TEAC14

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Title: TEAC14

1
TEAC14
Thursday, January 23, 2003 Radisson Hotel
Marlborough Marlborough, Massachusetts Version
for posting on the ISO-NE website. Certain
information as been redacted for security
reasons. Other corrections/changes made are
noted.

2
SWCT Reports Available

To obtain paper or electronic version of the
following reports contact ISO-NE Customer Service
at 413 540 4220
Southwestern Connecticut Electric Reliability
Study - Volume 1 - Final Power - Flow, Voltage
and Short circuit
Southwestern Connecticut Electric Reliability
Study - A Comparative Analysis of 345 kV
Plumtree-Norwalk Overhead versus 2 -115 kV Cables
from Plumtree - Norwalk.

3
TEAC14 Agenda

Welcoming Remarks
RTEP03 Scope Overview
Planning Assumptions
Update on Transmission Studies
SEMA/RI Export
Boston /NEMA -
Downtown
North Shore
RTEP Projects

4
RTEP03 Scope

Reliability and Economic Assessments
Updated planning assumptions
MARS analysis by RTEP sub-area
SCED bus by bus analysis at selected load levels
Expanded IREMM analysis to reflect SMD
Historical Losses
Unit Commitment
Uplift
Several Cases to be studied
Incremental MARS IREMM Analysis -2004

5
RTEP03 Cases

6
Case ID Case Description IREMM MARS SCED
1 Base, Sub-Area Transfer limits with RTEP02 Appendix 13.5.C Interface Transmission Elements (updated to include Upgrades anticipated by 04.01.03 )and RTEP03 load, generation, fuel cost, and other Control Area assumptions Fuel Based Bids Y 50,60, 70,80, 90 100 Percent Load Levels 2004
1A Case 1 Higher Bids NA TBD
1B Case 1 Fuel Oil Cost 25 NA TBD
1C Case 1 Gas Costs 25 NA TBD
1D Generator Attrition Case Y Y Y
1E HQ Ph II at 2000 MW Y Y TBD
7

Case ID Case Description IREMM MARS SCED
2 Glenbrook Statcom Y Y TBD
3 SWCT 345 kV Ph I Y Y TBD
4 SWCT 345 kV Ph II Y Y TBD
5 SEMA/RI Export Improvement Y Y TBD
6 ME Export Improvement Y Y TBD
7 NEMA/Boston Import Improvement Y Y TBD
8 NW VT Improvement Y Y TBD
9 Improvements Cases 2-8 Y Y TBD
9A Case 9 w/ higher bidding Y N TBD
8
RTEP03 Scope

Transmission Planning Studies
SEMA/RI Export Improvement
ME Export Improvement
NEMA/Boston Improvement
Support Approved RTEP02 Projects
SWCT 345 kV
NW Vermont

9
RTEP03 Scope

Fuel Diversity Study
Analysis of Air Emission Impacts
Distributed Resources
LRP
Interregional Coordination

10
RTEP 03 Congestion Cost Methodology
Presentation to the Transmission Expansion
Advisory Committee January 23, 2003 Wayne
Coste Principal, IREMM, Inc.
11
Where We Have Been - RTEP 01

RTEP01 identified key transmission constraints
Economic congestion was estimated
Economic congestion created higher prices for
some sub-areas
Interface ratings were significant (static)
Focus was on LMP effect of price volatility
during high loads
ISO-NE Congestion Management System
Assumed SMD in place at the start of 2002
- ARR / FTR revenue reallocation same as
RTEP01/02
Various assumptions tested using sensitivity
cases
Tested the impact on several alternative bidding
strategies
Did not include transmission uplift (generally
off-peak),losses,load forecast uncertainty or
sub-area internal limits
Tested relaxation of transmission constraints

12
Where We Have Been - RTEP 02

Used basic RTEP01 economic framework
Modeling refinements
Assumption updates for
fuel
new units
transmission upgrades
interchange assumptions
Interchange combination of fixed import and CC
based value
Effect of full unit outages on congestion
Limited representation of operating reserve
Monthly hydro profile developed
RTEP02 quantified impact of relaxation of
transmission constraints

