nepool participants committee boston, ma october 1, 2004

NEPOOL Participants Committee

Boston, MA

October 1, 2004

Stephen G. WhitleySenior Vice President & COO

2

• System Operations• Market Operations• Cold Snap Task Force• Winter 2004/2005 Outlook• Back-Up Detail

Agenda

3

System Operations

4

Operations Highlights

• Boston & Hartford Weather Pattern: – Temperatures were near normal with double the normal precipitation during

September due to two (2) tropical storms.• Peak load of 20,829 MW at 20:00 hours on September 9, 2004.• During September:

– NPCC Shared Activation of Reserve Events:• September 1 L/O Indian Point #2 1050 Mw• September 9 L/O Salem #21150 Mw• September 15 L/O Mystic # 8 & 9 1350 Mw• September 24 L/O Indian Point #2 950 Mw

– Minimum Generation:• September 7, 19, 20 and 21.

5

Market Operations

6

Day–Ahead & Real-Time Prices, ISO Hub:

7

Day-Ahead–LMP Average by Zone & Hub:

LMP Marginal Loss Component Congestion Component

September 1, 2004 to September – 22, 2004

(-13.73%)(-5.93%) (-0.76%)

(2.56%)

(-1.47%)

(-1.86%)

(-1.09%)

(-1.19%)

8

97.4%

Real-Time-LMP Average by Zone & Hub:

LMP Marginal Loss Component Congestion Component

(-13.07%)

(-1.54%)

(2.83%) (-1.28%)

(-1.67%)

(1.91%) (-1.12%)(-6.55%)

September 1, 2004 to September – 22, 2004

9

Day-Ahead Market vs. Forecast Load

Day Ahead Market Generation Cleared vs. Forecast Load (%)

92 91 94

0

20

40

60

80

100

July August September

September data represents September 1-September 22

Day Ahead Market Demand Cleared vs. Forecast Load (%)

99 99 102

020406080

100120

July August September

September data represents September 1-September 22

10

Day-Ahead LMPDAM LMP Through September 23, 2004

10

20

30

40

50

60

70

80

90

09/01

/2004

01

09/03

/2004

01

09/05

/2004

01

09/07

/2004

01

09/09

/2004

01

09/11

/2004

01

09/13

/2004

01

09/15

/2004

01

09/17

/2004

01

09/19

/2004

01

09/21

/2004

01

09/23

/2004

01

Day

$/M

Wh

INTERNAL_HUB CONNECTICUT MAINE NEMASSBOST NEWHAMPSHIRE

RHODEISLAND SEMASS VERMONT WCMASS

CT IMPORT INTERFACE CONSTRAINT BINDING DUE TO LOAD/GENERATION PATTERN.

11

Real-Time LMPReal-Time LMP Through September 23, 2004

0

20

40

60

80

100

09/01

/200

4 01

09/03

/200

4 01

09/05

/200

4 01

09/07

/200

4 01

09/09

/200

4 01

09/11

/200

4 01

09/13

/200

4 01

09/15

/200

4 01

09/17

/200

4 01

09/19

/200

4 01

09/21

/200

4 01

09/23

/200

4 01

Day

$/M

Wh

INTERNAL_HUB CONNECTICUT MAINE NEMASSBOST NEWHAMPSHIRE

RHODEISLAND SEMASS VERMONT WCMASS

MINIMUM GENERATION EMERGENCY

NRST INTERFACE CONSTRAINED DUE TO LOAD/GENERATION PATTERN.

1845 LINE CONSTRAINT BINDING DUE TO LACK OF GENERATION ON IN WMASS

NRST INTERFACE CONSTRAINED DUE TO 1416 LINE OOS.

12

Settlement Data – Real-Time & Balancing MarketPercentage of Real-Time Load Fully Hedged Through ISO-NE

Settlement System

Month

% R

T L

oa

d F

ull

y H

ed

ge

d

Note: Partial Data (September 1-20, 2004)

