NEPOOL Participants Committee Meeting

April 4, 2003

Boston, MA

Stephen G. WhitleySenior Vice President & COO

2

• System Operations

• Gas Study Initiative

• SMD Market Operations Update

• Summer 2003 – “A Look Ahead”

• ISO/NEPOOL Cost Causation Update

• Demand Response Kickoff Update

• Back – Up Details– Demand Response– New Generation– SW CT/Boston

Agenda

3

System Operations

4

Operation’s Highlights

• Boston & Hartford Weather Pattern: – Temperatures were below the average (longest sustained 6-

month period in 50 years) with normal to above normal precipitation.

• Peak Load– Peak load of 18,039 MW at 20:00 hours on March 31.

• During March– Minimum Generation on March 22 & 28.– Requested Shared Activation of Reserves (SAR) – March 5, 7

and 20(2); Provided SAR on March 29.– Resources postured on March 22, 23, 28 and 30.– Emergency Sales on March 3.– Solar Magnetic Disturbances – K7 forecasts on March 17 & 18.– The following were not implemented in March:

• M/S#2; • M/S#3;• OP#4; and,• Class 6 Load Management.

5

Gas Study

6

Gas Study Update

• Northeast very dependent on gas storage during winter heating season.

• Too much cold weather beginning in November – January 2003 – Almost a peak design/month.

• Depletion of working gas storage inventories.• Maintenance of line pack is a daily issue.• LNG is OK (Distrigas).• ISO-NE is performing a post-winter

assessmentto determine the capacity impacts on gas-fired generation.

7

Winter Capacity of Gas Capable Units

SMD Zone

Gas Only

Primary Gas

w/No.2 Fuel Oil

Primary No.2 Fuel Oil

w/Gas Backup

Primary No.6 Fuel Oil w/Gas

Backup

Other fuel

w/Gas Backup Totals

CT 778 1,636 - 902 - 3,316 ME 1,365 349 - - 108 1,822 NEMA 1,868 83 117 623 2,691 NH - 1,305 - 400 1,705 RI 2,046 - - - 2,046 SEMASS 1,360 1,335 56 1,118 3,869 VT - - - - 53 53 WCMA 173 1,187 354 115 1,829 Totals 7,590 5,895 527 3,158 161 17,331

Includes 2003 units: AES GRANITE RIDGE, MILFORD PDC, SITHE FORE RIVER, SITHE MYSTIC

Gas Study Update

8

Temperature Impacts on Gas-Fired

Generating Capacity, 12/02 – 3/03

0

400

800

1,200

1,600

2,000

2,400

12/1 12/15 12/29 1/12 1/26 2/9 2/23 3/9 3/23

MW

Cur

taile

d

0

10

20

30

40

50

60

Tem

p. @

Pea

k

MW Temp. @ PeakPeak Day Temp.

Gas Study Update

9

1) Assume Salem Harbor Is Converted To Fire Natural Gas: 1.1 Assume final technology will attain compliance with the MA DEP 310

CMR 7.29 by October 2004 or October 2006. 1.2 Assume Salem Harbor’s conversion to fire natural gas uses existing

infrastructure & design (steam turbine generator mode) and reflects minimization of costs.

1.3 Discuss whether residual fuel oil or distillate oil is a viable primary or backup fuel.

2) Assess Natural Gas Supply Issues:

2.1 Discuss the uncertainties surrounding natural gas supplies from North America, including Sable Island, Gulf Coast, Western Canada, and LNG.

2.1 Discuss current exploration and production (E&P) outlook in Atlantic Canada, including retrenchment of Canadian majors, expiry profiles, and production constraints.

2.2 Discuss current issues concerning maturation of the resource base in North America, accelerated “depletion rates,” storage issues affecting the Northeast, and gas price volatility parameters.

