NEPOOL Participants Committee Meeting Boston, MA February 4, 2005

NEPOOL Participants Committee Meeting

Boston, MA

February 4, 2005

Stephen G. WhitleySenior Vice President & COO

2

• System Operations• Market Operations• Overall Uplift• Winter 2004/2005 Outlook• Back-Up Detail

Agenda

3

System Operations

4

Operations Highlights• Boston & Hartford Weather Pattern:

– On average, temperatures in January were slightly below average; precipitation averaged +0.53 (Western MA) and +0.63 (Boston Area) above normal. (The moisture content during the snow storms in January was very low).

• Peak load of 22,100 MW at 19:00 hours on January 18, 2005.• During January:

– NPCC Shared Activation of Reserve Events:• January 4 IMO – Bruce G1 @ 950 Mw• January 8 PJM – Gavin1 @1400 Mw

– Solar Magnetic Disturbance (SMD)• January 7 K - 7• January 17 K – 7• January 18 K – 7 (twice)• January 21 K – 7• January 21 K - 8

5

Market Operations

6

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

Note: Natural Gas source is Algonquin Citygates Price.

7

Day-Ahead–LMP Average by Zone & Hub:

LMP Marginal Loss Component Congestion Component

January 1, 2005 to January 25, 2005 : Day-Ahead LMPs

(-6.92%)

(-2.56%)

(-0.21%)

(-1.88%)

(-1.70%)

(0.16%)

(4.15%)(-0.63%)

8

Real-Time-LMP Average by Zone & Hub:

LMP Marginal Loss Component Congestion Component

(-5.87%)

(-1.75)%

(-0.14%)

(-1.00%)

(-1.94%)

(-2.34%)

(0.04%) (-0.95%)

January 1, 2005 to January 25, 2005: Real Time LMPs

9

Day Ahead Market vs. Forecast Load

January data represents January 1-January 25

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

9999102

020406080

100120

November December January


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

909093

0

20

40

60

80

100

November December January


10

Day Ahead LMPDAM LMP December 30, 2004 Through January 26, 2005

20.00

40.00

60.00

80.00

100.00

120.00

140.00

160.00

180.00

200.00

12/3

0/20

04 0

1

01/0

1/20

05 0

1

01/0

3/20

05 0

1

01/0

5/20

05 0

1

01/0

7/20

05 0

1

01/0

9/20

05 0

1

01/11

/200

5 01

01/1

3/20

05 0

1

01/1

5/20

05 0

1

01/1

7/20

05 0

1

01/1

9/20

05 0

1

01/2

1/20

05 0

1

01/2

3/20

05 0

1

01/2

5/20

05 0

1

Day

$/M

Wh

INTERNAL_HUB CONNECTICUT MAINE NEMASSBOST NEWHAMPSHIRE RHODEISLAND SEMASS VERMONT WCMASS

Dupont G18 Line constrained due to F19 Line outage.

NEMASSBOST interface constrained due to minimal generation clearing within

the interface.

Low temperatures and higher gas prices resulted in higher than

normal DA LMPs.

NEMASSBOST interface constrained due to minimal

generation clearing within the interface.

11

Real Time LMPReal-Time LMP December 30, 2004 Through January 26, 2005

0.00

20.00

40.00

60.00

80.00

100.00

120.00

140.00

160.00

180.00

12/3

0/20

04 0

1

01/0

1/20

05 0

1

01/0

3/20

05 0

1

01/0

5/20

05 0

1

01/0

7/20

05 0

1

01/0

9/20

05 0

1

01/11

/200

5 01

01/1

3/20

05 0

1

01/1

5/20

05 0

1

01/1

7/20

05 0

1

01/1

9/20

05 0

1

01/2

1/20

05 0

1

01/2

3/20

05 0

1

01/2

5/20

05 0

1

Day

$/M

Wh

INTERNAL_HUB CONNECTICUT MAINE NEMASSBOST NEWHAMPSHIRE RHODEISLAND SEMASS VERMONT WCMASS

Minimum Generation Emergency

Tight capacity conditions due to several units failing to start as

scheduled during morning load pickup.