72%70%70%

73% 73%

75% 75% 75%

73%

71%72%

70% 71%

68%

71%

77%

74%73%

71%

50%

55%

60%

65%

70%

75%

80%

Apr 0

2 - M

ar 0

3 Ave

rage

Apr-0

3

May

-03

Jun-

03

Jul-0

3

Aug-0

3

Sep-0

3

Oct-03

Nov-0

3

Dec-0

3

Jan-

04

Feb-0

4

Mar

-04

Apr-0

4

May

-04

Jun-

04

Jul-0

4

Aug-0

4

Sep-0

4

13

RMR and Economic Operating Reserve Payments

RMR and Economic Operating Reserve Payments

$0

$2,500,000

$5,000,000

$7,500,000

$10,000,000

$12,500,000

$15,000,000

$17,500,000

$20,000,000

Jan-

04

Feb-

04

Mar

-04

Apr-0

4

May

-04

Jun-

04

Jul-0

4

Aug-0

4

DA RMR DA Economic RT RMR RT EconomicNote: May-August subject to 90-Day Resettlement

14

Monthly VAR Support and SCR Payments

Monthly VAR Support and SCR Payments

$0

$1,000,000

$2,000,000

$3,000,000

$4,000,000

$5,000,000

$6,000,000

$7,000,000

$8,000,000

$9,000,000

$10,000,000

Jan-

04

Feb-

04

Mar

-04

Apr-0

4

May

-04

Jun-

04

Jul-0

4

Aug-0

4

DA VAR RT VAR RT SCR

15

August 2004

$0

$100

$200

$300

$400

$500

$600

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31

Th

ou

sa

nd

s

CT NEMA WCMA

Real-Time Reliability Must Run Credits per Reliability Region

16

Cold Snap Task Force

17

Cold Snap

Three high-priority, short-term objectives targeted for implementation prior to winter 2004/2005:

1) Electric Market Synchronization with Gas Market• ISO & NEPOOL Cold Snap Task Force (CSTF) –

Finalized proposal with NEPOOL MC & RC2) Electric/Gas Operating Committee

• Education, Understanding, Coordination, Communications

3) Investigate True Dual Fuel Capability & Promote Expansion

• ESS Group – Environmental Consultants

18

Cold Snap, Con’t.

1) Electric Market Synchronization with Gas Market

– Cold Snap Proposal is event driven, triggered by extreme weather (or by gas-side operational constraints)

– Option A selected by NEPOOL MCOption A FEATURES Option B

09:00 DA Market Closes 05:00

Commit at EcoMin Gas Units Only

Schedule Info Available – Quantity

DAM Obligation All Units

09:30 Schedule Info Available - Time

09:00

Yes DA Gas Market Price Discovery Prior to Offer

No

19

2) Electric/Gas Operating Committee:– Three meetings held to date– Communications: Information transfer has Legal issues

• Gas-Side: Antitrust & FERC Standards of Conduct• Electric-Side: NEPOOL Information Policy• ISO proposed Non-Disclosure Agreement

– Coordination within four areas:• Maintenance: scheduled & unscheduled• Operations: contingencies, blackout/system

restoration• Training: common-mode & emergency drills• Planning: contingency identification & analysis

Cold Snap, Con’t.

20

3) Investigate True Dual Fuel Capability & Promote Expansion– ESS Group = Engineering & Environmental Solutions

• Compilation of environmental permits• Assess dual fuel constraints & limitations• Expansion strategies & feasibility analysis• Dialogue with New England Air Regulators• Site visits will determine real barriers

4) Other ISO Activities:– Obtained database of generators’ pipeline capacity

contracts– Obtained access to pipelines electronic bulletin boards– New England-specific natural gas supply study

Cold Snap, Con’t.

21

• Timeline– Define problem & key issues - Complete– Publish Interim ISO-NE Cold Snap Report - Complete– Prioritize issues & brainstorm solution sets - Complete– Present proposal options to stakeholders - Complete – Finalize proposal & Market Rule changes - October– Publish Final Cold Snap Report - October– Publish ISO Management Response - October– FERC Filing - TBD– Implement & test changes - Fall 2004– EGOC weekly look-ahead meetings - Nov ~ Mar

Cold Snap, Con’t.

