nepool participants committee meeting waterville valley, nh march 11, 2005

NEPOOL Participants Committee Meeting

Waterville Valley, NH

March 11, 2005

Stephen G. WhitleySenior Vice President & COO

2

• System Operations• Market Operations• Overall Uplift• Back-Up Detail

Agenda

3

System Operations

4

Operations Highlights• Boston & Hartford Weather Pattern:

– Temperatures for February were slightly below normal in the Boston area with slightly above temperatures in the Hartford area. Precipitation was slightly below normal in both areas.

• Peak load of 19,892 MW at 19:00 hours on February 1, 2005.• During February:

– NPCC Shared Activation of Reserve Events:• February 2 NE – Granite Ridge @ 743 Mw• February 9 IMO – Bruce 7 @ 800 Mw• February 9 NE – Mystic 9 @ 600 Mw• February 16 NYISO – Ginna @ 500 Mw

– MS2• Implemented for Southeast CT 1330 hours (2/27) to 2000 hours (3/1)

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

February 1, 2005 to February 28, 2005 : Day-Ahead LMPs

-7.65%)(-2.66%)

(0.58%) (-2.16%)

(-2.34%)

(0.12%)

(-0.38%)

(1.15%)

8

Real-Time-LMP Average by Zone & Hub:

LMP Marginal Loss Component Congestion Component

(-6.65%)

(-2.39)%

(0.55%) (1.35%)(-2.14%)

(-2.31%)

(0.13%)

February 1, 2005 to February 28, 2005: Real Time LMPs

(-1.28%)

9

Day - Ahead Market vs. Forecast Load

January data represents January 1-January 25

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

999999

020406080

100120

December January February

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

929090

0

20

40

60

80

100

December January February

10

Day - Ahead LMPDAM LMP January 27, 2005 Through February 26, 2005

20.00

40.00

60.00

80.00

100.00

120.00

140.00

160.00

01/2

7/20

05 0

1

01/2

9/20

05 0

1

01/3

1/20

05 0

1

02/0

2/20

05 0

1

02/0

4/20

05 0

1

02/0

6/20

05 0

1

02/0

8/20

05 0

1

02/1

0/20

05 0

1

02/1

2/20

05 0

1

02/1

4/20

05 0

1

02/1

6/20

05 0

1

02/1

8/20

05 0

1

02/2

0/20

05 0

1

02/2

2/20

05 0

1

02/2

4/20

05 0

1

02/2

6/20

05 0

1

Day

$/M

Wh

INTERNAL_HUB CONNECTICUT MAINE NEMASSBOST NEWHAMPSHIRE RHODEISLAND SEMASS VERMONT WCMASS

Peak load period.

CT Import Interface constraint binding due to cleared demand and generation pattern during

peak load period.

Norwalk Stamford Interface constraint binding due to

91001 Line out of service for maintenance.

Boston Interface constraint binding due to minimal

generation clearing within the Boston interface.

11

Real-Time LMP January 27, 2005 Through February 26, 2005

01/2

7/20

05 0

1

$/M

Wh

INTERNAL_HUB CONNECTICUT MAINE NEMASSBOST NEWHAMPSHIRE RHODEISLAND SEMASS VERMONT WCMASS

10.00

30.00

50.00

70.00

90.00

110.00

130.00

150.00

01/2

9/20

05 0

1

01/3

1/20

05 0

1

02/0

2/20

05 0

1

02/0

4/20

05 0

1

02/0

6/20

05 0

1

02/0

8/20

05 0

1

02/1

0/20

05 0

1

02/1

2/20

05 0

1

02/1

4/20

05 0

1

02/1

6/20

05 0

1

02/1

8/20

05 0

1

02/2

0/20

05 0

1

02/2

2/20

05 0

1

02/2

4/20

05 0

1

02/2

6/20

05 0

1

Day

Loss of the 394 Line onto 379 Line constraint binding due to 326 Line

out of service.

Morning/Evening load pickup.

Norwalk Stamford Interface constraint binding due to 91001

Line out of service for maintenance.Boston Interface constraint

binding during peak load period due to trip of 339 Line earlier in

the day.

