (GWH)

2026

5750

3176

81966701

23800

110439860

1218710847

16408

10809

5405

0

5000

10000

15000

20000

25000

BH

E

C-M

E

S-M

E

NH

VT

Bost

CN

EM

A

W-M

A

SE

MA

RI

N-C

T

SW

-CT

NO

RS

T

RTEP02 NET ENERGY FOR LOAD FORECAST AS A PERCENT OF NEPOOL

RTEP02 NET ENERGY FOR LOAD FORECASTAS PERCENT OF NEPOOL

1.6

4.6

2.5

6.55.3

18.9

8.87.8

9.78.6

13

8.6

4.3

0

2

4

6

8

10

12

14

16

18

20

BH

E

C-M

E

S-M

E

NH

VT

Bost

CN

EM

A

W-M

A

SE

MA

RI

N-C

T

SW

-CT

NO

RS

T

RTEP02 SUMMER PEAK LOAD FACTOR

RTEP02 SUMMER PEAK LOAD FACTOR

59.5

62.2

60.661.4

63

58.1

63

6160.4

61.6

58.3

55.354.3

59.5

52

54

56

58

60

62

64

66

BH

E

C-M

E

S-M

E

NH

VT

Bost

CN

EM

A

W-M

A

SE

MA

RI

N-C

T

SW

-CT

NO

RS

T

NE

PO

OL

NUMBER OF DAYS AT 90%+ OF SUMMER PEAK

NUMBER OF DAYS AT 90%+ OF SUMMER PEAKOriginal Forecast and 1990-2001 Actuals

7

9

11

13

15

17

19

21

Fcast

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Average Annual

2002 NEPOOL SUMMER DAILY PEAK LOAD FORECAST AS A PERCENT OF SUMMER PEAK

(24,200 MW)

2002 NEPOOL SUMMER DAILY PEAK LOAD FORECASTAS PERCENT OF SUMMER PEAK (24200 MW)

53

63

73

83

93

103

JUN:1 JUL:1 JUL:31 AUG:30

90% Original Revised

States vs RTEP Sub-AreasFERC715 Summer Peak as a Percent of NEPOOL

8.5

1.64.4 2.5

8.3 6.3 4.1 5

45.2

19.3

8.3 7.6 9.56.3 8.3

27.6

13.39.2

4.7

0 5

10 15 20 25 30 35 40 45 50

Reliability Analysis

Presented to TEACMay 23, 2002

Edward Tsikirayi

New England Sub-Area Model

NB

NH

BHEMES-ME

BOSTON

RI SEMACT

SW CTNOR

CMA/NEMA

W-MA

VT

NY

East - WestEast - West

Orring ton SouthOrring ton South

SurowiecSurowiec South SouthME - NHME - NH

North - SouthNorth - South

BostonBoston

SEMA/RISEMA/RISEMASEMA

NY - NENY - NE

South WestSouth WestCTCT

ConnecticutConnecticut

Norwalk - StamfordNorwalk - Stamford

NB - NENB - NEHQ

High gateHigh gate

Phase IIPhase II

CSCCSC

Important Note

• It must noted that this is a Sub-Area Resource Adequacy Assessment which takes into account the effects of static transmission limits simplification between the various sub-areas. Transmission security issues relating to generation and transmission operations and their interdependencies are not modeled in this analysis.

A Result Presented at TEAC 7

• Upgrading the SWCT and CT import interfaces will result in the greatest improvement to NEPOOL system reliability.

Case Outline

• RTEP02 shows the impact of the non-transmission assumption updates( load and generation) when compared to RTEP01.

• RTEP02A shows the impact of increasing the SWCT import limit to 1,850 MW as compared to RTEP02.

• RTEP02B shows the impact of increasing the SWCT import limit to 2,150 MW as compared to RTEP02A.

• RTEP02C shows the impact of further increasing the SWCT import limit to 2,450 MW as compared to RTEP02B.