13
RTEP03 Goals

Forecast on-peak congestion (same as RTEP02)
Quantify off-peak uplift
Renamed in SMD Operating Reserve Charges and
Credits
Will remain due to need to securely dispatch the
system
Market screens approved by FERC on Dec 20th
Develop a more secure unit commitment
Include N-2 considerations
Loss of largest unit
Loss of second transmission element
Incorporate Transmission Losses
Transmission losses under SMD may be relatively
high
Roll up results to SMD Reliability Zones

14
Improve Secure Dispatch Representation

ISO-NE has always operated under a secure
dispatch
SMD will continue this operating practice
RTEP03 should reflect this practice
RTEP02 respected N-1 transmission limits
Operations also considers N-2 transmission
limits
Typically transmission outages are the most
constraining
For second contingency transmission outages
Interface ratings are lower
Count a portion of quick-start resources
Include ramp-rate from on-line units
Include OP-4 actions
Include allowable amounts of load shedding

15
Unit Commitment Process

Three (or more) passes for unit commitment
First pass - all units can operate at any level
when needed
Interfaces at N-2 limits.
Identify units that could be flagged ON for
economics
Remaining uneconomic units flagged OFF
Second pass with flagged OFF units, price
spikes occur
Interfaces at N-2 limits.
Identify units that are needed to avoid price
spikes
Remaining uneconomic units flagged OFF
Third pass with units flagged ON typically at
LOL
Interfaces at N-1 limits.
Committed min block bids in at zero

16
Unit Commitment Data

Relatively few units can be added in unit
commitment process
We will examine the following for impacts
Start-up cost
Minimum run hours
Low operating limit
Incremental heat rates
Use physical limits for LOL (typically 25)

17
LMP

LMPs have three components
Energy Clearing Price
Congestion
- in areas of bottled generation
in load pockets
Losses
close to load center
- in remote exporting areas

18
Proxy CT Bid Screens in Constrained in Areas

Allowable safe harbor bids into import
constrained areas
Addressed in FERC Dec 20th order
FERC desires to allow limited scarcity pricing
Based on cost of hypothetical new Proxy CT
Reduction due to prevailing ICAP revenue offset
Net difference in fixed cost is allocated over
500 or 2000 hr
At 500 hours - adder can be in the range of 300
At 2000 hours - adder can be in the 50 - 80
range

19
Indicative LMPs by Load Zone - Energy Component

Energy component is
uniform in all zones
(HISTORICAL
DATA)

20
Indicative LMPs by Load Zone - Congestion
Component

Congestion
component can be
significant when
transmission
contingency is
binding
(HISTORICAL DATA)

21
Indicative LMPs by Load Zone - Loss Component

Loss component is
very non-linear and
affect importing and
exporting regions
Differently
(HISTORICAL DATA)

22
Indicative LMPs by Load Zone - Loss Component

Maine has lowest loss
component while Vermont
has the highest.
(Sept 2002)

23
Including Losses in RTEP03

We will use historic loss data by unit
Implications of loss component
Need to develop loss changes due to transmission
upgrades
Distant generation may be penalized
Prevailing prices may rise if marginal units are
Electrically distant and
High losses

24
SCED Analysis

SCED - Security Constrained Economic Dispatch
program developed by PTI
GOAL To identify the specific transmission
facilities that may constrain and cause
congestion on the New England system

25
SCED Basics

Analysis focuses on optimal operation of the
system (generator dispatch phase shifters)
Transfers and dispatches are calculated as part
of an optimization process
Uses network load flow model employing a dc
linearized powerflow calculation
Provides estimates of costs incurred to securely
operate around transmission constraints
Identifies reliability problems when secure
system operation is infeasible
Identify HUB price divergence

26
SCED Analysis Assumptions

Similar Analysis performed as part of RTEP01
2004 Summer Peak to be analyzed at a number of
varying load levels (50, 60, 70, 80, 90 and 100)
Sensitivities will be studied with larger units
out of service

27
InterregionalSystem Planning ProcessImplementat
ion Plan
28
Goals

Reduce Both Physical and Process System Planning
Seams
Issue Draft Coordinated NY/NE System Plan by 1st
Qtr. 2004
Expand upon NPCC planning process
Include MAAC/PJM
Increase coordination under NY and NE agreements
with IMO and New Brunswick

29
Existing Physical and Process System Planning
Seams

Tie Line Capabilities
Phase II HVdc vs. Central East and PJM Interfaces
Interconnection and Tariff Studies
Queues
Interconnection Standards
Cost Allocation
Single Coordinated Plan