2.3 Discuss potential electric sector impacts from sustained high natural gas prices.

2.4 Discuss Canadian and U.S. regulatory issues associated with transport pricing on TransCanada Pipeline (TCPL), Iroquois Gas Transmission System (IGTS), Portland Natural Gas Transmission System (PNGTS), and Maritime & Northeast (M&N).

2.5 Discuss supply issues relative to LNG sources and increased worldwide demand.

Gas Study Update – Scope of Work“A Natural Gas Assessment & Reliability Implications for New England’s Electric Generation Sector”

10

Gas Study Update – Scope of Work, cont.

“A Natural Gas Assessment & Reliability Implications for New England’s Electric Generation Sector”

Assess Natural Gas Deliverability Issues Affecting New England: 3.1 Discuss on a seasonal basis (winter & summer), the current and future

deliverability concerns impacting both New England, and in particular, the transmission constrained greater Boston-area load pocket.

3.2 Discuss current and future LNG supply adequacy concerns impacting New Mystic station.

3.3 Discuss deliverability issues in Items 3.1 & 3.2, both with and without Salem Harbor as a natural gas fired facility.

3.4 For Items 3.1, 3.2, & 3.3, discuss seasonal (winter and summer) electric sector reliability issues relating to:

3.4.1 Impacts associated with new Homeland Security requirements (to be defined).

3.4.2 Postulated discontinued LNG refills at the Distrigas terminal in Everett (short duration), including loss of truck-transported liquids.

3.4.3 Postulated discontinued LNG refills at the Distrigas terminal in Everett (long duration), including loss of truck-transported liquids.

3.4.4 Potential impacts due to gas-side contingencies. 3.4.5 Post-contingency sustainability issues surrounding

emergency pipeline supplies from other New England pipelines. Addressed both with and without a New Mystic connection to HubLine through the proposed Everett lateral.

11

Assess Fuel Diversity Concerns: 4.1 Discuss seasonal electric sector reliability issues surrounding New England

merchant generators’ growing reliance on natural gas. 4.2 Discuss overall portfolio concerns about decreasing fuel diversity for both New

England, and in particular, the transmission constrained greater Boston sub-area. 4.3 Discuss the relationship between fuel diversity and volatility events at gas market

hubs in New England. 4.4 Discuss impacts both with and without Salem Harbor burning natural gas.

Gas Study Update – Scope of Work, cont.

“A Natural Gas Assessment & Reliability Implications for New England’s Electric Generation Sector”

12

SMD Operations

13

SMD Experience in March

• Standard Market Design (SMD) cut-over was virtually seamless.

• The March implementation date was designed to allow for a learning curve prior to the summer.

• Energy prices were consistent with the cost of fuel:– Higher fuel costs in the first few weeks created

higher energy prices; and,– Recently, energy prices have decreased

consistent with the downward trend of fuel prices.• Software and business systems have generally

worked well and functioning as designed.– Limited number of hardware and software issues,

resulted in interruption of data flow.

14

SMD Experience in March (cont.)

• Potential for error is elevated during this learning process:– Internally

• Data – issues such as Non-PTF Loss Factors• Operator Error – RT dispatch or selection in day ahead

– Externally• Methods used to reflect “Seller Choice” strategies• Self Scheduling

• Internal decisions reviewed and business process and software tools enhanced to mitigate potential for repeat.

• No reliability issues since going live.• NERC Control Performance within criteria.• Conditions experienced in Real-time so far:

– Congestion;– Excess ramping curtailments;– Minimum generation emergency; – Major generation contingencies; and,– Emergency sales.

15

SMD Action Plan

Action Date Computer Systems

Data availability and navigation improvements to the web site.

List servers in addition to web postings.

May – June 2003 Special notices now available.

Customer Forums Outage Coordination SMD Unit Commitment and Market Mitigation SMD Markets Forum

April May Fall

Online Forums Summer Operational and Market Issues

As needed.