Tight capacity conditions during peak

load period.

Multiple unit trips during the morning load pickup.

Peak load period.

12

Settlement Data – Real Time & Balancing Market

Note: Partial Month Data January 1-January 25

Minimum % of Real-Time Load Fully Hedged

71% 70%

72%

75%

73%71% 71%

77%

73%71% 71% 70% 70%

63%

72%

70%

68%

74%

72%

50%

55%

60%

65%

70%

75%

80%

Aug 0

2 - J

ul 0

3 Av

erag

e

Aug-0

3

Sep-

03

Oct-0

3

Nov-0

3

Dec-0

3

Jan-

04

Feb-

04

Mar

-04

Apr-0

4

May

-04

Jun-

04

Jul-0

4

Aug-0

4

Sep-

04

Oct-0

4

Nov-0

4

Dec-0

4

Jan-

05

Month

% R

T L

oad F

ully H

edged

13

RMR and Economic Operating Reserve Payments

RMR & 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

Sep-

04

Oct-0

4

Nov-0

4

Dec-0

4

Jan-

05

DA RMR DA Economic RT RMR RT Economic

Preliminary/Partial DataJanuary 1-January 24

Note: Oct.-Dec. subject to 90-Day Resettlement

14

Monthly VAR Support and SCR PaymentsMonthly VAR Support and SCR Payments

$0

$2,000,000

$4,000,000

$6,000,000

$8,000,000

$10,000,000

$12,000,000

$14,000,000

$16,000,000

$18,000,000

Jan-

04*

Feb-0

4*

Mar

-04*

Apr-0

4*

May

-04*

Jun-

04*

Jul-0

4*

Aug-0

4*

Sep-0

4*

Oct-04

Nov-0

4

Dec-0

4

Jan-

05

DA VAR RT VAR RT SCR * - denotes 90-Day Resettlement values reflected

Preliminary/Partial DataJanuary 1-January 24

15

Overall Uplift

16

Uplift – Where It Occurs – January 2005(MWh)

DA

RT

NEMA

CT

Other

NEMA

CT

Other

Day Ahead

Real Time

Jan (MWH)

17

Uplift – What Is Cause – January 2005(MWh)

Jan (MWH)

Day Ahead

Real Time

DA

RT

Econ

RMR

VAR

Econ

RMR

VAR SCR

18

Uplift as % of Total DA/RT Energy Market

0

1

2

3

4

5

% of Energy Market

Dollar value of Energy Mkt assumed to equal :

(DALMP*DAALO + RTLMP*RTALOdev) summed for each location in each hour.

*2003 values reflect SMD months - March through December

** January 2005 includes only 24 days of data

19

VAR & SCR Uplift as % of Total DA/RT Energy Market

0

1

2

3

4

5

% of Energy Market





20

Economic & RMR Uplift as % of Total DA/RT Energy Market

0

1

2

3

4

5

% of Energy Market





21

0

30

60

90

120

150

180

Mil

lio

ns 2004

2005

048

1216202428

Mil

lio

ns 2004

2005

Overall Uplift

($) (MWHs)

Note: Overall uplift includes out of merit DA and RT Economic, RMR, VAR, and RT SCR components2003 includes SMD months only.

Monthly

Year To Date($) (MWHs)

0100200300400500600700800

Th

ou

sa

nd

s

2004

2005

01234567

Mil

lio

ns

2004

2005

22

Action Plan to Reduce VAR Uplift

1. 98% of VAR uplift in 2004 was for the Boston area to reliably operate during light load, high voltage conditions stemming from their underground cable system.

2. To expand area reactive resources, the following actions were taken:

a. Working with the owners of Mystic, the leading reactive limits on units 8 and 9 were increased by a total of 100 MVAR.

b. Working with NSTAR; i. A work around allowed the early return of an 80 MVAR reactor.ii. Repair of a load tap changer on the Woburn 345/115 kV transformer

was expedited increasing the effectiveness of 3 reactors at the station.