Real - Time LMP

12

Settlement Data – Real Time & Balancing Market

Minimum % Of Real Time Load Fully Hedged

73.10%

70.94%

71.84%

70.13%

74.39%

72.14%

70.57% 70.36%70.86%

69.59%

70.00%

63.12%

61.98%

67.62%

60%

62%

64%

66%

68%

70%

72%

74%

76%

Jan-04 Feb-04 Mar-04 Apr-04 May-04 Jun-04 Jul-04 Aug-04 Sep-04 Oct-04 Nov-04 Dec-04 Jan-05 Feb-05

Month

% R

T L

oad

Fu

lly H

edg

ed

% Hedged Load Average % Hedged Load

13

Overall Uplift

14

Uplift Analysis – February 2005

• Monthly MWh by market and zone• Monthly MWh by market and type• Uplift payments as % of energy market

– OATT billed– Energy market billed

• Monthly and YTD totals• Data through February 26, 2005

(except where noted)

15

What is Uplift?

• “Make-whole” payments made to resources whose hourly commitment and dispatch by the ISO resulted in a shortfall between the resource’s offered value in the Energy and Regulation Markets and the revenue earned from output over the course of the day.

• Typically, this is the result of some out-of-merit operation of resources occurring in order to protect the overall resource adequacy and transmission security of the (specific locations or for the entire) control area.

16

Uplift MWh by Market and Zone

February-05

34%

66%

Day-Ahead Real-Time

Day-Ahead

45%

4%

51%

NEMA CT Other Zones

Real-Time

66%

21%

13%

NEMA CT Other ZonesMWh totals reported are the total hourly MWh for uplift flagged units.

17

Uplift MWh By Market and Type

February-05

34%

66%

Day-Ahead Real-Time

Day-Ahead

58%

2%

40%

Econ Daily RMR VAR

Real-Time

73%

15%

10%

2%

Econ Daily RMRVAR SCR

MWh totals reported are the total hourly MWh for uplift flagged units.

18

Uplift Payments as % of Energy Market Value

2.4%

2.1%1.8%1.7%

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%2

00

3

20

04

Jan

-05

Feb

-05

Mar

-05

Ap

r-0

5

May

-05

Jun

-05

Jul-

05

Au

g-0

5

Sep

-05

Oct

-05

No

v-0

5

Dec

-05

2003 values reflect only SMD months

Energy Market value derived as the sum over all locations of the product of locational load obligation and price by hour in the Day-Ahead Market, and locational price and Real-Time Load Obligation Deviation in the Real-Time Market.

19

VAR and SCR Uplift Payments as % of Energy Market Value



1.1%

0.5%0.7%

0.4%

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%2

00

3

20

04

Jan

-05

Feb

-05

Mar

-05

Ap

r-0

5

May

-05

Jun

-05

Jul-

05

Au

g-0

5

Sep

-05

Oct

-05

No

v-0

5

Dec

-05

20

Action Proposals: VAR Uplift Reduction

Action ResponsibleTimefra

me1. Increase Mystic 8/9 capability to absorb

leading reactive power by a total of 100 Mvar.

P. Brandien Completed4th Qtr ‘04

2. Work with NSTAR to get the early return of an 80 Mvar shunt reactor.

P. Brandien Completed4th Qtr ’04

3. Work with NSTAR to expedite repair of load tap changer in Woburn 345/115 kV transformer to increase effectiveness of 3 reactors at the station.

P. Brandien Completed4th Qtr ’04

4. Revise the Boston area Operating Guide to capture recent reactive limit improvements in area (ISO, NSTAR, REMVEC actions.)