Customer Training FTR/ARR re-offer with QUA’s Virtual Markets Workshop Capacity Market Workshop Full SMD Training re-offer

May June September/October September/October

16

March 2003

$0.00

$20.00

$40.00

$60.00

$80.00

$100.00

$120.00

$140.00

03/01/2003 03/06/2003 03/11/2003 03/16/2003 03/21/2003 03/26/2003 03/31/2003

Date

$/M

Wh

Average DA Price Average RT Price

Average Spread (DA - RT): $1.39

Ave. % DA Pool Generation Cleared vs. Forecast Load: 91%

Ave. % DA Demand Cleared vs. Forecast Load: 96%

Day-ahead & Real-time Prices, ISO-NE Hub

17

March 2003

-$10.00

$10.00

$30.00

$50.00

$70.00

Hub ME NH VT CT RI SEMASS WCMASS NEMASS& Boston

Region

$/M

Wh

LMP Marginal Loss Component Congestion Component

(-1.3) (-1.4) (+0.1) (-2.7) (-2.8)

Day Ahead – LMP Average by Zone & Hub

18

March 2003

-$10.00

$10.00

$30.00

$50.00

$70.00

Hub ME NH VT CT RI SEMASS WCMASS NEMASS& Boston

Region

$/M

Wh

LMP Marginal Loss Component Congestion Component

97.4%

(-5.7) (-1.5) (+0.1) (+0.1) (-2.6) (-2.0)

Real Time – LMP Average by Zone & Hub

19

March 2003

0

25

50

75

100

125

150

175

200

Day

$/M

Wh

WCMASS CONNECTICUT MAINE NEMASSBOST NEWHAMPSHIRE

RHODEISLAND SEMASS VERMONT INTERNAL_HUB

Minimum Generation

Emergencies

Real-time LMP

20

March 2003

0

20

40

60

80

100

120

140

160

180

200

220

Day

$/M

Wh

CONNECTICUT MAINE NEMASSBOST NEWHAMPSHIRE RHODEISLAND

SEMASS VERMONT WCMASS INTERNAL_HUB

No significant transmission outages;

Maine and NEMASSBOST

Congestion resulted Bidding

Patterns

379 OOS, Virtual Bids;

Resulting congestion on W149

for L/O 340

PV20 was OOS

causing

congestion on

NWVT_I

1977 OOS; 1710 Line

constrained for L/O 1480

Bus Tie

379 OOS, Virtual Bids;

Resulting congestion on

W149 for L/O 340

303 Line Terminal OOS;

C129N-2 Line constrained for L/O 315

Line

DAM LMP

21

Summer 2003

22

Summer 2003 Capacity

AssessmentLeast Operable Capacity Margin - Weeks beginning June

7, 14 and 21 MW

Projected Peak (50/50) 25,120

Operating Reserve Required 1,700

Total Operable Cap. Required 26,820

Projected Capacity 31,920

Assumed Outages 3,600

Total Capacity 28,320

Operable Capacity Margin 1,500

23

Week Beginning, Saturday

Year Month Day

Installed Seasonal Claimed

Capability (SCC)

[Note 1]

Interchange (NYPP, NB, HQ, Highgate,

Block Load)

Note

New Generation

[Note 2]Net

Capacity

Peak Load Exposure [Note 3]

Operating Reserve

Requirement [Note 4]

Total Known Maintenance

Allowance for

Unplanned Outages [Note 6]

Operable Capacity

Margin (+/-)

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

Actions up to and including) [Note 7]

(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW)2003 May 31 27,974 550 3,400 31,920 21,580 1,700 1,000 2,800 4,840

