nepool participants committee meeting boston, ma january 7, 2005
DESCRIPTION
NEPOOL Participants Committee Meeting Boston, MA January 7, 2005. Stephen G. Whitley Senior Vice President & COO. Agenda. System Operations Market Operations Status of Non-PTF Ties Winter 2004/2005 Outlook Back-Up Detail. System Operations. Operations Highlights. - PowerPoint PPT PresentationTRANSCRIPT
NEPOOL Participants Committee Meeting
Boston, MA
January 7, 2005
Stephen G. WhitleySenior Vice President & COO
2
• System Operations• Market Operations• Status of Non-PTF Ties• Winter 2004/2005 Outlook• Back-Up Detail
Agenda
3
System Operations
4
Operations Highlights• Boston & Hartford Weather Pattern:
– Temperatures were higher during December with below normal precipitation.• Peak load of 22,524 MW at 18:00 hours on December 20, 2004.• During December:
– OP #4• Actions 1 & 6 implemented system wide
– NPCC Shared Activation of Reserve Events:• December 16 NE – Granite Ridge @617 Mw• December 21 NY – Bowline #2 @567 Mw
– MS #2• December 20 – Capacity
– Resources Postured• December 20
5
Market Operations
6
Day–Ahead & Real-Time Prices, ISO Hub:
Note: Natural Gas source is Algonquin Citygates Price.
Daily Natural Gas Price $7.15/MMBtu
OP.4 Declared
Daily Natural Gas Price $7.38/MMBtu
MS2 Declared
7
Day-Ahead–LMP Average by Zone & Hub:
LMP Marginal Loss Component Congestion Component
December 1, 2004 to December 29, 2004 : Day-Ahead LMPs
(-8.92%)
(-3.22%)
(-0.44%)
(-0.03%)
(-1.55%)
(-2.24%)
(0.09%)
(3.04%)
8
Real-Time-LMP Average by Zone & Hub:
97.4%
LMP Marginal Loss Component Congestion Component
(-7.39%)
(-2.50%)
(-0.31%)
(-0.27%)
(-1.57%)
(-2.34%)
(-0.02%)
(-1.18%)
December 1, 2004 to December 29, 2004 : Real-Time LMPs
9
Day - Ahead Market vs. Forecast Load
Day Ahead Market Demand Cleared vs. Forecast Load (%)
99102102
020406080
100120
October November December
December data represents December 1-December 29
Day Ahead Market Generation Cleared vs. Forecast Load (%)
909391
0
20
40
60
80
100
October November December
December data represents December 1-December 29
10
Day - Ahead LMPDAM LMP November 24, 2004 Through December 29, 2004
20.00
40.00
60.00
80.00
100.00
120.00
140.00
160.00
11/2
4/20
04 0
1
11/2
6/20
04 0
1
11/2
8/20
04 0
1
11/3
0/20
04 0
1
12/0
2/20
04 0
1
12/0
4/20
04 0
1
12/0
6/20
04 0
1
12/0
8/20
04 0
1
12/1
0/20
04 0
1
12/1
2/20
04 0
1
12/1
4/20
04 0
1
12/1
6/20
04 0
1
12/1
8/20
04 0
1
12/2
0/20
04 0
1
12/2
2/20
04 0
1
12/2
4/20
04 0
1
12/2
6/20
04 0
1
12/2
8/20
04 0
1
Day
$/M
Wh
INTERNAL_HUB CONNECTICUT MAINE NEMASSBOST NEWHAMPSHIRE
RHODEISLAND SEMASS VERMONT WCMASS
BSTN interface constraint binding during peak load period due to
load and generation pattern.
11
Real - Time LMPReal-Time LMP November 24, 2004 Through December 29, 2004
0
20
40
60
80
100
120
140
160
180
11/2
4/20
04 0
1
11/2
6/20
04 0
1
11/2
8/20
04 0
1
11/3
0/20
04 0
1
12/0
2/20
04 0
1
12/0
4/20
04 0
1
12/0
6/20
04 0
1
12/0
8/20
04 0
1
12/1
0/20
04 0
1
12/1
2/20
04 0
1
12/1
4/20
04 0
1
12/1
6/20
04 0
1
12/1
8/20
04 0
1
12/2
0/20
04 0
1
12/2
2/20
04 0
1
12/2
4/20
04 0
1
12/2
6/20
04 0
1
12/2
8/20
04 0
1
Day
$/M
Wh
INTERNAL_HUB CONNECTICUT MAINE NEMASSBOST NEWHAMPSHIRERHODEISLAND SEMASS VERMONT WCMASS
Minimum Generation Emergency
OP4 Conditions due to deficiencies in Operating Reserves. Zonal LMPs >
$600.00 for HE 17.