P. Brandien 1st Qtr. ‘05

5. Train Operations staff and implement Revised Boston Area Operating Guide.

P. Brandien 2nd Qtr. ‘05

6. NSTAR to install new 150 Mvar reactor. P. Brandien 2nd Qtr. ‘05

21

Economic and Daily RMR Uplift Payments as % of Energy Market Value



1.3%1.6%

1.0%1.3%

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%2

00

3

20

04

Jan

-05

Feb

-05

Mar

-05

Ap

r-0

5

May

-05

Jun

-05

Jul-

05

Au

g-0

5

Sep

-05

Oct

-05

No

v-0

5

Dec

-05

Feb-05:CT: 0.8%NEMA: 4.4%

22

Daily RMR Uplift Payments as % of Energy Market Value

0.6%

1.0%

0.4%0.7%

0.0%

1.0%

2.0%

3.0%

4.0%

5.0%2

00

3

20

04

Jan

-05

Feb

-05

Ma

r-0

5

Ap

r-0

5

Ma

y-0

5

Jun

-05

Jul-

05

Au

g-0

5

Se

p-0

5

Oct

-05

No

v-0

5

De

c-0

5



Feb-05:CT: 0.4%NEMA: 1.6%

23

Action Proposals: Daily RMR Uplift Reduction

ActionResponsi

bleTimefram

e

1. Implement new FERC Order on allocation of Real-time RMR charges to Real-time Load Obligation (RTLO) from Real-time deviations.

S. Hann March ‘05

2. Develop new RMR mitigation rules R. Ethier 2nd Qtr. ‘05

3. Develop new Combined Cycle unit dispatch process to gain additional unit flexibility

P. Brandien 3rd Qtr. ‘05

4. Develop new Day-Ahead Market commitment plan for RMR units

M. Taniwha 3rd Qtr. ‘05

5. Develop new ASM market to incent the addition of fast/quick start units into load pockets

V. Chadalavada

2nd Qtr. ‘06

6. Market enhancements to capture out-of-merit dispatch costs in reserve prices.

V. Chadalavada

3rd Qtr. ‘05

24

Monthly and YTD Total Uplift

Note: Overall uplift includes out of merit DA and RT Economic, RMR, VAR, and RT SCR components. MWh totals reported are the total hourly MWh for uplift flagged units.

-

100

200

300

400

500

600

700

800

J an Feb Mar Apr May J un J ul Aug Sep Oct Nov Dec

MWh Thousands

2004 2005

-

1

2

3

4

5

6

7


MWh Millions

2004 2005

-

5

10

15

20

25

30


$ Millions

2004 2005

-

20

40

60

80

100

120

140

160

180


$ Millions

2004 2005

MWh $Mil.

Mon

thY

TD

25

Day-Ahead vs. Real-Time Pricing

• This month vs. prior years• Day-ahead cleared load vs. real-time• Zonal and total inc’s and dec’s• De-listed capacity• Self-schedules• Day-ahead vs. real-time net interchange

26

Day-Ahead vs. Real-Time LMPs ($/MWh)

Year 20031 NEMA CT Maine NH VT RI SEMA WCMA HubDay-Ahead 48.84$ 50.50$ 44.92$ 47.87$ 49.65$ 48.11$ 47.73$ 48.99$ 48.97$ Real-Time 48.09$ 50.22$ 44.19$ 47.36$ 48.75$ 47.69$ 47.54$ 48.68$ 48.59$ Delta % -1.5% -0.6% -1.6% -1.1% -1.8% -0.9% -0.4% -0.6% -0.8%

Year 2004 NEMA CT Maine NH VT RI SEMA WCMA HubDay-Ahead 53.46$ 54.62$ 48.62$ 52.09$ 53.95$ 52.82$ 52.33$ 53.86$ 53.72$ Real-Time 51.46$ 52.80$ 47.79$ 50.72$ 52.32$ 51.21$ 50.72$ 52.33$ 52.13$ Delta % -3.7% -3.3% -1.7% -2.6% -3.0% -3.0% -3.1% -2.8% -3.0%

February-04 NEMA CT Maine NH VT RI SEMA WCMA HubDay-Ahead 50.42$ 52.15$ 45.84$ 49.74$ 51.39$ 50.33$ 49.76$ 51.35$ 51.21$ Real-Time 48.06$ 49.71$ 44.08$ 47.57$ 49.50$ 48.36$ 47.74$ 49.32$ 49.11$ Delta % -4.7% -4.7% -3.8% -4.4% -3.7% -3.9% -4.1% -4.0% -4.1%

February-05 NEMA CT Maine NH VT RI SEMA WCMA HubDay-Ahead 56.17$ 57.03$ 52.07$ 54.88$ 56.71$ 55.17$ 55.07$ 56.46$ 56.39$ Real-Time 53.02$ 54.43$ 50.13$ 52.43$ 54.01$ 52.56$ 52.47$ 53.78$ 53.71$ Delta % -5.6% -4.6% -3.7% -4.5% -4.8% -4.7% -4.7% -4.7% -4.8%

Full month’s data.