3. To capture the benefits of these actions, the ISO, NSTAR and REMVEC will complete technical work to revise the Boston area operating guide by February 11.

4. In the longer term, NSTAR plans to install a new 150 MVAR reactor with dynamic control features by May 1.

23

Definitions

Uplift Make whole payments made to resources whose hourly commitment and dispatch by the ISO resulted in the resource not earning its offered value in the Energy and Regulation Markets for its output over the course of the day. Typically, there is some out-of-merit operation occurring in the process of protecting the overall resource adequacy and transmission security, either for specific locations or for the entire control area.

VAR Uplift Uplift paid to resources operated by the ISO to provide voltage support in specific locations.

SCR Uplift Uplift paid to units dispatched by request of local transmission providers for purpose of managing low voltage constraints. Special Constrained Resource (SCR) constraints are not modeled in the day-ahead market software.

RMR Uplift Uplift paid to resources providing adequate capacity in constrained areas to respond to a local second contingency. They are committed based on RMR protocols.

Economic Uplift

Uplift paid to an eligible resource that is not providing for RMR, VAR, or SCR requirements. These resources may have been providing for first contingency requirements (system-wide or locally). Cancelled start-ups are covered by economic uplift if the unit was not committed for RMR, VAR or SCR requirements.

Delisted Units

Resources within the control area that have requested to be classified as a non-ICAP resource, and as such, are not required to offer their capacity into the day-ahead energy market.

24

Winter Outlook

25

Winter 2005 Capacity Assessment 50/50 Forecast

February through March ’05Conditions for Week of Lowest Operable Capacity

MarginWeek beginning February 12th

MW

Projected Peak (50/50) 21,961 Operating Reserve Required 1,700Total Operable Cap. Required 23,661Projected Capacity 32,3701

Assumed Outages 6,550Total Capacity 25,820Operable Capacity Margin

2,159

1 2,950 MW of installed capacity has delisted. Only 950 MW has been deducted from the total reflecting what has been sold outside of New England.

26

2005 Capacity Assessment

Week Beginning, Saturday

Year Month Day

Installed Seasonal Claimed

Capability (SCC)

[Note 1]

Interchange (NYPP, NB,

HQ, Highgate,

Block Load)

No

te

New Generation

[Note 2]

De-listed ICAP sold [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

Total Capacity

Operable Capacity

Margin (+/-)

Extent of OP 4 Actions That May be Necessary (OP 4 Actions up to and

including) [Note 8]

(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) 2005 February 5 33,031 290 0 950 32,370 21,990 1,700 1,000 3,100 2,250 26,020 2,330

12 33,031 290 0 950 32,370 21,961 1,700 1,200 3,100 2,250 25,820 2,160 19 33,031 290 0 950 32,370 21,696 1,700 1,800 3,100 0 27,470 4,070 26 33,036 290 0 950 32,380 20,697 1,700 2,400 2,200 0 27,780 5,380

2005 March 5 33,036 450 0 950 32,540 20,344 1,700 2,800 2,200 0 27,540 5,500 12 33,036 450 0 950 32,540 20,147 1,700 3,400 2,200 0 26,940 5,090 19 33,036 450 0 950 32,540 19,778 1,700 3,700 2,200 0 26,640 5,160 26 33,036 450 0 950 32,540 19,207 1,700 3,300 2,200 0 27,040 6,130

2005 April 2 33,036 450 0 950 32,540 18,708 1,600 5,500 2,700 0 24,340 4,030 9 33,036 450 0 950 32,540 18,453 1,600 6,200 2,700 0 23,640 3,590 16 33,036 450 0 950 32,540 17,939 1,600 7,600 2,700 0 22,240 2,700 23 33,036 200 9 0 950 32,290 17,671 1,600 6,500 2,700 0 23,090 3,820 30 33,036 450 0 33,490 17,644 1,600 6,500 3,400 0 23,590 4,350