Declared MLCC-2 due to capacity deficiences in Operating Reserves.
Zonal LMPs >300.00 for HE 19.
NRST Interface and 1480_Trumbull_1730-1_A constraints
binding with 1710 line OOS.
NRST Interface constraint binding with 1710 line OOS.
Peak load period for the day.
12
Settlement Data – Real Time & Balancing Market
Minimum % of Real-Time Load Fully Hedged Through ISO-NE Settlement System
6 8 %
7 0 %
7 2 %
7 5 % 7 5 %7 3 %
7 1% 7 1%7 7 % 7 3 %
7 2 %7 1% 7 1% 7 0 %
7 1% 7 2 %7 0 %7 0 %
7 4 %
50%
55%
60%
65%
70%
75%
80%
Month
% R
T L
oad
Fu
lly
Hed
ged
Note: Partial Month Data: December 1 - 22, 2004
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-04
May
-04
Jun-
04Ju
l-04
Aug-04
Sep-
04
Oct-04
Nov
-04
Dec-04
DA RMR DA Economic RT RMR RT EconomicNote: Sept.-October subject to 90-Day Resettlement
December Data values through the 22nd.
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
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
Oct-04
Nov-0
4
Dec-0
4
DA VAR RT VAR RT SCR * - denotes 90-Day Resettlement values reflectedDecember values through the 22nd.
15
Status of Non-PTF Ties(Discussion Lead by Steve
Whitley)
16
Winter Outlook
17
Winter 2005 Capacity Assessment 50/50 Forecast
January through March ’05Conditions for Week of Lowest Operable Capacity Margin
Week beginning January 15th
MWProjected Peak (50/50) 22,370 Operating Reserve Required 1,700Total Operable Cap. Required 24,070Projected Capacity 32,3801
Assumed Outages 6,500Total Capacity 25,880Operable Capacity Margin 1,8101 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.
18
Winter 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 January 8 33,066 260 0 950 32,380 22,370 1,700 700 2,800 2,800 26,080 2,010
15 33,066 260 0 950 32,380 22,370 1,700 900 2,800 2,800 25,880 1,810 22 33,066 260 0 950 32,380 22,370 1,700 600 2,800 2,800 26,180 2,110 29 33,068 260 0 950 32,380 22,146 1,700 700 3,100 2,250 26,330 2,480
2005 February 5 33,068 450 0 950 32,570 21,878 1,700 1,000 3,100 2,250 26,220 2,640 12 33,068 450 0 950 32,570 21,849 1,700 1,100 3,100 2,250 26,120 2,570 19 33,068 450 0 950 32,570 21,585 1,700 1,800 3,100 0 27,670 4,390 26 33,073 450 0 950 32,570 20,592 1,700 1,900 2,200 0 28,470 6,180
2005 March 5 33,073 450 0 950 32,570 20,240 1,700 3,200 2,200 0 27,170 5,230 12 33,073 450 0 950 32,570 20,044 1,700 3,300 2,200 0 27,070 5,330 19 33,073 450 0 950 32,570 19,677 1,700 3,600 2,200 0 26,770 5,390 26 33,073 450 0 950 32,570 19,108 1,700 3,300 2,200 0 27,070 6,260
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 January 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 January, 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 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 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 ANALYSISJanuary 4, 2005 - WITH KNOWN EXTERNAL CONTRACTS - 50/50 FORECAST
19
Winter 2005 Capacity
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
8-J
an
15
-Ja
n
22
-Ja
n
29
-Ja
n
5-F
eb
12
-Fe
b
19
-Fe
b
26
-Fe
b
5-M
ar
12
-Ma
r
19
-Ma
r
26
-Ma
r
January - March 2005, W/B Saturday
Ope
ratin
g C
apac
ity M
argi
n (M
W)
20
Winter 2005 Capacity Assessment 90/10 Forecast January through March ’05Conditions for Week of Lowest Operable Capacity Margin
Weeks beginning January 8th – 22nd
MWProjected Peak (90/10) 23,255 Operating Reserve Required 1,700Total Operable Cap. Required 24,955Projected Capacity 32,3801
Assumed Outages 7,000Total Capacity 25,380Operable Capacity Margin 425Assumed 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.