• RTEP02D shows the impact of the new SEMA, SEMA/RI and East-West transfer limits based on the recent analysis as compared to RTEP02.

• RTEP02E shows the impact of the improvements from the IPT Breaker upgrades as compared to RTEP02D.

• RTEP02F shows what synergies are gained by improving both the SWCT and SEMA/RI transfer limits simultaneously as compared to RTEP02C and E.

Case Assumptions

Case Load Assumptions Capacity Assumptions Interface Assumptions RTEP01 RTEP01 RTEP01 RTEP01 RTEP02 RTEP02 RTEP02 RTEP01

RTEP02A RTEP02 RTEP02 SWCT = 1,700 MW (1/1/02) as per RTEP01SWCT = 1,850 MW (5/1/02) per Long Mt. Area Capacitor BanksSWCT = 1,700 MW (1/1/02) as per RTEP01

RTEP02B RTEP02 RTEP02 SWCT = 1,850 MW (5/1/02) per Long Mt. Area Capacitor BanksSWCT = 2,150 MW (5/1/04) per Glenn Brook StatComSWCT = 1,700 MW (1/1/02) as per RTEP01

RTEP02C RTEP02 RTEP02 SWCT = 1,850 MW (5/1/02) per Long Mt. Area Capacitor BanksSWCT = 2,150 MW (5/1/04) per Glenn Brook StatComSWCT = 2,450 MW (12/1/04) per 345 kV Phase I UpgradeSWCT = 1,700 MW (1/1/02) as per RTEP01

RTEP02D RTEP02 RTEP02 SEMA/RI = 1,600 MW (1/1/02) as per SEMA/RI StudySEMA = 1,150 MW (1/1/02) as per SEMA/RI StudyEast-West = 950 MW (1/1/02) as per SEMA/RI StudySWCT = 1,700 MW (1/1/02) as per RTEP01SEMA/RI = 1,600 MW (1/1/02) as per SEMA/RI StudySEMA/RI = 2,200 MW (6/1/02) as per IPT Breaker Upgrades

RTEP02E RTEP02 RTEP02 SEMA = 1,150 MW (1/1/02) as per SEMA/RI StudySEMA = 1,450 MW (6/1/02) as per IPT Breaker UpgradesEast-West = 950 MW (1/1/02) as per SEMA/RI StudyEast-West = 2,100 MW (6/1/02) as per IPT Breaker UpgradesSWCT = 1,700 MW (1/1/02) as per RTEP01SWCT = 1,850 MW (5/1/02) per Long Mt. Area Capacitor BanksSWCT = 2,150 MW (5/1/04) per Glenn Brook StatCom

RTEP02F RTEP02 RTEP02 SWCT = 2,450 MW (12/1/04) per 345 kV Phase I UpgradeSEMA/RI = 1,600 MW (1/1/02) as per SEMA/RI StudySEMA/RI = 2,200 MW (6/1/02) as per IPT Breaker UpgradesSEMA = 1,150 MW (1/1/02) as per SEMA/RI StudySEMA = 1,450 MW (6/1/02) as per IPT Breaker UpgradesEast-West = 950 MW (1/1/02) as per SEMA/RI StudyEast-West = 2,100 MW (6/1/02) as per IPT Breaker Upgrades

Interface Changes Considered

From ToLimit Limit Date

Interface (MW) (MW)SWCT Capacitors / Breakers 1,700 1,850 May 2002SWCT Glen Brook Upgrade 1,850 2,150 May 2004SWCT Phase 1 2,150 2,450 Dec 2004East / West Study Results 2,150 950 Jan 2002East / West IPT Breakers 950 2,100 Jun 2002SEMA / RI IPT Breakers 1,600 2,200 Jun 2002SEMA IPT Breakers 1,150 1,450 Jun 2002

Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

MARS LOLE ResultsAll Cases – No Unit Retirements

NEPOOL LOLE in Days / YearCase 2002 2003 2004 2005 2006

RTEP02 0.126 0.017 0.015 0.012 0.025RTEP02A 0.034 0.006 0.004 0.004 0.006RTEP02B 0.034 0.006RTEP02C 0.034 0.006RTEP02D 0.126 0.017 0.015 0.012 0.025RTEP02E 0.126 0.017 0.015 0.012 0.025RTEP02F 0.034 0.006


Incremental Reliability Benefit of Capacitor Upgrade *

NEPOOL LOLE in Days / Year2002 2003 2004 2005 2006

RTEP02 LOLE 0.126 0.017 0.015 0.012 0.025RTEP02A LOLE 0.034 0.006 0.004 0.004 0.006Benefit (Days Per Year) 0.092 0.011 0.011 0.008 0.019Benefit (%) 73% 65% 73% 67% 76%

* Upgrade assumed in-service on May 1 2002

Incremental Reliability Benefit of Static Compensator Upgrade *


RTEP02A LOLE 0.034 0.006 0.004 0.004 0.006RTEP02B LOLE 0.034 0.006Benefit (Days Per Year) 0.000 0.000 0.004 0.004 0.006Benefit (%) 0% 0% 100% 100% 100%

* Upgrade assumed in-service on May 1 2004Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

Sensitivity Analysis –Norwalk Harbor 1 and 2 and Cos Cob Unavailable *


RTEP02B 0.034 0.006 0.470 0.669 1.391RTEP02C 0.034 0.006 0.470 0.000 0.001

* Norwalk Harbor 1 and 2 and Cos Cob assumed retired on January 1, 2004


Incremental Reliability Benefit of345 kV Phase I Upgrade* assuming

Norwalk Harbor 1 and 2 andCos Cob Unavailable


RTEP02B LOLE 0.034 0.006 0.470 0.669 1.391RTEP02C LOLE 0.034 0.006 0.470 0.001Benefit (Days Per Year) 0.000 0.000 0.000 0.669 1.390Benefit (%) 0% 0% 0% 100% 100%

* 345 kV Phase I upgrade assumed in-service on December 1, 2004


Devon 7,8 and 10 Deactivation* Scenarios (per 18.4 Application)

* Deactivation assumed effective as of August 1, 2002


Base Case without Devon 7,8 and 10 (SWCT = 1,700 MW) 0.207 0.091 0.088 0.077 0.118Base Case without Devon 7,8 and 10 (1,850 SWCT Upgrade) 0.057 0.029 0.029 0.023 0.040

Base Case without Devon 7,8 and 10 (2,150 MW SWCT Upgrade) 0.057 0.029 0.002 0.002 0.003Base Case without Devon 7,8 and 10 (2,450 MW SWCT Upgrade) 0.057 0.029 0.002## Cases Below Assume Only One Milford Unit is Available in 2003' (Proxy for modelling Loss of Equivalent Megawatts)No 7,8 and 10:1 Milford in '03 ( SWCT = 1,700 MW) 0.783 0.322 0.436 0.453 0.789No 7,8 and 10:1 Milford in '03 (1,850 MW SWCT Upgrade) 0.224 0.110 0.138 0.141 0.237No 7,8 and 10:1 Milford in '03 ( 2,150 MW SWCT Upgrade) 0.224 0.110 0.013 0.011 0.025No 7,8 and 10:1 Milford in '03 ( 2,450 MW SWCT Upgrade) 0.224 0.110 0.013 0.002 0.003


Summary of Findings

• The Long Mountain Breakers & Capacitors and the Glenbrook StatCom upgrades to the SWCT interface will provide short to long term reliability benefits to the NEPOOL system.

• The SWCT Phase I upgrade will provide medium to long term reliability benefits to the NEPOOL system especially in the event of extended outages of generating units.