30
Process Issues

Timing of FERC Decisions
SMD Rule
Planning
Pricing
Interconnection Rule
Queuing
Cost Sharing across ISO Borders
TO/ITC Issues
Differences in NY License Plate vs. NE Network
Tariffs
Obligation to Build
Accommodation of Potential ITC(-s)
Formalization of Planning Process
State Issues

31
Opportunities to Address Physical Issues

Identify and Address Physical Seams
Form Initial Plan based upon Existing Procedures
RTEP02 and RTEP03
NY Power Alert
Existing NY and NE Interconnection Procedures
NPCC Annual Reviews
NPCC CP-10 Studies
Initiate Joint Studies
NY-NE Transfer Analysis
Loss of HQ Phase II Project
UPNY-SENY Impact on NE
Identify Small Ticket Improvements
Develop Preliminary Designs for Further Analysis

32
Process to Address Physical Seams

Establish NY-NE Liaison Committee
Define Plan
Transmission Plan
Initially utilize existing planning procedures as
approved by FERC
Coordinate with Regulatory Agencies
NYS DPS
NECPUC
FERC
Engage MP Committees
NEPOOL Participants Committee
NY Operating Committee
TEAC
Utilize agreements with IMO and NB to increase
regional planning scope
Coordinate with NPCC and MAAC/PJM

33
Scope of Work

Assessment
Study Assumptions
Load Forecast
Generation I/S and Availability
Transportation Limits
Transmission Projects
Load Response/Distributed Resources
Establish Common Databases
MARS
IREMM/MAPS Congestion Projections
Transmission Analysis
NPCC Studies
Annual Reviews
CP-10
CP-8
Other TFSS Activities
Transmission Plan
Summary of Transmission Planning Studies
Include Project Status

34
RTEP03 Assessments Overview Assumptions Peter
K. Wong
35
RTEP03

Reliability Analysis 2003 - 2012
Economic Impact Assessment 2003 - 2012

36
Reliability Analysis

Reliability analysis (Resource Adequacy
Assessment) to identify NEPOOL system reliability
based on meeting the 1 Day in 10 Years Loss of
Load Expectation criterion (disconnection of firm
customers).
GE Multi-Area Reliability Simulation (MARS)
program will be used for this analysis.

37
Economic Impact Assessment

Congestion cost assessment to identify possible
congestion trend is based on meeting NEPOOL
energy requirements.
Congestion cost assessment will be conducted
using a market based energy production simulator
(IREMM).

38
Economic Impact Assessment

Estimate congestion cost as result of
transmission constraints identified in
transmission studies.
Estimate congestion cost as result of different
bidding strategies.
Congestion based on price differences between
sub-areas (market areas)
Estimate LMP losses component
Estimate Uplift impacts

39
Load and Existing Resources

Load and existing generating resource capability
assumptions will be based on the 2003 CELT Report
forecast.
Interruptible/dispatchable load and demand
response assumptions will be based on the latest
ISO-NE Settlement data.

40
Unit Addition Assumptions

Generating unit additions are based on approved
18.4 Applications and reflect those that have
started construction as of January 2003.

41
Unit Addition Assumptions

Summer Rating (MW)
AES Granite Ridge (NH) 678
Milford Units 1 2 (SWCT) 490
Mystic Units 8 9 (BOSTON) 1,414
Fore River (SEMA) 700
English Station 7 8 (CT) 70
Great Northern Hydro (BHE) 126
Total 3,478
All assumed in service by June 1, 2003
18.4 Application submittal expected in Feb/Mar
2003

42
Generation Out of Service

Devon 7 and 8 are assumed deactivated when
Milford units are in service.
New Boston 1 is assumed retired when Sithe Mystic
9 is in service. (corrections in red)
No other generation deactivations or retirements
are assumed in the base case.

43
Generating Unit Energy

Generation from fossil fueled units will be
calculated as a function of their short run
marginal costs.
Generation from hydro units are modeled using a
historical monthly generation profile.
Generation from pumped-storage units will reflect
an assumed 10 capacity factor and 75
efficiency.

44
RTEP AssumptionsGeneration Other Adjustments

CELT Capacity Changes
Change in effective MW due to different forced
outage rates

45
Generating Unit Availability

Generator unit availabilities are based on 5-year
average of historical data (1998 - 2002).
Data Sources are as follows
NABS for 1998 thru April 1999.
ISO Short Term Generator Outage Data Base for May
1999 thru April 2000.
ISO Unit Availability Database for May 2000 thru
December 2002.