2005 May 7 33,036 450 0 - 33,490 19,911 1,700 5,100 3,400 0 24,990 3,380 14 33,036 450 0 - 33,490 20,836 1,700 4,300 3,400 0 25,790 3,250 21 33,036 450 0 - 33,490 21,695 1,700 2,200 3,400 0 27,890 4,500 28 33,036 450 0 - 33,490 22,639 1,700 1,700 3,400 0 28,390 4,050

2005 June 4 30,662 450 0 - 31,110 26,355 1,700 200 2,800 0 28,110 60 11 30,662 450 0 - 31,110 26,355 1,700 200 2,800 0 28,110 60 18 30,662 450 0 - 31,110 26,355 1,700 400 2,800 0 27,910 (150) Action 5 25 30,662 450 0 - 31,110 26,355 1,700 200 2,800 0 28,110 60

2005 July 2 30,624 450 0 - 31,070 26,355 1,700 100 2,100 0 28,870 820 9 30,624 450 0 - 31,070 26,355 1,700 200 2,100 0 28,770 720 16 30,624 450 0 - 31,070 26,355 1,700 300 2,100 0 28,670 620 23 30,624 450 0 - 31,070 26,355 1,700 200 2,100 0 28,770 720 30 30,625 450 0 - 31,070 26,355 1,700 200 2,100 0 28,770 720

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 February 1, 2005 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. For the month of February, a total of 2,950 MW have been delisted with 950 MW sold outside New England. It is assumed that 950 MW will be delisted through March. 4. Net Capacity = (SCC) + (Interchange) + (New Generation) - (De-listed ICAP Resources). In this equation, values for SCC, Interchange and De-listed ICAP sold are rounded to the nearest ten

and New Generation is rounded to the nearest hundred.5. Peak Load Exposure per the preliminary April 2005 CELT Report. 6. Operating Reserve Requirement based on the first contingency (Generator at 1160 MW) plus 1/2 the second contingency (Generator at 1145 MW).7. Allowance for Unplanned Outages includes forced outages and maintenance outages scheduled less than 14 days in advance.8. Relief from certain OP 4 Actions varies, depending on system conditions. 9. Highgate maintenance scheduled.

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 2005 OPERABLE CAPACITY ANALYSISFebruary 1, 2005 - WITH KNOWN EXTERNAL CONTRACTS - 50/50 FORECAST

27

2005 Capacity Assessment


Year Month Day


Capability (SCC)

[Note 1]


HQ, Highgate,

Block Load)

No

te

New Generation

[Note 2]




Operating Reserve





to Gas Supply

Total Capacity

Operable Capacity

Margin (+/-)


including) [Note 8]

(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) 30 30,625 450 0 - 31,070 26,355 1,700 200 2,100 0 28,770 720

2005 August 6 30,625 450 0 - 31,070 26,355 1,700 200 2,100 0 28,770 720 13 30,625 450 0 - 31,070 26,355 1,700 200 2,100 0 28,770 720 20 30,625 450 0 - 31,070 26,355 1,700 200 2,100 0 28,770 720 27 30,625 450 0 - 31,070 26,355 1,700 300 2,100 0 28,670 620

2005 September 3 30,624 450 0 - 31,070 24,236 1,700 300 2,100 0 28,670 2,730 10 30,624 450 0 - 31,070 22,926 1,700 600 2,100 0 28,370 3,740 17 30,624 450 0 - 31,070 22,578 1,700 700 2,100 0 28,270 3,990 24 30,624 450 0 - 31,070 22,491 1,700 1,300 2,100 0 27,670 3,480

2005 October 1 33,029 450 0 - 33,480 17,951 1,600 3,400 2,800 0 27,280 7,730 8 33,029 450 0 - 33,480 17,988 1,600 4,100 2,800 0 26,580 6,990 15 33,029 450 0 - 33,480 18,937 1,600 4,400 2,800 0 26,280 5,740 22 33,029 450 0 - 33,480 19,312 1,600 5,000 2,800 0 25,680 4,770 29 33,033 450 0 - 33,480 19,524 1,700 2,700 3,600 0 27,180 5,960