22

Winter Outlook

23

Winter 2004-05 Capacity Assessment 50/50 Forecast

December ’04 through March ’05Conditions for Week of Lowest Operable Capacity

MarginWeek beginning January 8th

MWProjected Peak (50/50) 22,370 Operating Reserve Required 1,700Total Operable Cap. Required 24,070Projected Capacity 33,610Assumed Outages 6,600Total Capacity 27,010Operable Capacity Margin 2,940

24

Winter 2004-05 Capacity

AssessmentWeek Beginning, Saturday

Year Month Day

Installed Seasonal Claimed

Capability (SCC)

[Note 1]

Interchange (NYPP, NB, HQ, Highgate, Block Load)

Note

New Generation

[Note 2]

De-listed ICAP

Resources [Note 3]

Net Capacity [Note 4]

Peak Load Exposure [Note 5]

Operating Reserve

Requirement [Note 6]

Total Known Maintenance

Allowance for Unplanned

Outages [Note 7]

Generation at Risk Due

to Gas Supply [Note

8]Total

Capacity

Operable Capacity

Margin (+/-)

Extent of OP 4 Actions That May be Necessary (OP 4

Actions up to and including) [Note 9]

(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW)2004 October 2 33,061 450 0 1,320 32,190 17,590 1,700 3,600 2,800 0 25,790 6,500

9 33,061 450 0 1,320 32,190 17,625 1,700 3,200 2,800 0 26,190 6,870 16 33,061 450 0 1,320 32,190 18,556 1,700 4,200 2,800 0 25,190 4,930 23 33,061 450 0 1,320 32,190 18,923 1,700 4,400 2,800 0 24,990 4,370 30 33,061 450 0 1,320 32,190 19,131 1,700 4,000 3,600 0 24,590 3,760

2004 November 6 33,061 450 100 - 33,610 19,247 1,700 2,200 3,600 0 27,810 6,860 13 33,061 450 100 - 33,610 19,594 1,700 2,800 3,600 0 27,210 5,920 20 33,061 450 100 - 33,610 20,337 1,700 900 3,600 0 29,110 7,070 27 33,061 450 100 - 33,610 21,061 1,700 200 3,600 0 29,810 7,050

2004 December 4 33,061 450 100 - 33,610 21,263 1,700 500 3,200 0 29,910 6,950 11 33,061 450 100 - 33,610 21,554 1,700 200 3,200 0 30,210 6,960 18 33,061 450 100 - 33,610 21,565 1,700 100 3,200 0 30,310 7,050 25 33,061 450 100 - 33,610 21,627 1,700 100 3,200 0 30,310 6,980

Notes: Please note that the information contained within the Capacity Analysis is a deterministic projection of system conditions which could materialize during any given week of the year.1. Installed Capability per September 1, 2004 SCC Report, less recent retirements or deactivations that have not yet been reflected in the SCC Report. The Operable Capability does not reflect possible

transmission constraints within the NEPOOL system.2. New Generation information includes 1) generation recently commercial but not yet reflected in the NEPOOL SCC Report totals used in the Installed Capability Column, and 2) future generation

as assumed by ISO-NE Planning Department. This value is rounded to the nearest hundred.3. De-listed ICAP quantities are only known with certainty in the current month. This number is adjusted when a delisted generator is out on maintenance to avoid double counting.4. Net Capacity = (SCC) + (Interchange) + (New Generation) - (De-listed ICAP Resources). In this equation, the SCC, Interchange and De-listed ICAP values are rounded to the nearest ten

and New Generation is rounded to the nearest hundred.5. Peak Load Exposure reflects values published in the April 2004 CELT Report. 6. Operating Reserve Requirement based on the first contingency (Generator at 1160 MW) plus 1/2 the second contingency (Generator at 1155 MW).7. Allowance for Unplanned Outages includes: forced outages and maintenance outages scheduled less than 14 days in advance.8. Assumed values based on ISO-NE study. 9. Relief from certain OP 4 Actions varies, depending on system conditions.

This analysis is a tabulation of weekly assessments shown in one single table. The information shows the operable capacity situation under assumed conditions for each week. It is not expected that the system peak will occur every week during June, July and August.

ISO-NE 2004 OPERABLE CAPACITY ANALYSISSeptember 27, 2004 - WITH KNOWN EXTERNAL CONTRACTS - 50/50 FORECAST

25



Year Month Day


Capability (SCC)

[Note 1]


No

te

New Generation

[Note 2]

De-listed ICAP

Resources [Note 3]



Operating Reserve




Outages [Note 7]


to Gas Supply [Note

8]Total

Capacity

Operable Capacity

Margin (+/-)



(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW)2005 January 1 33,061 450 100 - 33,610 21,902 1,700 100 2,800 2,250 28,460 4,860