46
Generating Unit Availability

For new units, unit immaturity is assumed for
first 3 years of operation. After this period,
unit historical data and TUA is used to develop
the 5 year average.
Forced outage assumptions for nuclear units with
extended outage are based on NEPOOL Target Unit
Availabilities except for the first year of the
long outage.

47
Generating Unit Availability

For the first year of the long nuclear outage,
any outage longer than 6 months would be
represented by 6 months of forced outage averaged
with either historical data or TUA (TUA is used
if the unit is on outage the remainder of the
year).

48
Existing Generating Unit Availability(Perce
nt) (edited to indicate gas turbine and jet
statistics separately)
49
Interchange Assumptions for Base Economic
Impact Analysis

Updated RTEP02 methodology with base plus price
sensitive transactions
LI sound cables (Scenario Based)

50
Fuel Price Assumptions

Fuel Price Forecast Based on Energy Information
Administrations
Annual Energy Outlook (Dec 2002 AEO) for 2004
Short term outlook for 2003, 2004
Reference Case forecast was used

51
RTEP Assumptions - Fuel Costs
52
RTEP Assumptions - Fuel Costs
53
RTEP Assumptions - Fuel Costs
54
RTEP Assumptions - Fuel Costs
55
RTEP Assumptions - Fuel Costs
56
Interface Limits

Update for
Impacts of Upgrade Timing
Results of Planning Studies

57
Draft 4/03 Forecast ofNet Energy for Load and
Seasonal Peaks

David Ehrlich
ISO New England
Principal Analyst, Load Forecasting,System
Planning

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Summer Peaks for States Selected Operating
Companies

2003
2008
CAGR
CONNECTICUT
6900
7253
1.0
ISO State peaks Operating Company 2002 Weather
Normal
CMEEC
328
343
0.9
UI
1367
1460
1.3
CLP
4682
4880
0.8
MAINE
1970
2114
1.4
BHE
316
308
-0.5
CMP
1833
1804
-0.3
MASSACHUSETTS
11510
12468
1.6
BECO
3233
3563
2.0
EED
691
729
1.1
FERC715 Operating Company 2003 2008 Forecasts
MECO
3980
4277
1.4
WMECOHWP
773
803
0.7
NEW HAMPSHIRE
2110
2326
2.0
UNITIL
260
306
3.3
GSE
182
202
2.1
PSNH
1472
1508
0.5
RHODE ISLAND
1730
1851
1.4
BVE
343
354
0.7
NEC
125
137
1.9
NECO
1334
1418
1.2
VERMONT
975
1020
1.9
VELCO
975
1102
2.5
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STATUS OF RTEP STUDIES

80
FOCUS

NEMA / Boston
North Shore
Downtown
SEMA / RI Export
Update on remaining RTEP studies

81
NEMA/Boston Planning Study

TEAC Update
January 23, 2003

82
Study Objectives

Assess local reliability and dependence on local
generation
Identify short term projects that could be
completed by 2006 or earlier
Identify long term projects as required

83
Areas of Concern map redacted
84
Generation

North Shore
1150 MW of load
Salem Harbor 1-4 743MW
Downtown Boston
1000 MW of load
Mystic4-6 379MW
Mystic7 565MW
Mystic Block8 800MW
Mystic Block9 800MW
New Boston 380MW

85
Analyses Performed

Thermal Voltage Load Flow Analysis
Short Circuit

86
Initial Conditions Studied

25800 Load Level
Reduced Generation at Salem for North Shore Cases
Cases with and without 115kV Generation in
Downtown Boston
Various system stresses and dispatches

87
Problems Found

Reliability
North Shore Transmission Overloads
Downtown Boston Transmission Overloads

88
North Shore Current Conditions

Overloads occur for load levels experienced today
North Shore Import limit determined to be
approximately 500 MW
All North Shore generation needed to assure
transmission adequacy

89
Transmission Facility Overloads

North Shore (low generation cases)
REDACTED

90
Two Alternatives Investigated for the North Shore

Package 1 Straightforward Replacement of
Overloaded Facilities
Package 2 Addition of 345kV Ring Bus at Ward
Hill, second Ward Hill 345/115kV Transformer, and
replacement of the remaining overloaded facilities