Potential Reasons:• Day-Ahead load obligations higher than Real-Time load obligations• De-listed units not offered in Day-Ahead market but scheduled in Real-

Time.• Units that self-schedule after close of Day-Ahead Market.• Real-time imports that exceed day-ahead imports.• Interface limit changes that occur resulting from transmission topology

changes leading units to be self- or ISO- scheduled after close of Day-Ahead Market

• Units committed by ISO as part of RAA process.

27

Day-Ahead Load Obligation Percentof Real-Time Load Obligation

Monthly Percent, Last 13 Months

85%

90%

95%

100%

105%

Feb-04 Apr-04 J un-04 Aug-04 Oct-04 Dec-04 Feb-05

Daily Percent, This Year vs. Last Year

90%

95%

100%

105%

110%

2/ 1 2/ 5 2/ 9 2/ 13 2/ 17 2/ 21 2/ 25 2/ 29

2004 2005

28

Zonal Increment Offers and Cleared Amounts

Monthly by Zone, This Year vs. Last Year

0

50,000

100,000

150,000

200,000

250,000

300,000

350,000

Hub ME NH VT CT RI SEMA WCMA NEMA

MW

h

Feb-04 Offers Feb-04 Cleared Feb-05 Offers Feb-05 Cleared


29

Zonal Decrement Bids and Cleared Amounts

Monthly by Zone, This Year vs. Last Year

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

Hub ME NH VT CT RI SEMA WCMA NEMA

MW

h

Feb-04 Bids Feb-04 Cleared Feb-05 Bids Feb-05 Cleared


30

Total Increment Offers and Decrement Bids

Overall, Last 13 Months

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

MW

h

I nc's Offered I nc's ClearedDec's Bid Dec's Cleared


31

De-listed Capacity, February 2005

This Month vs. Prior Year By Zone

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

ME NH VT CT SEMA WCMA NEMA Total

Su

mm

er

Ca

pa

cit

y (

MW

)

Feb- 04 Feb- 05

Total, Last 13 Months

-

200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

Su

mm

er

Cap

aci

ty (

MW

)


32

Dispatchable vs. Non-Dispatchable Generation

Monthly Energy

-

2,000

4,000

6,000

8,000

10,000

12,000

14,000

GW

h

Non- Dispatchable Dispatchable


33

Day-Ahead vs. Real-Time Net InterchangeFebruary 2005 vs. February 2004

Positive values are net imports.


2004

(200)

0

200

400

600

800

1,000

1,200

1,400

2/1 2/6 2/11 2/16 2/21 2/26

Avg

. H

ou

rly

MW

h

Day-Ahead Real-Time

2005

(200)

0

200

400

600

800

1,000

1,200

1,400

2/1 2/6 2/11 2/16 2/21 2/26A

vg

. H

ou

rly

MW

hDay-Ahead Real-Time

34

Action Proposals: Price Convergence

ActionResponsi

bleTimefram

e

1. Complete actions identified on the VAR Uplift Reduction Action Plan.

See slide 20

2. Complete actions identified on the RMR Uplift Reduction Action Plan.

See slide 23

35

DefinitionsUplift Make-whole payments made to resources whose hourly

commitment and dispatch by the ISO resulted in a shortfall between the resource’s offered value in the Energy and Regulation Markets and the revenue earned from output over the course of the day. Typically, this is the result of some out-of-merit operation of resources occurring in order to protect the overall resource adequacy and transmission security of the (specific locations or for the entire) control area.

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

SCR Uplift Uplift paid to units dispatched at the request of local transmission providers for purpose of managing constraints on the low voltage system. 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 (System-wide) Uplift

Uplift paid to an eligible resource that is not providing for RMR, VAR, or SCR requirements. These resources may have been providing first contingency coverage (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.