8 33,061 450 100 - 33,610 22,370 1,700 1,000 2,800 2,800 27,010 2,940 15 33,061 450 100 - 33,610 22,370 1,700 900 2,800 2,800 27,110 3,040 22 33,061 450 100 - 33,610 22,370 1,700 600 2,800 2,800 27,410 3,340 29 33,061 450 100 - 33,610 22,146 1,700 200 3,100 2,250 28,060 4,210

2005 February 5 33,061 450 100 - 33,610 21,878 1,700 300 3,100 2,250 27,960 4,380 12 33,061 450 100 - 33,610 21,849 1,700 200 3,100 2,250 28,060 4,510 19 33,061 450 100 - 33,610 21,585 1,700 1,100 3,100 0 29,410 6,130 26 33,061 450 100 - 33,610 20,592 1,700 800 2,200 0 30,610 8,320

2005 March 5 33,061 450 100 - 33,610 20,240 1,700 1,800 2,200 0 29,610 7,670 12 33,061 450 100 - 33,610 20,044 1,700 1,700 2,200 0 29,710 7,970 19 33,061 450 100 - 33,610 19,677 1,700 2,000 2,200 0 29,410 8,030 26 33,061 450 100 - 33,610 19,108 1,700 1,200 2,200 0 30,210 9,400







26


AssessmentNEPOOL Operating Capacity Margins WITH KNOWN EXTERNAL TRANSACTIONS - 50/50 FORECAST

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

2-O

ct

9-O

ct

16-O

ct

23-O

ct

30-O

ct

6-N

ov

13-N

ov

20-N

ov

27-N

ov

4-D

ec

11-D

ec

18-D

ec

25-D

ec

25-D

ec

1-Ja

n

8-Ja

n

15-J

an

22-J

an

29-J

an

5-F

eb

12-F

eb

19-F

eb

26-F

eb

5-M

ar

12-M

ar

19-M

ar

26-M

ar

October 2004 - March 2005, W/B Saturday

Ope

ratin

g C

apac

ity M

argi

n (M

W)

27


December ’04 through March ’05Conditions for Week of Lowest Operable Capacity

MarginWeeks beginning January 8th – 22nd

MWProjected Peak (90/10) 23,255 Operating Reserve Required 1,700Total Operable Cap. Required 24,955Projected Capacity 33,610 Assumed Outages 7,000Total Capacity 26,610Operable Capacity Margin 1,655Assumed outages are based on Jan. 2004 Cold Snap experience (9,000 MW of total outage) adjusted for 2,000 MW of capacity expected to be available as result of preliminary Cold Snap Initiatives.

28



Year Month Day


Capability (SCC)

[Note 1]


No

te

New Generation

[Note 2]

De-listed ICAP

Resources [Note 3]



Operating Reserve




Outages [Note 7]


to Gas Supply [Note

8]Total

Capacity

Operable Capacity

Margin (+/-)



(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW)2004 October 2 33,061 450 0 1,320 32,190 18,286 1,700 3,600 2,800 0 25,790 5,800

9 33,061 450 0 1,320 32,190 18,324 1,700 3,200 2,800 0 26,190 6,170 16 33,061 450 0 1,320 32,190 19,291 1,700 4,200 2,800 0 25,190 4,200 23 33,061 450 0 1,320 32,190 19,673 1,700 4,400 2,800 0 24,990 3,620 30 33,061 450 0 1,320 32,190 19,889 1,700 4,000 3,600 0 24,590 3,000

2004 November 6 33,061 450 100 - 33,610 20,010 1,700 2,200 3,600 0 27,810 6,100 13 33,061 450 100 - 33,610 20,370 1,700 2,800 3,600 0 27,210 5,140 20 33,061 450 100 - 33,610 21,142 1,700 900 3,600 0 29,110 6,270 27 33,061 450 100 - 33,610 21,896 1,700 200 3,600 0 29,810 6,210

2004 December 4 33,061 450 100 - 33,610 22,105 1,700 500 3,200 0 29,910 6,110 11 33,061 450 100 - 33,610 22,407 1,700 200 3,200 0 30,210 6,100 18 33,061 450 100 - 33,610 22,419 1,700 100 3,200 0 30,310 6,190 25 33,061 450 100 - 33,610 22,484 1,700 100 3,200 0 30,310 6,130







29


Week Beginning, Saturday

Year Month Day


Capability (SCC)