Next StepsLong Term Reliability Analysis

• 2002 - 2011 MARS

• Generation Assumptions– 2002 - 2006 new units – 2007 - 2011 no retirements/additions– 2 Retirement Sensitivity Cases

• Fossil Steam over 40 years old– Boston -480 MW, WEMA -17MW, NH - 142MW– SWCT - 213MW, SME - 105MW

• Nuclear Retirement Sensitivity – 5 years prior to NRC license expiration

RTEP 02 Congestion Cost Evaluation

Presentation to the Transmission Expansion Advisory CommitteeMay 23, 2002

Wayne CostePrincipal, IREMM, Inc.

Where We Have Been

RTEP01 identified key transmission constraintsIn RTEP01 economic congestion was estimated

- Economic congestion created higher prices for some sub-areas - Interface ratings were significant- Focus was on price volatility during high load periods- Congestion Management System

- Assumed in place at the start of 2002- ARR / FTR revenue reallocation same as RTEP01

- Various assumptions tested using sensitivity cases- Tested the impact on several alternative bidding strategies- Did not include transmission “uplift” (generally off-peak)

TEAC 6 - Illustrated impact of Price Responsive DSM on SWCTTEAC 7 - Illustrated impact of relieving transmission constraints

TEAC7 Interface Relaxation Cases Presented

TEAC7 Evaluated the Impact of Relaxing Interface Constraints

Reference HQ at 1500 MWCase1:SWCT Increased 300 MWCase2: ME/NH Increased 300 MWCase3: ME/NH & SWCT Increased 300 MWCase4: SEMA/RI Increased 600 MWCase5: SEMA/RI Increased 600 MW;ME/NH & SWCT Increased 300 MWCase6: SEMA/RI Increased 600 MW;

ME/NH & SWCT Increased 300 MW;BOST Increased 600 MWCase7: BOST Increased 600 MW

Relieving the SWCT interface showed the greatest benefits

FuelCost Based Bids

West and Bost Higher

0.00

200.00

400.00

600.00

800.00

1000.00

1200.00

1400.00

Fiv

e Y

ear

Co

ng

esti

on

C

ost

s ($

Mill

ion

)

Five Year Congestion Costs

FuelCost Based Bids CT and BOST Higher West and Bost Higher

TEAC7 Congestion Cost for Interface Relaxation ScenariosFive Year Total Congestion Costs by Bid Strategy


Interface Relaxation Benefits using RTEP01 Assumptions

Using RTEP 01 assumptions- Illustrate benefits of constraint relaxation- SWCT import is the most significant constraint- TEAC7 case showed the effect of 300 MW relaxation- New case showing the effect of 450 MW relaxation- These amounts approximate transmission improvements

Preliminary analysis provided insights prior to RTEP02 revisions

Uplift vs. RTEP Congestion Analysis

Historical “uplift” and RTEP congestion are differentBoth represent a cost of managing the transmission systemUplift is paid to local out-of merit generation RTEP congestion based on locational prices

Historical Uplift

- Paid when flagged for transmission and its bid is above ECP- On-peak conditions may require more expensive units- Off-peak conditions may require expensive units be kept on

RTEP congestion only addresses on-peak conditions- Under SMD, “uplift” will continue- Additional “uplift” costs will be incurred that are not in analysis

Total Uplift by Hour For Selected Month

0

50,000

100,000

150,000

200,000

To

tal

Up

lift

Do

llar

s b

y H

ou

r ($

)

Histogram of Uplift Hours Sep-00


0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

To

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Up

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Do

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)

Histogram of Uplift Hours Feb-00


0

50,000

100,000

150,000

200,000

250,000

To

tal

Up

lift

Do

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s b

y H

ou

r ($

)

Histogram of Uplift Hours Dec-00


0

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100,000

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250,000

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Up

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Do

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Histogram of Uplift Hours Jul-00

Historical SWCT Transmission Uplift - Hourly Histograms

February 2000

December 2000September 2000

July 2000


0

300

600

900

1200

1500

Fiv

e Y

ear

Co

ng

esti

on

($

Mil

lio

n)