2003 June 7 27,974 550 3,400 31,920 25,120 1,700 800 2,800 1,500

14 27,974 550 3,400 31,920 25,120 1,700 800 2,800 1,500

21 27,974 550 3,400 31,920 25,120 1,700 800 2,800 1,500

28 27,936 550 3,400 31,890 25,120 1,700 100 2,800 2,170

2003 July 5 27,936 550 3,400 31,890 25,120 1,700 100 2,100 2,870

12 27,936 550 3,400 31,890 25,120 1,700 100 2,100 2,870

19 27,936 550 3,400 31,890 25,120 1,700 100 2,100 2,870

26 27,937 550 3,400 31,890 25,120 1,700 100 2,100 2,870

2003 August 2 27,937 550 3,500 31,990 25,120 1,700 100 2,100 2,970

9 27,937 550 3,500 31,990 25,120 1,700 100 2,100 2,970

16 27,937 550 3,500 31,990 25,120 1,700 200 2,100 2,870

23 27,937 550 3,500 31,990 25,120 1,700 300 2,100 2,770

30 27,937 550 3,500 31,990 25,120 1,700 500 2,100 2,570

2003 September 6 27,937 550 3,500 31,990 23,100 1,700 1,100 2,100 3,990

13 27,937 550 3,500 31,990 21,850 1,700 800 2,100 5,540

20 27,937 550 3,500 31,990 21,520 1,700 2,000 2,100 4,670

27 29,994 550 3,500 34,040 21,440 1,700 1,200 2,100 7,600

2003 October 4 29,994 710 3,500 34,200 17,310 1,700 3,900 2,800 8,490

Notes:

1. Installed Capability per March 1, 2003 SCC Report and adjusted for known generator additions.2. New Generation information as assumed by ISO-NE Planning Department and rounded to the nearest hundred.3. Peak Load Exposure per the preliminary April 2003 CELT Report. 4. Operating Reserve Requirement based on the first contingency (Generator at 1160 MW) plus 1/2 the second contingency (Generator at 1145 MW).5. Highgate maintenance scheduled.6. Allowance for Unplanned Outages includes: forced outages and maintenance outages scheduled less than 14 days in advance.7. Relief from certain OP 4 Actions varies, depending on system conditions.

ISO-NE 2003 OPERABLE CAPACITY ANALYSIS

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.

March 15, 2003 - WITH KNOWN EXTERNAL CONTRACTS - 50th PERCENTILE PLEThis 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 a

Summer 2003 Capacity

Assessment

24

Summer 2003 Capacity AssessmentNEPOOL Operating Capacity Margins - 50th Percentile PLE

WITH KNOWN EXTERNAL TRANSACTIONS

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

June - September 2003, W/B Saturday

Ope

ratin

g C

apac

ity M

argi

n (M

W)

25

Summer 2003 Capacity

AssessmentLeast Operable Capacity Margin - Weeks beginning June

7, 14 and 21 MW

Projected Peak (90/10) 26,630Operating Reserve Required 1,700Total Operable Cap. Required 28,330Projected Capacity 31,920Assumed Outages 3,600Total Capacity 28,320Operable Capacity Margin

(10)

26

Summer 2003 Capacity

Assessment

Week Beginning, Saturday

Year Month Day

Installed Seasonal Claimed

Capability (SCC)

[Note 1]

Interchange (NYPP, NB, HQ, Highgate,

Block Load)

Note

New Generation

[Note 2]Net

Capacity

Peak Load Exposure [Note 3]

Operating Reserve

Requirement [Note 4]

Total Known Maintenance

Allowance for

Unplanned Outages [Note 6]

Operable Capacity

Margin (+/-) With HQ

FEC

Operable Capacity

Margin (+/-)

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

Actions up to and including) [Note 7]

(MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW) (MW)2003 May 31 27,974 550 3,400 31,920 22,880 1,700 1,000 2,800 3,540 3,540