2005 November 5 33,033 450 0 - 33,480 19,643 1,700 2,200 3,600 0 27,680 6,340 12 33,033 450 0 - 33,480 19,997 1,700 2,500 3,600 0 27,380 5,680 19 33,033 450 0 - 33,480 20,755 1,700 800 3,600 0 29,080 6,630 26 33,033 450 0 - 33,480 21,494 1,700 600 3,600 0 29,280 6,090

2005 December 3 33,033 450 0 - 33,480 21,700 1,700 600 3,200 0 29,680 6,280 10 33,033 450 0 - 33,480 21,997 1,700 600 3,200 0 29,680 5,980 17 33,033 450 0 - 33,480 22,008 1,700 500 3,200 0 29,780 6,070 24 33,033 450 0 - 33,480 22,072 1,700 100 3,200 0 30,180 6,410







28

2005 Capacity AssessmentNEPOOL Operating Capacity Margins

WITH KNOWN EXTERNAL TRANSACTIONS - 50/50 FORECAST

(1,000)

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

5-F

eb

12-F

eb

19-F

eb

26-F

eb

5-M

ar

12-M

ar

19-M

ar

26-M

ar

2-A

pr

9-A

pr

16-A

pr

23-A

pr

30-A

pr

7-M

ay

14-M

ay

21-M

ay

28-M

ay

4-Ju

n

11-J

un

18-J

un

25-J

un

2-Ju

l

9-Ju

l

16-J

ul

23-J

ul

30-J

ul

6-A

ug

13-A

ug

20-A

ug

27-A

ug

3-S

ep

10-S

ep

17-S

ep

24-S

ep

1-O

ct

8-O

ct

15-O

ct

22-O

ct

29-O

ct

5-N

ov

12-N

ov

19-N

ov

26-N

ov

3-D

ec

10-D

ec

17-D

ec

24-D

ec

February - December 2005, W/B Saturday

Ope

ratin

g C

apac

ity M

argi

n (M

W)

OP 4 Action 5

29

Winter 2005 Capacity Assessment 90/10 Forecast

February through March ’05Conditions for Week of Lowest Operable Capacity

MarginWeek beginning February 5th

MWProjected Peak (90/10) 22,872 Operating Reserve Required 1,700Total Operable Cap. Required 24,572Projected Capacity 32,3701

Assumed Outages 7,000Total Capacity 25,370Operable Capacity Margin 798Assumed 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. 1 2,950 MW of installed capacity has delisted. Only 950 MW has been deducted from the total reflecting what has been sold outside of New England.

30

DRAFT -2005 Capacity Assessment 90/10 Forecast


Year Month Day


Capability (SCC)

[Note 1]


HQ, Highgate,

Block Load)

No

te

New Generation

[Note 2]




Operating Reserve





to Gas Supply

Total Capacity

Operable Capacity

Margin (+/-)


including) [Note 8]

(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) 2005 February 5 33,031 290 0 950 32,370 22,872 1,700 1,000 3,100 2,900 25,370 800

12 33,031 290 0 950 32,370 22,841 1,700 1,200 3,100 2,700 25,370 830 19 33,031 290 0 950 32,370 22,565 1,700 1,800 3,100 0 27,470 3,210 26 33,036 290 0 950 32,380 21,527 1,700 2,400 2,200 0 27,780 4,550

2005 March 5 33,036 450 0 950 32,540 21,160 1,700 2,800 2,200 0 27,540 4,680 12 33,036 450 0 950 32,540 20,954 1,700 3,400 2,200 0 26,940 4,290 19 33,036 450 0 950 32,540 20,570 1,700 3,700 2,200 0 26,640 4,370 26 33,036 450 0 950 32,540 19,976 1,700 3,300 2,200 0 27,040 5,360