Fuel BasedBids

BOST/CT BidHigher

West SidBids Higher

Case

SWCT and NOR Congestion (Five Year Million $)RTEP01 Case 5 - No Interface Relaxation

All Other

SWCT and NOR

Congestion From the TEAC7 Reference Case

Fuel Based Bids

BOST/CT Bid Higher

West Sid Bids

HigherNOR & SWCT 521.3 720.8 745.5Other 106.4 569.5 650.5Total 627.7 1290.3 1396


0

300

600

900

1200

1500

Fiv

e Y

ear

Co

ng

esti

on

($

Mil

lio

n)

Fuel BasedBids

BOST/CT BidHigher

West SidBids Higher

Case

SWCT and NOR Congestion (Five Year Million $)RTEP01 Case 5 - SWCT Interface Relaxed 300 MW

All Other

SWCT and NOR

Congestion From with SWCT Relaxed 300 MW

Fuel Based Bids

BOST/CT Bid Higher

West Sid Bids

HigherNOR & SWCT 146.8 272.7 307.4Other 127.4 585.7 653.1Total 274.2 858.4 960.5


0

300

600

900

1200

1500

Fiv

e Y

ear

Co

ng

esti

on

($

Mil

lio

n)

Fuel BasedBids

BOST/CT BidHigher

West SidBids Higher

Case

SWCT and NOR Congestion (Five Year Million $)RTEP01 Case 5 - SWCT Interface Relaxed 450 MW

All Other

SWCT and NOR

Fuel Based Bids

BOST/CT Bid Higher

West Sid Bids

HigherNOR & SWCT 67.8 185.8 225.2Other 98.3 570.3 668.3Total 166.1 756.1 893.5

Congestion From with SWCT Relaxed 450 MW


Preliminary RTEP02 Analysis

Revised assumptions- Used RTEP01Case 5 as the reference case (HQ at 1500 MW)- RTEP02 sub-area loads- RTEP02 fuel prices- RTEP02 resources and future changes

- Existing unit rating changes- Existing unit availability changes (EFOR Immaturity)- Future units included- Future unit in-service dates

- RTEP02 interface rating changes overtime- Fuel cost based bids only for preliminary assessment- Spinning reserve and unit commitment reflected

Preliminary analysis to review impact of revised assumptions

Generating Unit Availability(Percent)

86.468.844.54SYSTEM

94.534.680.83HYDRO

84.889.805.90NUCLEAR

93.753.093.25JET

95.280.534.21DIESEL

85.599.735.19CC

84.128.298.28FOSSIL

EAF ESOF EFOR Type


Unit AvailabilityNew Combined Cycle Units

Non-Weighted AvailabilityYear of Operation Months In-Service EFOR ESOF EAF

First 1 - 12 14.46 17.12 69.50Second 13 - 24 7.92 10.66 83.20

Third 25 - 36 4.78 11.89 83.33TUA 37 - 60 4.49 5.77 90.00


Effect of Changes in Unit Ratings and Capacity

-100.0

0.0

100.0

200.0

300.0

400.0

BH

E

BO

ST

CM

AN

CT

ME

NH

NO

R RI

SE

MA

SM

E

SW

CT

VT

WE

MA

RTEP Sub Area

Ch

ang

e (M

W)

Change in MW Change in Effective MW

Effective Change in Unit Ratings / EFOR

Change = MW * (1-EFOR)Results are based on modeling assumptions and limitations and can be misleading if taken out of context.