91
Package Comparison

Package 1
Allows for 1100MW of imports
Eliminates the dependency on North Shore
generation
Uses Non-Standard sized transformers which would
have no system spare
More expensive

92
Package Comparison

Package 2
Allows for 1000MW of imports
Would require 112 MW of generation at North Shore
Uses Standard Size Equipment
Better Voltage and Thermal Performance
Better platform for implementing long term
solutions

93
Ward Hill One Line Diagram for Package 2
redacted
94
Downtown Boston Conditions

Overloads occur for load levels experienced today
1000 MW of load in downtown Boston

95
Transmission Facility Overloads

All 115kV generation off
Numerous overloads in Downtown Area
115kV generation on
redacted
Loading on several other 115kV facilities
slightly over LTE

96
Recommended Solutions (Downtown Boston)

Upgrade of circulation equipment of two Downtown
Boston cables
redacted
Still requires generation on Downtown Boston
115kV system

97
SEMA / RIEXPORT CAPABILITYENHANCEMENT
98
Objective

Assess the existing stability and thermal export
limits, determine major (long term) and minor
(short term) upgrades to enhance the export
capability.

Address congestion and reliability issues
associated with locked-in and locked-out
generation
Address locked-in generation in SEMA/RI Eastern
New England
Address line loading, voltage, stability and
torsional reclosing issues
Increase CT and NEMA/Boston import capabilities
Increase East to West transfer capability

99
Current Status - Stability

Report complete on existing stability limits
(2002/03 Southeast Massachusetts / Rhode Island
Export and Short Term Upgrade Analysis)
Report is available from ISO-NE Customer Service

100
Current Status - Thermal

Preliminary analysis to assess the thermal export
capability for the system as planned is ongoing.
Ongoing analysis to assess the benefit of various
345kV projects.

101
Results Stability Performance Analysis

Stability limits were based on the result of
three-phase fault with delayed clearing extreme
contingency which resulted in a transiently
unstable response
All applicable contingencies were evaluated

102
Results Stability Performance Analysis

The existing simultaneous stability transfer
limits were found to be
E/W 850
SEMA/RI 2400
SEMA 400

103
Recommendation Stability Performance Analysis

Modify the following breakers for Independent
Pole Tripping operation
West Medway 111, 112 (completed)
Millbury 314 (Completed)
West Walpole 104, 105, 108, 109 (2003)
Sherman Road 142 (Complete)
IPT Modification results in improved stability
limits
E/W 2400
SEMA/RI 3000
SEMA 2300

104
redacted
105
redacted
106
redacted
107
redacted
108
Follow-Up Stability Analysis

Upgrades to the Canal breakers or reducing the
backup breaker clearing time would eliminate the
possibility of an extreme contingency involving
those breakers causing a total source loss over
2200 MW.
Upgrading Brayton Point circuit breaker 15-300T
and 03-300T to IPT would eliminate the
possibility of an extreme contingency involving
those breakers causing a total source loss over
2200 MW.

109
Results Thermal Performance Analysis

The existing thermal transfer limits for the 2006
As Planned system were found to be 2200 - 3000
MW.
Range limit determined by varying (1) sources in
SEMARI and sinks in NEPOOL and (2) levels of E/W
transfer in the base case.
SEMA/RI Exports limit is highly dependent on
East/West Transfers
CT Import
NEMA Import

110
Results - Thermal

These projects studied to date can improve
SEMA/RI East West and CT Import Capabilities
Project Thermal Export Range
Option 1
Card-West Farnum-Sherman-Millbury 345kV 2700
4200
Option 2
Mntvlle-Kent-W Farnm-Shrmn-Milbry 345kV 2700
4200
Existing 2200 - 3000

111
SEMARI (CT Import) Option 1
redacted
112
SEMARI (CT Import) Option 2
redacted
113
Follow-Up Thermal

Currently evaluating the benefit of two separate
options which improve SEMA/RI to NEMA Boston area
Transfer Capabilities
Option 1
Tapping the 316 Line between Holbrook and West
Walpole at Canton, adding a 345kV line from
Canton to Hyde Park, 115kV from Hyde Park to
Dewar St with a 345/115kV transformer at Hyde
Park.
Option 2
Adding 345kV line from Holbrook-Edgar-K St-Mystic
with 345/115kv transformers at Edgar, K St, and
Mystic.