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									Alternatives to Full Nodal
    Pricing for Load


          May 18, 2004
Alternatives to Full Nodal Pricing of Load                         Compliance Filing for the Federal Energy Regulatory Commission




                                        TABLE OF CONTENTS


1      Executive Summary ................................................................. 1
2      Background .............................................................................. 3
3      Study Overview ........................................................................ 5
4      Analysis of Alternative LMP Load Zone Configurations ... 7
    4.1       Introduction ......................................................................................................... 7
    4.2       Distribution of LMPs in Alternative RTEP-Based Load Zones ......................... 8
    4.3       Statistical Analysis ............................................................................................ 11
    4.4       Statistical Results and Observations ................................................................. 12
    4.5       Impact of Reliability Resources ........................................................................ 15
    4.6       Load Zones for Markets Other than Energy ..................................................... 16
    4.7       Findings............................................................................................................. 17
5      Special Case Nodal Pricing ................................................... 19
    5.1       Introduction ....................................................................................................... 19
    5.2       Special Case Nodal Pricing: General Program Requirements ......................... 19
    5.3       SCNP Non-Dispatchable Option ...................................................................... 21
    5.4       SCNP Dispatchable Option............................................................................... 21
    5.5       Metering and Settlement ................................................................................... 22
    5.6       SCNP Implementation ...................................................................................... 25
    5.7       Timeframe for Implementing SCNP ................................................................. 26
6      Recommendations .................................................................. 27

Appendix A: RTEP Sub-areas, the New England States, and
SMD Load Zones ....................................................................... A-1

Appendix B: Multiple Comparison Tests ............................... B-1

Appendix C: Cluster Analysis .................................................. C-1
Alternatives to Full Nodal Pricing of Load      Compliance Filing for the Federal Energy Regulatory Commission




1          Executive Summary

Locational Marginal Pricing (LMP) is an integral part of the Standard Market Design
(SMD) concept. In NEPOOL, the interaction of supply and demand at the node
determines a generator’s LMP. In contrast, the LMP charged to load is the load-weighted
average of nodal prices in each Load Zone. At the outset of SMD, New England
established eight Load Zones – Maine, New Hampshire, Vermont, Rhode Island,
Connecticut, Western-Central Massachusetts, Northeastern Massachusetts, and
Southeastern Massachusetts.
In September 2002, the Federal Energy Regulatory Commission (Commission) initially
accepted the zonal pricing method for load in its Order Accepting in Part And Modifying
in Part the Standard Market Design Filing, with the understanding that full nodal pricing
for load could be implemented within 18 months. In October 2003, however, NEPOOL,
ISO-NE, and NECPUC jointly petitioned the Commission to remove its requirement for
full nodal pricing for load. In its Order Granting Request for Extension of Time with
Regard to Alternatives to Nodal Pricing dated January 28, 2004, the Commission
indicated that it still considered nodal pricing for load to be a fair and reasonable pricing
method. However, the Commission agreed that consumers would benefit if alternative
pricing methods could more efficiently achieve the Commission’s objectives of increased
price transparency and more accurate price signals for demand response. The
Commission directed ISO-NE and NEPOOL to study alternatives to full nodal pricing of
load and to file the results of that study by July 1, 2004.
In compliance with the Commission’s January 28 Order, this report presents the results of
ISO-NE’s analysis of two alternatives to full nodal pricing for load. The two alternatives
analyzed include:

          The potential reconfiguration of zones, and
          Special case nodal pricing options for some load in limited circumstances.
In the analysis of alternative LMP zone configurations, ISO-NE evaluated whether
differently formulated Load Zones could be expected to produce more accurate price
signals and price transparency than the existing Load Zones. In contrast to the eight Load
Zones implemented at the outset of SMD, over 600 load pricing nodes in the NEPOOL
system were allocated to 13 alternative regions based on known electrical interfaces, as
defined in ISO-NE’s Regional Transmission Expansion Plan (RTEP). Quantitative
analysis was conducted to assess whether the level and pattern of prices were consistent
within each RTEP region, and different between regions.
The results of this analysis indicate that prices are relatively consistent within the existing
SMD Load Zones. The only exceptions are Connecticut and Maine. Within their
respective states, the prices in the Norwalk/Stamford and Southern Maine RTEP regions
stand out. While the prices of Norwalk/Stamford and Southern Maine are statistically
different from the rest of their respective states, annual average differences are quite
small – less than $2.00/MWh. Subdividing Norwalk/Stamford or Southern Maine from
the rest of their respective Load Zones on an energy basis alone is not justified. The


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present eight Load Zones should continue to be used to price energy to load at this time.
However, to the extent additional zones are created for other purposes – e.g., for
locational installed capacity or reserve markets – zonal energy prices should be
recomputed consistently with the new zonal configuration.
This study also addresses Special Case Nodal Pricing (SCNP), which would permit
specific loads to settle at nodal prices. Under SCNP, load-serving entities (LSEs) would
be allowed to enroll specific loads that are at least 5 MW in size and capable of being
mapped to a specific SCADA point and node for nodal settlement. A participating load,
as a beneficiary of SCNP, would pay the costs of complying with applicable metering,
telecommunications, administrative, and technical requirements. Additionally,
participating loads could opt for a non-dispatchable or a dispatchable option. Loads
opting for dispatchable status would be considered ICAP Resources and eligible to
receive ICAP credit.
In order to achieve the Commission’s objectives for the New England SMD, ISO-NE
recommends implementing SCNP as described in this report. Full nodal pricing would
impose transaction costs (e.g., administrative, metering, and other infrastructure costs) on
all loads, regardless of whether they stand to lose or gain from the changes. In contrast,
SCNP requires participating loads benefiting from nodal-based settlement to pay these
transaction costs. This alternative produces a more economical, financially viable, and
equitable solution than full nodal pricing. Special Case Nodal Pricing is an economical
and financially viable solution because only those loads for which the benefits of nodal
settlement outweigh the transaction costs would elect nodal settlement. It is an equitable
solution because SCNP does not require non-participants to subsidize the transaction
costs of those who stand to benefit from nodal settlement.
Over the long run, SCNP would result in a gradual transition of loads to nodal pricing, to
the extent that it is cost-effective. As customers at lower cost nodes migrate to nodal
settlement, those loads would be excluded from the calculation of the zonal LMP, and the
weighted average zonal price would go up to some extent. Such marginal increases in
zonal prices may lead to additional loads finding nodal settlement beneficial. This
process would continue until the transaction costs of nodal settlement exceed the benefits.
Non-participating customers would continue to be settled on a zonal price basis.
SCNP would increase Demand Resources in the market, and would better integrate
demand response directly into the market design without requiring non-participants to
subsidize program participants. Because loads participating in SCNP are likely to
dispatch off at high prices, participating loads could potentially dampen price volatility.
Additionally, participants in the dispatchable load option under SCNP would enhance
system reliability.
Because SCNP better meets the Commission’s objectives of promoting price
transparency and demand response where efficient and equitable, ISO-NE urges the
Commission to waive the full nodal pricing requirement and adopt the proposed SCNP
program as an effective alternative.