2003 June 7 27,974 550 3,400 31,920 26,630 1,700 800 2,800 (10) (10) Action 5

14 27,974 550 3,400 31,920 26,630 1,700 800 2,800 (10) (10) Action 5

21 27,974 550 3,400 31,920 26,630 1,700 800 2,800 (10) (10) Action 5

28 27,936 550 3,400 31,890 26,630 1,700 100 2,800 660 660

2003 July 5 27,936 550 3,400 31,890 26,630 1,700 100 2,100 1,360 1,360

12 27,936 550 3,400 31,890 26,630 1,700 100 2,100 1,360 1,360

19 27,936 550 3,400 31,890 26,630 1,700 100 2,100 1,360 1,360

26 27,937 550 3,400 31,890 26,630 1,700 100 2,100 1,360 1,360

2003 August 2 27,937 550 3,500 31,990 26,630 1,700 100 2,100 1,460 1,460

9 27,937 550 3,500 31,990 26,630 1,700 100 2,100 1,460 1,460

16 27,937 550 3,500 31,990 26,630 1,700 200 2,100 1,360 1,360

23 27,937 550 3,500 31,990 26,630 1,700 300 2,100 1,260 1,260

30 27,937 550 3,500 31,990 26,630 1,700 500 2,100 1,060 1,060

2003 September 6 27,937 550 3,500 31,990 24,490 1,700 1,100 2,100 2,600 2,600

13 27,937 550 3,500 31,990 23,170 1,700 800 2,100 4,220 4,220

20 27,937 550 3,500 31,990 22,820 1,700 2,000 2,100 3,370 3,370

27 29,994 550 3,500 34,040 22,730 1,700 1,200 2,100 6,310 6,310

2003 October 4 29,994 710 3,500 34,200 18,000 1,700 3,900 2,800 7,800 7,800

Notes:

1. Installed Capability per March 1, 2003 SCC Report and adjusted for known generator additions.2. New Generation information as assumed by ISO-NE Planning Department and rounded to the nearest hundred.3. Peak Load Exposure per the preliminary April 2003 CELT Report. 4. Operating Reserve Requirement based on the first contingency (Generator at 1160 MW) plus 1/2 the second contingency (Generator at 1145 MW).5. Highgate maintenance scheduled.6. Allowance for Unplanned Outages includes: forced outages and maintenance outages scheduled less than 14 days in advance.7. Relief from certain OP 4 Actions varies, depending on system conditions.

ISO-NE 2003 OPERABLE CAPACITY ANALYSIS

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.

March 15, 2003 - WITH KNOWN EXTERNAL CONTRACTS - 90th PERCENTILE PLE 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 a

27

Summer 2003 Capacity AssessmentNEPOOL Operating Capacity Margins - 90th Percentile PLE

WITH KNOWN EXTERNAL TRANSACTIONS - 90th PERCENTILE PLE

(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

June - September 2003, W/B Saturday

Ope

ratin

g C

apac

ity M

argi

n (M

W)

OP- 4 Action 5

28

Cost Causation for System Upgrades

29

Transmission Cost Allocation Workshops

1. ISO-NE presented “staff recommendation” for transmission cost allocation at the fourth and final stakeholder workshop on March 14.

2. Workshop participants included regulators from all six New England states and the FERC. (ISO-NE Board members also in attendance).

3. ISO-NE invited further comment beyond the workshop.4. Next steps:

1. Present ISO-NE staff proposal to NECPUC and NEPOOL Tariff Committee (April);

2. Investigate least-cost-planning and resource parity issues with NECPUC and NEPOOL (April-June);

3. Present proposal to NPC and ISO-NE Board (May); and,

4. File proposal with the FERC (May).

30

ISO-NE Cost Allocation Method Proposal

1. ISO-NE/NEPOOL define upgrade categories.2. Through RTEP, ISO staff recommends to

SPARC/BOD each upgrade’s assignment to the appropriate category.

3. If the assignment can be reasonably made to both local or regional, Regional Cost Allocation is utilized.

4. Regional Mechanism – Project is “Regionalized” for the life of the project if:• Project provides loop/network benefits… 2-way

traffic; and,• Project is 115-kV and above.