2005 April 2 33,036 450 0 950 32,540 19,457 1,600 5,500 2,700 0 24,340 3,280 9 33,036 450 0 950 32,540 19,193 1,600 6,200 2,700 0 23,640 2,850 16 33,036 450 0 950 32,540 18,657 1,600 7,600 2,700 0 22,240 1,980 23 33,036 200 9 0 950 32,290 18,379 1,600 6,500 2,700 0 23,090 3,110 30 33,036 450 0 33,490 18,351 1,600 6,500 3,400 0 23,590 3,640

2005 May 7 33,036 450 0 - 33,490 21,143 1,700 5,100 3,400 0 24,990 2,150 14 33,036 450 0 - 33,490 22,125 1,700 4,300 3,400 0 25,790 1,970 21 33,036 450 0 - 33,490 23,037 1,700 2,200 3,400 0 27,890 3,150 28 33,036 450 0 - 33,490 24,039 1,700 1,700 3,400 0 28,390 2,650

2005 June 4 30,662 450 0 - 31,110 27,985 1,700 200 2,800 0 28,110 (1,580) Action 12 11 30,662 450 0 - 31,110 27,985 1,700 200 2,800 0 28,110 (1,580) Action 12 18 30,662 450 0 - 31,110 27,985 1,700 400 2,800 0 27,910 (1,780) Action 12 25 30,662 450 0 - 31,110 27,985 1,700 200 2,800 0 28,110 (1,580) Action 12

2005 July 2 30,624 450 0 - 31,070 27,985 1,700 100 2,100 0 28,870 (820) Action 9 9 30,624 450 0 - 31,070 27,985 1,700 200 2,100 0 28,770 (920) Action 12 16 30,624 450 0 - 31,070 27,985 1,700 300 2,100 0 28,670 (1,020) Action 12 23 30,624 450 0 - 31,070 27,985 1,700 200 2,100 0 28,770 (920) Action 12 30 30,625 450 0 - 31,070 27,985 1,700 200 2,100 0 28,770 (920) Action 12







31



Year Month Day


Capability (SCC)

[Note 1]


HQ, Highgate,

Block Load)

No

te

New Generation

[Note 2]




Operating Reserve





to Gas Supply

Total Capacity

Operable Capacity

Margin (+/-)


including) [Note 8]

(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) 2005 August 6 30,625 450 0 - 31,070 27,985 1,700 200 2,100 0 28,770 (920) Action 12

13 30,625 450 0 - 31,070 27,985 1,700 200 2,100 0 28,770 (920) Action 12 20 30,625 450 0 - 31,070 27,985 1,700 200 2,100 0 28,770 (920) Action 12 27 30,625 450 0 - 31,070 27,985 1,700 300 2,100 0 28,670 (1,020) Action 12

2005 September 3 30,624 450 0 - 31,070 25,735 1,700 300 2,100 0 28,670 1,240 10 30,624 450 0 - 31,070 24,344 1,700 600 2,100 0 28,370 2,330 17 30,624 450 0 - 31,070 23,975 1,700 700 2,100 0 28,270 2,600 24 30,624 450 0 - 31,070 23,882 1,700 1,300 2,100 0 27,670 2,090

2005 October 1 33,029 450 0 - 33,480 18,671 1,600 3,400 2,800 0 27,280 7,010 8 33,029 450 0 - 33,480 18,709 1,600 4,100 2,800 0 26,580 6,270 15 33,029 450 0 - 33,480 19,696 1,600 4,400 2,800 0 26,280 4,980 22 33,029 450 0 - 33,480 20,086 1,600 5,000 2,800 0 25,680 3,990 29 33,033 450 0 - 33,480 20,307 1,700 2,700 3,600 0 27,180 5,170

2005 November 5 33,033 450 0 - 33,480 20,430 1,700 2,200 3,600 0 27,680 5,550 12 33,033 450 0 - 33,480 20,798 1,700 2,500 3,600 0 27,380 4,880 19 33,033 450 0 - 33,480 21,586 1,700 800 3,600 0 29,080 5,790 26 33,033 450 0 - 33,480 22,356 1,700 600 3,600 0 29,280 5,220