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2          Background
Locational Marginal Pricing (LMP) is an integral part of the Standard Market
Design (SMD) concept. In NEPOOL, the interaction of supply and demand at the
node determines a generator’s LMP. In contrast, load’s locational price is the load-
weighted average of nodal prices in each Load Zone. At the outset of SMD, New
England established eight pricing zones for load – Maine, New Hampshire,
Vermont, Rhode Island, Connecticut, Western-Central Massachusetts, Northeastern
Massachusetts, and Southeastern Massachusetts.
In their joint SMD filing on July 15 2002, NEPOOL and ISO-NE requested Federal
Energy Regulatory Commission (Commission) approval of zonal pricing for load,
indicating that nodal pricing for load would not be feasible in New England without
improved metering and reporting capabilities. Currently, customer loads in each
pricing zone are allocated to Load Assets.1 Nodal pricing of load would require the
meter readers to re-map customer loads to specific nodes, rather than to such Load
Assets. ISO-NE and NEPOOL expected this process to take approximately 18
months to implement, and the Commission initially accepted the zonal pricing
method for load in its Order Accepting in Part And Modifying in Part the Standard
Market Design Filing issued on September 20 2002, with the understanding that full
nodal pricing for load could be implemented within 18 months.
In October 2003, NEPOOL, ISO-NE, and the New England Coalition of Public
Utility Commissioners (NECPUC) jointly asked the Commission to remove the full
nodal pricing for load stipulation from the SMD order. The joint filing argued that
implementation would be costly (estimated to be at least $30 million), and that it
would increase price volatility and reduce market liquidity. NECPUC also raised
concerns about the impact that full nodal pricing for load could have on retail rates.
Ninety-six percent of the members of the NEPOOL Participants Committee
approved a resolution to request the Commission to eliminate its full nodal pricing
requirement.
In its Order Granting Request for Extension of Time with Regard to Alternatives to
Nodal Pricing dated January 28, 2004, the Commission indicated that it still
considers nodal pricing for load to be a fair and reasonable pricing method, because
it may provide greater price transparency, and may send more accurate price signals
for demand response. However, the Commission agreed that consumers would
benefit if alternative pricing methods could achieve the same objectives more
efficiently. Thus, the Commission suspended its requirement for ISO-NE to
implement full nodal pricing for load, allowing New England time to study
alternatives. The Commission directed the ISO-NE and NEPOOL to study two
alternatives to full nodal pricing of load:


1
  A load asset is a physical load that has been registered with ISO-NE by the load servers within the
zone, in accordance with the Asset Registration Process. Each Load Asset and Generator Asset is
identified with a Location at which it will settle in the Real-Time Energy Market. For Load Assets,
the settlement Location can either be a Node or Load Zone, depending on the type of Load Asset.


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          The potential reconfiguration of zones, and
          Special case nodal pricing options for some load in limited circumstances.
The Commission expressed willingness to reconsider its position on full nodal
pricing for load if analysis were to show that other pricing methods could achieve
equivalent price transparency, while resolving such issues as costs, liquidity, or
conflicts with state pricing policies. The Commission ordered ISO-NE and
NEPOOL to file the results of the study by July 1, 2004, including
recommendations for changes arising from the analysis, or a justification for
retaining the status quo, together with a time frame for implementing any new
proposed pricing method.
This report presents the results of the analysis. Section 3 provides an overview of
the analysis conducted by ISO-NE in compliance with the Commission’s January
28, 2004 Order. This discussion is followed by Section 4, which presents the
analysis of alternative pricing zones for load. Section 5 outlines a method by which
Special Case Nodal Pricing (SCNP) for load could be implemented in limited
circumstances. Finally, Section 6 makes recommendations for changes.