• Revisions based on comments at last TEAC

• HQ -Highgate 225 MW

• HQ - Phase II

– Summer (6 months) 1200 MW + 300 MW( CC)

– Winter (6 months) 800 MW + 300MW (CC)

• NB - 400 MW + 300MW(CC)

• NY- 125 MW import from upstate

– 150 MW export (line 1385)

– 300 MW export (CSC)

Interchange Assumptions

Historical and Forecast Imports From New Brunswick

0

100

200

300

400

500

600

700

80010

/1/1

999

1/1/

2000

4/1/

2000

7/1/

2000

10/1

/200

0

1/1/

2001

4/1/

2001

7/1/

2001

10/1

/200

1

1/1/

2002

4/1/

2002

7/1/

2002

10/1

/200

2

1/1/

2003

4/1/

2003

7/1/

2003

10/1

/200

3

Month

Inte

rfch

ang

e F

low

s (M

W)

New Brunswick Import Assumptions - RTEP02 Reference

Price Taker - 400 MW All hoursDispatchable - 300 MW at combined cycle cost


Historical and Forecast Imports From New York

-1000

-500

0

500

1000

1500

200010

/1/1

999

1/1/

2000

4/1/

2000

7/1/

2000

10/1

/200

0

1/1/

2001

4/1/

2001

7/1/

2001

10/1

/200

1

1/1/

2002

4/1/

2002

7/1/

2002

10/1

/200

2

1/1/

2003

4/1/

2003

7/1/

2003

10/1

/200

3

Month

Inte

rfch

ang

e F

low

s (M

W)

New York Import Assumptions - RTEP02 Reference

125 NYPA Import - all hours150 MW export on 1385 resumes June 2002 - weekdays on-peak only

300 MW export on cross sound cable begins November 2002


Historical and Forecast Imports From Hydro-Quebec

0

500

1000

1500

2000

250010

/1/1

999

1/1/

2000

4/1/

2000

7/1/

2000

10/1

/200

0

1/1/

2001

4/1/

2001

7/1/

2001

10/1

/200

1

1/1/

2002

4/1/

2002

7/1/

2002

10/1

/200

2

1/1/

2003

4/1/

2003

7/1/

2003

10/1

/200

3

Month

Inte

rfch

ang

e F

low

s (M

W)

Hydro-Quebec Import Assumptions - RTEP02 Reference

Price Taker - 1200 MW Summer (April-September) 800 MW Winter On-Peak Weekdays onlyDispatchable - 300 MW at combined cycle cost


Congestion Cost Comparison RTEP01 vs. RTEP02

RTEP02 Congestion Cost Estimates for SWCT/NOR

0

100

200

300

400

500

600

RT

EP

01

RT

EP

01+3

00

RT

EP

01+4

50

Ref

eren

ce

Cap

acito

rs

Gle

nBro

ok

Pha

se 1

Sen

-G

lenB

rook

Sen

-Ph

1

Case

Con

gest

ion

Cos

t ($M

illio

n)

Six Year

Five Year

RTEP 01 Assumptions RTEP 02 Assumptions

Case Description Five-Year Six-YearRTEP02 Reference 327 407RTEP02A Capacitors 130 167RTEP02B GlenBrook 98 106RTEP02C Phase1 81 87RTEP02B-1 Sen-GlenBrook 173 214RTEP02C-1 Sen-Ph 1 108 121


Congestion Cost Comparison - East/West Cases

RTEP02 Congestion Cost Estimates for SWCT/NOR

0

100

200

300

400

500

600

700

800

Reference E-W at 950 E-W / SEMA/RI E-W / SEMA/RI /SWCT Phase I

Case

Con

gest

ion

Cos

t ($M

illio

n)

Six Year

Five Year

Case Description Five-Year Six-YearRTEP02 Reference 326.6 407RTEP02D E-W at 950 551.5 689RTEP02E E-W Fixed 305.5 379RTEP02F All Fixed 65.2 68


Case ID Case Name 5 year 6 year 5 year 6 yearRTEP02 Reference 331 419 327 407RTEP02A Capacitors 143 190 130 167RTEP0B Glen Brook 116 136 98 106RTEP02C Phase 1 103 123 81 87RTEP02D East-West at 950 760 951 551 689RTEP02E East-West Fixed 280 350 306 379RTEP02F Everything Fixed 45 47 65 68