21
Winter 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 January 8 33,066 260 0 950 32,380 23,255 1,700 700 2,800 3,500 25,380 430
15 33,066 260 0 950 32,380 23,255 1,700 900 2,800 3,300 25,380 430 22 33,066 260 0 950 32,380 23,255 1,700 600 2,800 3,600 25,380 430 29 33,068 260 0 950 32,380 23,025 1,700 700 3,100 3,200 25,380 660
2005 February 5 33,068 450 0 950 32,570 22,745 1,700 1,000 3,100 2,900 25,570 1,130 12 33,068 450 0 950 32,570 22,715 1,700 1,100 3,100 2,800 25,570 1,160 19 33,068 450 0 950 32,570 22,441 1,700 1,800 3,100 0 27,670 3,530 26 33,073 450 0 950 32,570 21,408 1,700 1,900 2,200 0 28,470 5,360
2005 March 5 33,073 450 0 950 32,570 21,043 1,700 3,200 2,200 0 27,170 4,430 12 33,073 450 0 950 32,570 20,838 1,700 3,300 2,200 0 27,070 4,530 19 33,073 450 0 950 32,570 20,457 1,700 3,600 2,200 0 26,770 4,610 26 33,073 450 0 950 32,570 19,866 1,700 3,300 2,200 0 27,070 5,500
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 January 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 January, 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 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 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 ANALYSISJanuary 4, 2005 - WITH KNOWN EXTERNAL CONTRACTS - 90/10 FORECAST
22
Winter 2005 Capacity
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
8-J
an
15
-Ja
n
22
-Ja
n
29
-Ja
n
5-F
eb
12
-Fe
b
19
-Fe
b
26
-Fe
b
5-M
ar
12
-Ma
r
19
-Ma
r
26
-Ma
r
January - March 2005, W/B Saturday
Ope
ratin
g C
apac
ity M
argi
n (M
W)
23
Back-Up Detail
24
Demand Response
25
Demand Response(as of January 3, 2005)
ReadyTo Respond: Approved:Zone Assets Total MW Assets Total MW
CT 200 148.2 24 26.5ME 8 104.5 0 0.0NEMA 114 44.9 1 24.0NH 8 18.5 0 0.0RI 11 2.8 0 0.0SEMA 82 8.9 0 0.0VT 17 13.5 0 0.0WCMA 94 27.0 0 0.0
Total 534 368.2 25 50.5
26
Demand Response, Con’t. (as of January 3, 2005)
* SWCT assets are included in CT values and are not included in Total
534 Assets 368.2 MW 25 Assets 50.5 MWZone Assets RT Price RT 30-Min RT 2-Hour Profiled Assets RT Price RT 30-Min RT 2-Hour Profiled
CT 200 31.8 116.0 0.4 0.0 24 9.0 17.5 0.0 0.0
SWCT* 147 5.2 90.7 0.4 0.0 22 0.0 17.5 0.0 0.0
ME 8 27.5 0.0 1.0 76.0 0 0.0 0.0 0.0 0.0
NEMA 114 39.0 3.0 1.5 1.4 1 0.0 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 11 2.8 0.0 0.0 0.0 0 0.0 0.0 0.0 0.0
SEMA 82 8.4 0.5 0.0 0.0 0 0.0 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 94 17.9 0.1 9.0 0.0 0 0.0 0.0 0.0 0.0
Total 534 152.9 120.2 12.0 83.2 25.0 9.0 41.5 0.0 0.0
Ready To Respond: Approved:
27
New Generation
28
New Generation Update
• No new resources were added in December.
• No additional capacity expected on line by the end of the year.
• Status of Generation Projects as of January 3, 2005:
No. MWIn Construction 1 8.4with 18.4 approval
Not in Construction 5 1,271with 18.4 Approval
Nuclear Uprates 4 265with 18.4 approval
29
RTEP
30
RTEP Update
• RTEP05 – Draft load forecast under review– Scope of work under development– RTO and related transitional issues to
the Regional System Expansion Plan (RSEP) have been identified
– Working towards better coordination of TEAC/Planning Advisory Committee (PAC) meetings with the RC
31
Inter-ISO Update
• Northeastern ISO/RTO Planning Coordination Protocol – Signed by PJM, NYISO, and ISO-NE– Initial joint Northeast Consolidated Plan (NCP)
under review by Joint Inter-ISO/RTO Planning Committee (JIPC)
– Developed project plan– Next Steps
• Issue NCP for management review• Develop joint website• Update timelines of planning activities
• NERC Blackout issues being addressed through NPCC
32
RTEP Project Stage Descriptions
Stage Description
1Planning and Preparation of Project Configuration
2Pre-construction (e.g., material ordering, project scheduling)
3 Construction in Progress4 Completed
33
NSTAR 345 kV Transmission Reliability ProjectStatus as of 1/4/05Project 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-07
Notes:- Siting review completed. EFSB/DTE approval on 12/23/04.