36

Back-Up Detail

37

Demand Response

38

Demand Response(Status as of March 1, 2005)

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

CT 231 165.6 8 14.9ME 8 104.5 0 0.0NEMA 114 44.9 3 24.2NH 8 18.5 0 0.0RI 16 3.3 4 0.4SEMA 87 9.4 1 0.1VT 16 13.4 0 0.0WCMA 95 27.1 0 0.0

Total 575 386.5 16 39.6

39

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

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

575 Assets 386.5 MW 16 Assets 39.6 MWZone Assets RT Price RT 30-Min RT 2-Hour Profiled Assets RT Price RT 30-Min RT 2-Hour Profiled

CT 231 31.8 133.4 0.4 0.0 8 9.0 5.9 0.0 0.0

SWCT* 175 5.2 106.1 0.4 0.0 6 0.0 5.9 0.0 0.0

ME 8 27.5 0.0 1.0 76.0 0 0.0 0.0 0.0 0.0

NEMA 114 39.0 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 4 0.4 0.0 0.0 0.0

SEMA 87 8.9 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 575 153.8 137.5 12.0 83.2 16.0 9.7 29.9 0.0 0.0

Ready To Respond: Approved:

40

New Generation

41

• No new resources were added in February.

• Approximately 110 MW of capacity expected on line by the end of the year.

• Status of Generation Projects as of March 4, 2005:

No. MWIn Construction 2 33.3

Not in Construction 7 1, 400

Nuclear Uprates 5 265

1 Proposed Plan approvals are pursuant to Section I.3.9 of the ISO New England Inc. Transmission, Markets and Services Tariff.

Generation Projects with Proposed Plan Approval1

New Generation Update

42

RSP (Regional System Plan)

43

RSP Update

• RSP05– Transmission Update reviewed by RC and PAC on 3/2. To

be reviewed by SPARC on 3/17.– PAC02 held on 3/3.– Detailed draft outline of RSP05 under development.

• Inter-ISO Update– Inter-ISO Planning Liaison Committee (IPLC)

• Final Draft Northeast Consolidated Plan (NCP) reviewed 3/8 and to be issued to Stakeholders on 3/31.

• NPCC– NERC Blackout issues being addressed through NPCC

(RCC Meeting 3/9).– TFCP provided input to the NERC TIS on issues 13C

(Voltage and Reactive Management) and 23 (Study of Reliability and Adequacy).

44

RSP Project Stage Descriptions

Stage Description

1Planning and Preparation of Project Configuration2Pre-construction (e.g., material ordering, project scheduling)3 Construction in Progress4 Completed

45

NSTAR 345 kV Transmission Reliability ProjectStatus as of March 7, 2005Project 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.

46

North Shore UpgradesStatus as of March 7, 2005

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.

47

SWCT 345 kV Transmission Reliability ProjectStatus as of March 7, 2005Project Benefit: Improves New England reliability by

addressing SWCT concerns. Increases SWCT Import Limit from 2,000 MW to approximately 3,400 MW.

Notes Phase 1:- Siting review complete; appeal denied.- Detailed engineering continues and some construction started.- TCA Application

• Received 1-12-05• RC and public meeting discussions held; another public hearing to be scheduled for March

- 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.- 2/14 (technical meeting) and 2/17 (ROC Report) hearings completed. All issues resolved with KEMA, the Siting Council’s consultant.


OriginalIn-service

Present Stage

Norwalk 345 kV Substation 3

Plumtree 345 kV Substation 3

Norwalk - Plumtree 345 kV 2

Associated 115 kV Line Work

Dec-04

Dec-04

Dec-04

Dec-04 2

Beseck 345 kV Substation 1

East Devon 345 kV Substation 1

Singer 345 kV Substation 1

Beseck - East Devon 345 kV 1

East Devon - Singer 345 kV 1

Singer - Norwalk 345 kV 1

Associated 115 kV Line Work

Jan-06

Jan-06

Jan-06

Jan-06

Jan-06

Jan-06

Jan-06 1

Phase 2

Phase 1Dec-06

Dec-06

Dec-06

Dec-06

Dec-09

Dec-09

Dec-09

Dec-09

Dec-09

Dec-09

Dec-09

48

Northeast Reliability Interconnect ProjectStatus as of March 7, 2005

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. Expect conclusion Fall 2005.