RTEP02B-1 Glen Brook Sens 166 207 173 214RTEP02C-1 Phase I Sens 121 144 108 121

New England SWCT/NOR

Summary of New England RTEP02 Congestion Analysis


0100

200300

400

500600

700

800900

1000

Fiv

e Y

ea

r C

on

ge

sti

on

($

Mil

lio

n)

Re

fere

nce

Ca

pa

cito

rs

Gle

n B

roo

k

Ph

ase

1

Ea

st-W

est

at

95

0

Ea

st-W

est

Fix

ed

Eve

ryth

ing

Fix

ed

Gle

n B

roo

k S

en

s

Ph

ase

I S

en

s

Case

SWCT and NOR Congestion (Five Year Million $)

All Other

SWCT and NOR

Summary of New England RTEP02 Congestion Analysis


RTEP Sub-Area Congestion by Year - Reference Case

Slide 1B

HE

ME

SM

E

NH

CM

AN

BO

ST

RI

SE

MA

VT

WE

MA

CT

SW

CT

NO

R

2002

2005-10.0

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0A

nn

ua

l C

on

ge

sti

on

Co

st

($M

illi

on

)

Fuel Cost Based Bids - Congested vs Completely Uncongested

2002

2003

2004

2005

2006

2007

Case: RTEP02


RTEP Sub-Area Congestion by Year - With Capacitors

BH

E

ME

SM

E

NH

CM

AN

BO

ST

RI

SE

MA

VT

WE

MA

CT

SW

CT

NO

R 2002

2005-5.0

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0A

nn

ua

l C

on

ge

sti

on

Co

st

($M

illi

on

)


2002

2003

2004

2005

2006

2007

Case: RTEP02A


RTEP Sub-Area Congestion by Year - With Glen Brook

BH

E

ME

SM

E

NH

CM

AN

BO

ST

RI

SE

MA

VT

WE

MA

CT

SW

CT

NO

R

2002

2005-5.0

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0A

nn

ua

l C

on

ge

sti

on

Co

st

($M

illi

on

)


2002

2003

2004

2005

2006

2007

Case: RTEP02B


RTEP Sub-Area Congestion by Year - With Phase 1

BH

E

ME

SM

E

NH

CM

AN

BO

ST

RI

SE

MA

VT

WE

MA

CT

SW

CT

NO

R

2002

2005-5.0

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0A

nn

ua

l C

on

ge

sti

on

Co

st

($M

illi

on

)


2002

2003

2004

2005

2006

2007

Case: RTEP02C


RTEP Sub-Area Congestion by Year - East-West at 950

BH

E

ME

SM

E

NH

CM

AN

BO

ST

RI

SE

MA

VT

WE

MA

CT

SW

CT

NO

R 2002

2005-20.0

0.0

20.0

40.0

60.0

80.0

100.0A

nn

ua

l Co

ng

es

tio

n C

os

t ($

Mill

ion

)


2002

2003

2004

2005

2006

2007

Case: RTEP02D


RTEP Sub-Area Congestion by Year -SEMA/RI at 2200

Case: RTEP02E

BH

E

ME

SM

E

NH

CM

AN

BO

ST

RI

SE

MA

VT

WE

MA

CT

SW

CT

NO

R 2002

2005-10.0

0.0

10.0

20.0

30.0

40.0

50.0

60.0

70.0

80.0A

nn

ual

Co

ng

esti

on

Co

st

($M

illio

n)

Fuel Cost Based Bids - Congested vs. Completely Uncongested

2002

2003

2004

2005

2006

2007


RTEP Sub-Area Congestion by Year - With Many Fixes

Case: RTEP02F

BH

E

ME

SM

E

NH

CM

AN

BO

ST

RI

SE

MA

VT

WE

MA

CT

SW

CT

NO

R 2002

2005-5.0

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0A

nn

ua

l Co

ng

es

tio

n C

os

t ($

Mill

ion

)