5. Any discretionary costs are borne by the entity requiring the special design (e.g. entities requesting underground).

31

System Upgrade Categories

A. Generator Interconnections• Generator interconnection in accordance with “minimum inter-connection standard.”

Direct Assignment

B. Participant Funding Voluntary among Participants

C. Load Interconnection• Second feed to industrial substation.

Direct Assignment to Load

D. Local• Radial transmission line.• 13-kV capacitor bank.• Project that does not improve inter-area transfer capability.

Individual sub-areas

E. Regional or Network• Loop/network project that increase inter- area transfer capability. Two-way traffic.• Phase shifting transformer, FACTS device.

Load Pro-rata (roll in)

32

Demand Response Summit

33

8: 30 – 9:00 Registration and Continental Breakfast Visit Exhibitor Booths

9:00 – 9: 20 Welcome and Opening Remarks “What is Demand Response and How Can Customers Benefit” Steve Whitley, Chief Operating Officer, ISO New England Inc.

9:20 – 10:30 Case Studies and Lessons Learned: Presentations by customers, utilities and competitive suppliers describing their experiences participating in the 2002 Demand Response Programs. Learn first-hand from customers what it takes to successfully participate in a program, the benefits they received and their lessons learned.

10:30 – 10:45 Break 10:45 – 11:15 Technology for Demand Response

Presentations by leading metering, technology and software providers describing how their products and services have helped customers reduce load and participate in the Demand Response Programs. In addition, learn about the other benefits these technologies and information services deliver.

11:15 – 11:45 What’s New for 2003? Presentations by ISO New England on the changes and new programs for 2003.

11:45 – Noon Q&A and Closing Comments

New England Demand Response Summit

Radisson Hotel75 Felton StreetMarlborough, MA

April 17, 20038:30 a.m. – 12:00 p.m.

34

Back-Up Details

35

Demand Response(as of March 31, 2003)

Active: 212 Assets 284.0 MW Pending: 15 Asset 7.5 MWZone Assets RT

PriceRT 30-

MinProfiled

*Assets RT

PriceRT 30-

MinProfiled

*CT 88 38.3 18.2 76.6 13 0.2 4.5

ME 29 20.3 65.0NEMA 19 26.0 7.2 1.4 4 1.9

NH 2 0.1 0.4RI 7 0.8SEMA 14 1.7 0.8 1 0.4

VT 7 1.1 2.0 5.0WCMA 46 4.8 7.1 7.3 1 0.5

Total 212 93.1 35.7 155.2 19 0.2 7.3 0.0

* Represents former Type 2 Interruptible Loads

36

New Generation Update (Revised)

• No new generating resources were added in March

• Approximately 3,382 MW expected by June 2003

• Generation Projects as of March 14, 2003

No. MW

In Construction 6 3,382with 18.4 approval

Not in Construction 5 1,783with 18.4 Approval

37

• NRG– NRG filed Cost-of-Service RMR Contracts on February 26.– Annual fixed cost of about $180 million, including $44 million for

normal and deferred maintenance.– FERC issued an order on NRG’s emergency motion on March 25,

putting the “Reliability Cost Tracker” in place effective February 27.– ISO-NE to serve as escrow agent for these funds.

• PPL– PPL Requesting Cost of Service RMR Contracts for Wallingford

Station – Four of Five Nominal 45MW Peaking Units.– Filed on January 16, 2003. FERC issued Deficiency Letter on

February 28, 2003.– PPL responded on March 31 and stated they will file an 18.4

Application for temporary deactivation effective July 1, 2003.

RMR Contracts

38

RMR Contracts

• PG&E (PGET and USGen New England)

– Considering filing an 18.4 Application for Salem Harbor 1-4 effective October 1, 2004.

– Governor has stated that units must be in environmental compliance by that date or shut down.

– PG&E was planning environmental upgrades for compliance by October 1, 2006.

– October 1, 2004 date is under appeal before a DEP ALJ.– ISO in discussion with DOER and DTE, National Grid

and NSTAR on NEMA reliability needs and possible transmission improvements.

(cont.)