2005 December 3 33,033 450 0 - 33,480 22,569 1,700 600 3,200 0 29,680 5,410 10 33,033 450 0 - 33,480 22,878 1,700 600 3,200 0 29,680 5,100 17 33,033 450 0 - 33,480 22,890 1,700 500 3,200 0 29,780 5,190 24 33,033 450 0 - 33,480 22,957 1,700 100 3,200 0 30,180 5,520







32


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

(3,000)

(2,000)

(1,000)

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

11,000

12,0005-

Feb

12-F

eb

19-F

eb

26-F

eb

5-M

ar

12-M

ar

19-M

ar

26-M

ar

2-A

pr

9-A

pr

16-A

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23-A

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30-A

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7-M

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14-M

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21-M

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28-M

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4-Ju

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11-J

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18-J

un

25-J

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2-Ju

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9-Ju

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16-J

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23-J

ul

30-J

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6-A

ug

13-A

ug

20-A

ug

27-A

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3-S

ep

10-S

ep

17-S

ep

24-S

ep

1-O

ct

8-O

ct

15-O

ct

22-O

ct

29-O

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5-N

ov

12-N

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19-N

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26-N

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February - December 2005, W/B Saturday

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33

Back-Up Detail

34

Demand Response

35

Demand Response(as of February 1, 2005)

ReadyTo Respond: Approved:Zone Assets Total MW Assets Total MW

CT 223 159.0 16 21.5ME 8 104.5 0 0.0NEMA 115 45.0 3 24.2NH 8 18.5 0 0.0RI 16 3.3 0 0.0SEMA 83 9.0 1 0.1VT 16 13.4 0 0.0WCMA 95 27.1 0 0.0

Total 564 379.6 20 45.8

36

Demand Response, Con’t. (as of February 1, 2005)

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

564 Assets 379.6 MW 20 Assets 45.8 MWZone Assets RT Price RT 30-Min RT 2-Hour Profiled Assets RT Price RT 30-Min RT 2-Hour Profiled

CT 223 31.8 126.8 0.4 0.0 16 9.0 12.5 0.0 0.0

SWCT* 167 5.2 99.5 0.4 0.0 14 0.0 12.5 0.0 0.0

ME 8 27.5 0.0 1.0 76.0 0 0.0 0.0 0.0 0.0

NEMA 115 39.1 3.0 1.5 1.4 3 0.2 24.0 0.0 0.0

NH 8 18.1 0.4 0.0 0.0 0 0.0 0.0 0.0 0.0

RI 16 3.3 0.0 0.0 0.0 0 0.0 0.0 0.0 0.0

SEMA 83 8.5 0.5 0.0 0.0 1 0.1 0.0 0.0 0.0

VT 16 7.3 0.1 0.0 5.9 0 0.0 0.0 0.0 0.0

WCMA 95 18.0 0.1 9.0 0.0 0 0.0 0.0 0.0 0.0

Total 564 153.5 130.9 12.0 83.2 20.0 9.3 36.5 0.0 0.0

Ready To Respond: Approved:

37

New Generation

38

New Generation Update

• No new resources were added in January.

• Approximately 50 MW of capacity expected on line by the end of the year.

• Status of Generation Projects as of February 1, 2005:

No. MWIn Construction 1 8.4

Not in Construction 6 1,370

Nuclear Uprates 5 265

1Existing Proposed Plan approvals are pursuant to section 18.4 of the RNA; future Proposed Plan approvals will be pursuant to Section I.3.9 of the ISO New England Inc. Transmission, Markets and Services Tariff.

Generation Projects with Proposed Plan Approval1

39

RSP (Regional System Plan)

40

RSP Update

• RSP05– PAC01 to be held February 2

Draft Load Forecast OC Assumptions and Outlook

– Next Steps PAC02 to be held March 2 or March 3 Meet with Sr. Management on key messages

• Inter-ISO Update– Revised Northeast Coordinated System Plan (NCSP).