[Note 1]


No

te

New Generation

[Note 2]

De-listed ICAP

Resources [Note 3]



Operating Reserve




Outages [Note 7]


to Gas Supply [Note

8]Total

Capacity

Operable Capacity

Margin (+/-)



(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW)2005 January 1 33,061 450 100 - 33,610 22,769 1,700 100 2,800 4,100 26,610 2,140

8 33,061 450 100 - 33,610 23,255 1,700 1,000 2,800 3,200 26,610 1,660 15 33,061 450 100 - 33,610 23,255 1,700 900 2,800 3,300 26,610 1,660 22 33,061 450 100 - 33,610 23,255 1,700 600 2,800 3,600 26,610 1,660 29 33,061 450 100 - 33,610 23,022 1,700 200 3,100 3,700 26,610 1,890

2005 February 5 33,061 450 100 - 33,610 22,743 1,700 300 3,100 3,600 26,610 2,170 12 33,061 450 100 - 33,610 22,713 1,700 200 3,100 3,700 26,610 2,200 19 33,061 450 100 - 33,610 22,439 1,700 1,100 3,100 0 29,410 5,270 26 33,061 450 100 - 33,610 21,406 1,700 800 2,200 0 30,610 7,500

2005 March 5 33,061 450 100 - 33,610 21,041 1,700 1,800 2,200 0 29,610 6,870 12 33,061 450 100 - 33,610 20,836 1,700 1,700 2,200 0 29,710 7,170 19 33,061 450 100 - 33,610 20,455 1,700 2,000 2,200 0 29,410 7,260 26 33,061 450 100 - 33,610 19,864 1,700 1,200 2,200 0 30,210 8,650







30


AssessmentNEPOOL Operating Capacity Margins WITH KNOWN EXTERNAL TRANSACTIONS - 90/10 FORECAST

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,000

2-O

ct

9-O

ct

16-O

ct

23-O

ct

30-O

ct

6-N

ov

13-N

ov

20-N

ov

27-N

ov

4-D

ec

11-D

ec

18-D

ec

25-D

ec

1-Ja

n

8-Ja

n

15-J

an

22-J

an

29-J

an

5-F

eb

12-F

eb

19-F

eb

26-F

eb

5-M

ar

12-M

ar

19-M

ar

26-M

ar

October 2004 - March 2005, W/B Saturday

Ope

ratin

g C

apac

ity M

argi

n (M

W)

31

Back-Up Detail

32

Demand Response

33

Demand Response(as of September 28, 2004)

ReadyTo Respond: Approved:Zone Assets Total Assets Total

CT 137 190.5 4 0.8ME 5 78.5 0 0.0NEMA 116 45.4 1 24.0NH 3 1.6 0 0.0RI 14 3.2 0 0.0SEMA 90 9.7 1 0.1VT 17 13.5 0 0.0WCMA 102 24.8 2 0.4

Total 484 367.1 8 25.3

34

Demand Response, Con’t.

(as of September 28, 2004)

* SWCT assets are included in CT values and are not included in Total

484 Assets 367.1 MW 8 Assets 25.3 MWZone Assets RT Price RT 30-Min RT 2-Hour Profiled Assets RT Price RT 30-Min RT 2-Hour Profiled

CT 137 31.8 158.2 0.4 0.0 4 0.0 0.8 0.0 0.0

SWCT* 84 5.2 133.0 0.4 0.0 4 0.0 0.8 0.0 0.0

ME 5 1.5 0.0 1.0 76.0 0 0.0 0.0 0.0 0.0

NEMA 116 39.2 3.3 1.5 1.4 1 0.0 24.0 0.0 0.0

NH 3 1.2 0.4 0.0 0.0 0 0.0 0.0 0.0 0.0

RI 14 3.2 0.0 0.0 0.0 0 0.0 0.0 0.0 0.0

SEMA 90 9.2 0.5 0.0 0.0 1 0.1 0.0 0.0 0.0

VT 17 7.5 0.1 0.0 5.9 0 0.0 0.0 0.0 0.0

WCMA 102 13.3 2.2 9.3 0.0 2 0.0 0.4 0.0 0.0

Total 484 106.8 164.8 12.3 83.2 8.0 0.1 25.2 0.0 0.0

Ready To Respond: Approved:

35

New Generation

36

New Generation Update

• No new resources were added in September.