2002

2003

2004

2005

2006

2007


RTEP Sub-Area Congestion by Year - Glen Brook Sensitivity

Case: RTEP02B-1

BH

E

ME

SM

E

NH

CM

AN

BO

ST

RI

SE

MA

VT

WE

MA

CT

SW

CT

NO

R

2002

2005-5.0

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0A

nn

ua

l C

on

ge

sti

on

Co

st

($M

illi

on

)


2002

2003

2004

2005

2006

2007


Case: RTEP02C-1

RTEP Sub-Area Congestion by Year - Phase 1 Sensitivity

BH

E

ME

SM

E

NH

CM

AN

BO

ST

RI

SE

MA

VT

WE

MA

CT

SW

CT

NO

R 2002

2005-5.0

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0A

nn

ua

l C

on

ge

sti

on

Co

st

($M

illi

on

)


2002

2003

2004

2005

2006

2007


NEPOOL Total Congestion Cost as Subarea Loads Increase (Load Increases Are a Proxy For Loss of Generation Resources)

0

100

200

300

400

500

600

700

800

900

1000

-500 0 500 1000 1500 2000 2500 3000

Load Increase (MW)

Co

ng

es

tio

n C

os

t ($

Mill

ion

) BHE

ME

SME

NH

SWCT

CT

WEMA

VT

BOST

CMAN

SEMA

SWCT

BHE

MEVT

CT

BOST

WEMA

CMAN

NH

SME

SEMA

Effect of Changes in Loads on Congestion Costs (2003)

West Side


Effect of Changes in Loads on Congestion Costs (2003)Supplemental Slide

NEPOOL Total Congestion Cost as Subarea Loads Increase (Load Increases Are a Proxy For Loss of Generation Resources)

0

100

200

300

400

500

600

700

800

900

1000

-25% -15% -5% 5% 15% 25% 35% 45% 55% 65% 75%

Load Increase (Percent of Sub-Area Peak Load)

Co

ng

esti

on

Co

st (

$Mill

ion

)

BHE

ME

SME

NH

SWCT

CT

WEMA

VT

BOST

CMAN

SEMA


Load Increases Shown as Effective Capacity Reductions-1700 MW

Effect of Capacity Reductions on SWCT/NOR Congestion2003

Capacity Reductions Occur on Jan 1, 2003SWCT Import Capability at 1700 MW

0

100

200

300

400

500

600

700

0 200 400 600 800 1000

Effective MW of Capacity Reduction

Co

ng

esti

on

Co

st (

$Mill

ion

)

2003 RTEP02 2003 RTEP01 (No Sensitivity Cases)

BOST and CT Bid Higher BOST and West Bids Higher

74 MW of Capacity on Long-Term Outage

Long-Term Outage of450 MW

$68.8 Million in 2003 with RTEP01(No Sensitivity Cases)


Effect of Capacity Reductions on SWCT/NOR Congestion2003

Capacity Reductions Occur on Jan 1, 2003SWCT Import Capability at 1850 MW

0

100

200

300

400

500

600

700

0 200 400 600 800 1000

Effective MW of Capacity Reduction

Co

ng

esti

on

Co

st (

$Mill

ion

)

2003 RTEP02 2003 RTEP01 (No Sensitivity Cases)

BOST and CT Bid Higher BOST and West Bids Higher

74 MW of Capacity on Long-Term Outage

Long-Term Outage of 450 MW

$68.8 Million in 2003 with RTEP01(No Sensitivity Cases)

Load Increases Shown as Effective Capacity Reductions-1850 MW


Emissions Impact Due To Transmission Upgrades

Environmental impact of transmission upgrades required for RTEP

NEPOOL Environmental Planning Committee (EPC) Will review at their June 10 meetingResponsible for NEPOOL emission rate assumptions

Preliminary results have been developedBased on MBtu of generationEPC emission rate assumptionsAssumed compliance with state mandated emission rules

Documents

TEAC9