49

NWVT 345 kV Transmission Reliability ProjectStatus as of March 7, 2005

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. The major conditions of the

Siting Order are:• 1.3 miles of 115 kV in Bay Road area ordered underground.• New Haven substation to be relocated, if feasible.• System studies necessary that address the impacts of placing more 115 kV

underground.• Telephone, electric distribution, and cable TV lines required to be put

underground in some areas.- Order under review

50

Southern New England Reliability ProjectStatus as of March 7, 2005

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

Sample UpgradeExpectedIn-service

OriginalIn-service

Present Stage

Millbury - Sherman Rd. 345 kV 2011 Dec-08 1Sherman Rd. - Lake Rd. 345 kV 2011 Dec-08 1Lake Rd. - Card St. 345 kV 2011 Dec-08 1

345 kV Substation Modifications 2011 Dec-08 1

- Planning studies in progress; completion scheduled for June 2005.- Project specifics may change; preferred alternatives to be determined September 2005.- Project planning and coordination meetings continuing.- 18.4 Approval goal: July 2006

51

Reliability Agreement Summary

52

Reliability AgreementStatus as of March 4, 2005

UnitAnnual Fixed

CostSummer MW 2005 CELT $/kw-month(1) Effective Date

Status: Effective with Final FERC Approval Exelon New Boston 1 $30,000,000 350 $7.14 01/01/02NRG Devon 11-14 $19,568,124 121 $13.52 01/17/04NRG Middletown 2-4, 10 $49,617,744 770 $5.37 01/17/04NRG Montville 5,6, 10&11 $23,032,716 494 $3.89 01/17/04

Status: Effective and in FERC Settlement ProceedingMirant Kendall Steam 1 $4,933,064 15 $28.22 10/08/04Mirant Kendall Steam 2 $5,964,958 21 $23.67 10/08/04Mirant Kendall Jet 1 $2,763,096 17 $13.69 10/08/04PSEG New Haven Harbor $47,368,806 448 $8.81 01/17/05PSEG Bridgeport Harbor 2 $19,012,116 130 $12.14 01/17/05

Status: Filed at FERC - Not EffectiveDominion Salem Harbor(2) $85,000,000 743 $9.54 Not Applicable

Milford Power 1 $40,824,787 239 $14.23 Not ApplicableMilford Power 2 $40,797,848 254 $13.41 Not ApplicableBridgeport Energy $57,825,915 451 $10.68 Not Applicable

(1) Does not reflect the netting of Market Revenues that are in excess of variable costs.(2) Environmental upgrades, in Settlement proceeding

53For additional information, please go to: http://www.iso-ne.com/settlement_reports/Reliability_Agreement_Information/

UnitAnnual Fixed

CostSummer MW 2005 CELT $/kw-month(1) Effective Date

Status: Reliability Determination Given - No FERC Filing YetBoston Generating Mystic 7, 8, 9 N/A 1953 N/A Not Applicable

Status: Reliability Determination PendingConEdison West Springfield 3 N/A 101 N/A Not Applicable

FPL Yarmouth 4 N/A 604 N/A Not Applicable

Indeck Enfield N/A 21 N/A Not Applicable

Indeck Jonesboro N/A 0.00 2 N/A Not Applicable

Ridgewood N/A 2 N/A Not Applicable

Blackstone Tupperware N/A 4 N/A Not Applicable

Status: Rejected by FERC, Pending Court of AppealsPPL Wallingford 2-5 $25,661,138 176 $12.16 Not Applicable

(1) Does not reflect the netting of Market Revenues that are in excess of variable costs.(2) Anticipated demonstration of 20 MW.

Unit

Annual Costs Prior to

TerminationSummer MW 2005 CELT $/kw-month(1) Termination Date

Status: Terminated RMR AgreementsNRG Devon 7 & 8 $15,626,245 214 $6.09 04/27/04NRG Devon 7 alone $13,028,705 107 $10.15 10/01/04

NRG Reliability Cost Tracker $30,000,000 1726 $1.45 12/31/04(2)

(1) Does not reflect the netting of Market Revenues that are in excess of variable costs.(2) Effectively terminated except for certain true-up provisions

Reliability Agreement, Con’t.Status as of March 4, 2005

http://www.iso-ne.com/settlement_reports/Reliability_Agreement_Information/

nepool participants committee meeting waterville valley, nh march 11, 2005

Documents

market demand

market generation

demand gen forecast

real time load

y ahead market

real time lmps

dayahead lmps

25sheet1december data