• Approximately 60 MW expected on line by the end of the year.

• Status of Generation Projects as of September 27, 2004:

No. MWIn Construction 3 127.4with 18.4 approval

Not in Construction 7 1,417with 18.4 Approval

37

RTEP

38

RTEP Update

• RTEP04 Report– ISO BOD action anticipated mid

October• Project Listing

– Update to be discussed at October 6 Joint TEAC/RC teleconference as addendum to RTEP04.

39

Inter-ISO Update

• Northeastern ISO/RTO Planning Coordination Protocol – Signed by ISO-NE and NYISO– Awaiting signature by PJM– Next Steps

• Form Joint ISO/RTO Planning Committee.

• Exchange system plans and SIS queues.• Initiate Inter-area Planning Stakeholder

Advisory Committee.

40

RTEP Project Stage Descriptions

Stage Description

1Planning and Preparation of Project Configuration

2Pre-construction (e.g., material ordering, project scheduling)

3 Construction in Progress

4 Completed

41

NSTAR 345 kV Transmission Reliability Project

Status as of 9/28/04Project Benefit: Improves New England reliability by addressing Boston Area concerns and increasing Boston Import Limit from 3,600 MW to approximately 4,500 MW.

UpgradeExpectedIn-service

OriginalIn-service

Present Stage

Stoughton 345 kV Substation Jun-06 Jun-06 1Stoughton - Hyde Park 345 kV Jun-06 Jun-06 1Stoughton - K Street 345 kV #1 Jun-06 Jun-06 1

Stoughton - K Street 345 kV #2 Dec-07 Dec-07 1

Notes:- Siting review in progress; ruling due 4th quarter 2004.

- Detailed engineering in progress.

Phase 2

Phase 1

- Received conditional RC approval 7-29-04.

42

SWCT 345 kV Transmission Reliability Project

Status as of 9/28/04Project Benefit: Improves New England reliability by addressing SWCT concerns. Increases SWCT Import Limit from 2,000 MW to approximately 3,400 MW.


OriginalIn-service

Present Stage

Norwalk 345 kV Substation Nov-05 Dec-04 2Plumtree 345 kV Substation Nov-05 Dec-04 2Norwalk - Plumtree 345 kV Nov-05 Dec-04 2

Associated 115 kV Line Work Nov-05 Dec-04 2

Beseck 345 kV Substation Dec-07 Jan-06 1East Devon 345 kV Substation Dec-07 Jan-06 1Singer 345 kV Substation Dec-07 Jan-06 1Beseck - East Devon 345 kV Dec-07 Jan-06 1East Devon - Singer 345 kV Dec-07 Jan-06 1Singer - Norwalk 345 kV Dec-07 Jan-06 1

Associated 115 kV Line Work Dec-07 Jan-06 1

Notes Phase 1:- Siting review complete; appeal denied.- Detailed engineering in progress.

- Modification may become necessary to mitigate harmonic resonance/transient overvoltage concerns.

Notes Phase 2:- Siting review in progress, ruling due December 2004.

- Modification may become necessary to mitigate harmonic resonance/transient overvoltage concerns.

Phase 2

Phase 1

43

Northeast Reliability Interconnect ProjectStatus as of 9/28/04

Project Benefit: Improves New England reliability by improving inter-area transfer capability and eliminating various protection/stability concerns.


OriginalIn-service

Present Stage

Orrington, ME - Pt. Lepreau, NB 345 kV Dec-08 Dec-08 1

Notes:- Siting approved for Canadian section of line.- DOE & Maine DEP review processes (approx. 1 year) to start 3rd quarter 2004.

44

NWVT 345 kV Transmission Reliability ProjectStatus as of 9/28/04

Project Benefit: Improves New England reliability by addressing NWVT concerns, bringing another source into the Burlington area.


OriginalIn-service

Present Stage

New Haven 345 kV Substation Oct-05 Oct-05 1

West Rutland - New Haven 345 kV Nov-05 Nov-05 1

New Haven - Queen City 115 kV Oct-06 Oct-06 1

Granite STATCOM/Upgrades Oct-07 Oct-07 1

Notes:- Siting review in progress, ruling due January 2005.- Sandbar Phase Angle Regulator in service.