Under review of Joint ISO/RTO Planning Committee (JIPC)

– Next Steps Draft NCSP to be issued to Sr. Management mid-

February• NPCC

– Blackout issues being addressed– NERC Version O Registration completed

41

RSP 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

42

NSTAR 345 kV Transmission Reliability ProjectStatus as of 2/2/05

Project 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 2Stoughton - Hyde Park 345 kV Jun-06 Jun-06 2Stoughton - K Street 345 kV #1 Jun-06 Jun-06 2

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

Phase 1

2

- New Boston 1 needed until project completed.- Received RC recommendation for 18.4 approval 12/13/04 and 12C approval 7-29-04.

Includes additional analysis of harmonics/transient overvoltage.- EFSB/DTE approval on 12/23/04.- TCA determination letter from ISO-NE expected Spring 2005.- 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.

43

North Shore UpgradesStatus as of 2/2/05

Project Benefit: Maintains system reliability for the North Shore area independent of Salem Harbor generation.


OriginalIn-service

Present Stage

Add 3 transformers at Ward Hill Jun-06 Jun-06 1Reconductor several 115kV lines Jun-06 Jun-06 1Salem Harbor capacitor banks Jun-06 Jun-06 1

New Wakefield Junction SS Jun-08 1Wakefield Junction

Ward Hill Upgrades

Jun-08

- MA DTE review in progress; ruling due early 2005- 18.4 application for Ward Hill upgrades expected early 2005- 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.

44

SWCT 345 kV Transmission Reliability ProjectStatus as of 2/2/05

Project 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 4th Qtr 06 Dec-04 2Plumtree 345 kV Substation Dec-04 2Norwalk - Plumtree 345 kV Dec-04 2

Associated 115 kV Line Work Dec-04 2

Beseck 345 kV Substation 2009 Jan-06 1East Devon 345 kV Substation Jan-06 1Singer 345 kV Substation Jan-06 1Beseck - East Devon 345 kV Jan-06 1East Devon - Singer 345 kV Jan-06 1Singer - Norwalk 345 kV Jan-06 1

Associated 115 kV Line Work Jan-06 1

Notes Phase 1:- Siting review complete; appeal denied.- Detailed engineering in progress.- TCA Application received 1/12/05.- Consultants doing final review of transient/harmonic analyses.

Notes Phase 2:- Siting review in progress, ruling due April 2005.- Final ROC report complete; recommended proceeding with 24 miles of UG XLPE cable.- 1/11 and 1/13 ROC Report Hearings completed.- Additional hearings scheduled for 2/14 (technical meeting) and 2/17 (ROC Report)- Consultants working on KEMA issues.

Phase 2

Phase 1

4th Qtr 064th Qtr 06

4th Qtr 06

200920092009200920092009

45

Northeast Reliability Interconnect ProjectStatus as of 2/2/05

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-07 Dec-08 1

- Siting approved for Canadian section of line.- DOE & Maine DEP review processes (approx. 1 year) have started.

46

NWVT 345 kV Transmission Reliability ProjectStatus as of 2/2/05

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 May-06 Oct-05 2West Rutland - New Haven 345 kV May-06 Nov-05 2New Haven - Queen City 115 kV Mar-07 Oct-06 2Granite STATCOM/Upgrades Oct-07 Oct-07 2

- Sandbar Phase Angle Regulator in service.- Conditional Siting approval received 1/28/05.- 1.3 miles of 115 kV in Bay Road area ordered underground.

47

Southern New England Reliability ProjectStatus as of 2/2/05

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

345 kV Substation Modifications Dec-08 Dec-08 1

- Planning studies in progress; estimated completion summer 2005.- Project specifics may change; alternatives still under review.- Project planning and coordination meetings continuing.

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NEPOOL Participants Committee Meeting Boston, MA February 4, 2005

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