- Detailed engineering in progress.
Phase 2
Phase 1
- Received RC recommendation for 18.4 (conditional) and 12C approval 7-29-04.
2
- Conditions removed at 12/13/04 RC.
34
North Shore UpgradesStatus as of 1/4/05
Project Benefit: Maintains system reliability for the North Shore area independent of Salem Harbor generation.
UpgradeExpectedIn-service
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 1
Notes:- MA DTE review in progress; ruling due early 2005
Wakefield Junction
Ward Hill Upgrades
- 18.4 application for Ward Hill upgrades expected early 2005
Jun-08
35
SWCT 345 kV Transmission Reliability ProjectStatus as of 1/4/05Project Benefit: Improves New England reliability by
addressing SWCT concerns. Increases SWCT Import Limit from 2,000 MW to approximately 3,400 MW.
UpgradeExpectedIn-service
OriginalIn-service
Present Stage
Norwalk 345 kV Substation Nov-05 Dec-04 2
Plumtree 345 kV Substation Nov-05 Dec-04 2
Norwalk - 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 1
East Devon 345 kV Substation Dec-07 Jan-06 1
Singer 345 kV Substation Dec-07 Jan-06 1
Beseck - East Devon 345 kV Dec-07 Jan-06 1
East Devon - Singer 345 kV Dec-07 Jan-06 1
Singer - 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.
Notes Phase 2:
- Siting review in progress, ruling due April 2005.- Final ROC report complete; recommended proceeding with 24 miles of UG XLPE cable.
Phase 2
Phase 1
Note:- “Expected In-service” dates differ from those listed on the NU website (Phase I is listed as May-06 and Phase II is listed as May-09); however, no official notice has been given to ISO-NE as to the slip in timing. NU’s pre-filed testimony of 12/28/04 speaks to the Phase II 2009 date.
36
Northeast Reliability Interconnect ProjectStatus as of 1/4/05
Project Benefit: Improves New England reliability by improving inter-area transfer capability and eliminating various protection/stability concerns.
UpgradeExpectedIn-service
OriginalIn-service
Present Stage
Orrington, ME - Pt. Lepreau, NB 345 kV Dec-07 Dec-08 1
Notes:- Siting approved for Canadian section of line.
- DOE & Maine DEP review processes (approx. 1 year) have started.
37
NWVT 345 kV Transmission Reliability ProjectStatus as of 1/4/05
Project Benefit: Improves New England reliability by addressing NWVT concerns, bringing another source into the Burlington area.
UpgradeExpectedIn-service
OriginalIn-service
Present Stage
New Haven 345 kV Substation May-06 Oct-05 1West Rutland - New Haven 345 kV May-06 Nov-05 1New Haven - Queen City 115 kV Mar-07 Oct-06 1Granite STATCOM/Upgrades Oct-07 Oct-07 1
Notes:- Siting review in progress, ruling due January 2005.
- Sandbar Phase Angle Regulator in service.
38
Southern New England Reliability ProjectStatus as of 1/4/05
Project Benefit: Improves New England reliability by increasing transfer limits of three critical interfaces, including Connecticut Import Limit
UpgradeExpectedIn-service
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
Notes:- Planning studies in progress; estimated completion summer 2005.- Project specifics may change; alternatives still under review.
39
Transmission Siting Update• SWCT
– Phase I• Received conditional approval from Connecticut Siting Council 2/11/04.• ISO in receipt of “preliminary” schedule 12C application.
– Phase II• ISO, NU and UI submitted the third and final Reliability and Operating
Committee (ROC) harmonics/overvoltage report on December 20. Recommendation was for 24 miles of UG XLPE cable.
• Next hearing dates are scheduled for 1/11 and 1/13. Main topic is the ROC Report; HVdc will also be discussed.
• BOSTON– New Boston 1 needed until NSTAR completes 345 kV Reliability Project from
Stoughton to Hyde Park and K Street (2006 earliest)• Received RC recommendation for 18.4 (conditional) and 12C approval on
7/29/04.• Additional analysis of harmonics/transient overvoltage completed.• Conditions removed at 12/13/04 RC Meeting.• EFSB/DTE approval on 12/23/04.
– 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 hearings held late September• Decision expected by January 24