45

Southern New England Reliability ProjectStatus as of 9/28/04

Project Benefit: Improves New England reliability by increasing transfer limits of three critical interfaces, including Connecticut Import Limit


OriginalIn-service

Present Stage

Millbury - Sherman Rd. 345 kV Dec-08 Dec-08 1

Sherman Rd. - Lake Rd. 345 kV Dec-08 Dec-08 1

Lake Rd. - Card St. 345 kV Dec-08 Dec-08 1

345 kV Substation Modifications Dec-08 Dec-08 1

Notes:- Planning studies in progress; estimated completion late 2004.- Project specifics may change; alternatives still under review.

46

Transmission Siting Update• SWCT

– Phase I• Received conditional approval from Connecticut Siting Council 2/11/04.

– Phase II• ISO, NU and UI submitted the Reliability and Operating Committee (ROC)

harmonics/overvoltage report on August 16. Study work continues and interim report scheduled for completion October 8.

• Hearing scheduled for September 28 on East Shore Alternative.• BOSTON

– New Boston 1 needed until NSTAR completes 345 kV Reliability Project from Stoughton to Hyde Park and K Street (2006 earliest)

• Conditional 18.4 approval for the NSTAR 345 kV Transmission Reliability Project August 4, 2004.

• Additional analysis of harmonics/transient overvoltage expected 4Q 2004.– Salem Harbor needed at least until NGRID North Shore upgrades (2006

earliest)– These units provide operating reserves for the current system as well as

insurance for delays in transmission projects.– Long-term solution is functioning Resource Adequacy market to incent

generation to locate in the most appropriate areas, with the ability to do gap RFP’s to address timing issues.

• NWVT– State hearing process continues

• Surrebuttal pre-file testimony submitted September 3• Surrebuttal hearings held late September• Decision expected by January 2005

47

Compliance

48

2004 Compliance Update

• A4: Maintenance for Bulk Power System Protection

– Responses to ISO-NE survey were required by 1/5/04.

– Level 2 sanction was imposed on 3 Participants for failure to respond on time.

– ISO-NE reported full compliance with this Standard to NPCC.

49

2004 Compliance Update, Con’t.

• A3-4.9: Generator Underfrequency Tripping– All Participants surveyed responded to the ISO-NE

Survey • 3 Participants have generators with non-

compliant trip settings– 2 are exempt (nuclear plants)– 1 will require that ISO-NE enforce compliance

• A3-4.6: Underfrequency Load Shedding

– All Participants surveyed responded to the ISO-NE Survey

– ISO-NE reported full compliance with this Standard to NPCC

50

SANCTIONS

• Level 1 – Letter from Director SP to the functional head of the Industry Participant with copy to NCWG

• Level 2 – Letter from COO to the Chief Executive of the Industry Participant with copy to the relevant functional head, all NEPOOL Participants and NPCC

• Level 3 – Letter from the CEO to the Board of Directors of the Industry Participant with copies to Level 2 recipients. Post on the ISO-NE Compliance Website.

• Level 4 –Level 3 penalty with copies to State/Provincial regulatory agencies, FERC, DOE, State Governor and Legislators.


51

2004 Compliance Update

• A4: Maintenance for Bulk Power System Protection

– Responses to ISO-NE survey were required by 1/5/04.

– Level 2 sanction was imposed on 3 Participants for failure to respond on time.

– ISO-NE reported full compliance with this Standard to NPCC.

52


• A3-4.9: Generator Underfrequency Tripping– All Participants surveyed responded to the ISO-NE

Survey • 3 Participants have generators with non-

compliant trip settings– 2 are exempt (nuclear plants)– 1 will require that ISO-NE enforce compliance

• A3-4.6: Underfrequency Load Shedding

– All Participants surveyed responded to the ISO-NE Survey

– ISO-NE reported full compliance with this Standard to NPCC

53

SANCTIONS

• Level 1 – Letter from Director SP to the functional head of the Industry Participant with copy to NCWG

• Level 2 – Letter from COO to the Chief Executive of the Industry Participant with copy to the relevant functional head, all NEPOOL Participants and NPCC

• Level 3 – Letter from the CEO to the Board of Directors of the Industry Participant with copies to Level 2 recipients. Post on the ISO-NE Compliance Website.

• Level 4 –Level 3 penalty with copies to State/Provincial regulatory agencies, FERC, DOE, State Governor and Legislators.


nepool participants committee boston, ma october 1, 2004

Documents