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3          Study Overview

This section briefly summarizes the alternatives studied to comply with the
Commission’s January 28, 2004 Order – i.e., Alternative LMP Load Zone Configurations
and Special Case Nodal Pricing. The study also considered the impact of out-of-merit
unit commitment and Load Zones for other non-energy markets, such as capacity and
reserve markets, on zonal energy pricing for load.
    Alternative LMP Load Zone Configurations – Over 600 load pricing locations2 in
     the NEPOOL system were individually allocated to 13 regions, as defined in ISO-
     NE’s Regional Transmission Expansion Plan (RTEP)3. The purpose of this step was
     to evaluate whether differently formulated Load Zones could be expected to produce
     more accurate price signals and price transparency than the existing Load Zones,
     which were configured at the outset of SMD. In contrast to these eight Load Zones,
     RTEP regions are based on known electrical interfaces, and offer a natural basis for
     comparison. This step was followed by quantitative analysis of the LMPs for the 13
     RTEP regions to determine whether the level and pattern of prices were consistent
     within each RTEP region, and different between RTEP regions.
          Certain generating units may need to be committed out-of-merit to meet
           operational standards, such as second contingency criteria, in order to maintain
           system reliability. The operation of such generating units may tend to depress
           LMPs in specific zones. The costs of committing these resources can vary greatly
           across Load Zones. To gauge the differential impact of commitment costs, the
           historical operating reserve costs associated with Reliability Must Run (RMR)
           and Special Constraint Resource (SCR) units were compiled for each affected
           RTEP region.
          Zones for energy, capacity, and reserves should coincide to the greatest extent
           possible. While this study focused on LMPs for energy, the study anticipates that
           potential future changes in locational capacity and reserve markets may require
           changes in Load Zone configurations for energy pricing purposes.
    Special Case Nodal Pricing – ISO-NE is studying a solution called Special Case
     Nodal Pricing (SCNP) that would enable specific loads to be priced on a nodal basis
     if they satisfy certain criteria. Qualifying loads could choose between an option for
     nodal settlement only (i.e., a non-dispatchable option), and a dispatchable option.

2
  There are approximately 1800 buses in New England. Of these buses, approximately 1300 represent
distinct injection and withdrawal points for load and generation. The ISO’s systems calculate prices for
each of these 1300 buses. It is these 1300 buses that the Joint Movants referred to as Network Nodes in
their October 30, 2003 filing. Locational marginal prices are calculated for certain individual Network
Nodes and for aggregations of small groups of Network Nodes. The 900 pricing locations referred to in the
October 30, 2003 filing are the total of individual and aggregate Network Nodes for which prices are
published. Of these 900 pricing locations, approximately 300 do not have associated load, so are not used
to derive the load-weighted average zonal price. This study is based on the remaining 600 + pricing
locations that are used to derive zonal prices.
3
  The Executive Summary of the latest RTEP report and additional information are available at
http://www.iso-ne.com/smd/transmission_planning/Regional_Transmission_Expansion_Plan


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     Those electing the dispatchable option would receive Locational Installed Capacity
     (Locational ICAP) credit. The program would leverage existing Dispatchable Load
     logic in the SMD platform – available only to pumped storage hydro units at this
     time. As part of this analysis, ISO-NE reviewed a proposal prepared by the NEPOOL
     Industrial Customer Coalition (NICC).




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4   Analysis of Alternative LMP Load Zone
Configurations
4.1        Introduction
Purpose of the Analysis: To determine if alternative Load Zones based on electrical
interfaces/boundaries have statistically different price levels and patterns from other
zones. If the level and pattern (mean and standard deviation) of prices between regions
are similar, there is no need to create additional zones. Significant differences suggest
exploring other issues, such as the absolute difference in mean zonal prices, cost, timing
issues, and potential changes to electrical interfaces that may mitigate price differentials.
Data Used to Define Alternative Load Zone Prices: To ensure consistency in prices
within each of the alternative Load Pricing Zones, these alternative zones were based on
known electrical interfaces – i.e., RTEP regions. LMPs for these regions were estimated
as follows:
     1.         Historical observations on nodal prices for 604 load nodes were gathered for
                the period March 2003 – February 2004 (the first year of SMD).
     2.         For the purposes of this analysis, the average of each nodal LMP was
                calculated for each of three periods: Annual (March 2003 – February 2004),
                summer (May-September 2003), and winter (October 2003-February 2004).
     3.         The average hourly nodal prices were then grouped by RTEP region. Because
                the objective was to compare the spread of average LMPs within RTEP
                regions as well as across RTEP regions, the simple averages were used.4 This
                calculation is different from the way LMPs for the RTEP regions are derived
                for the RTEP report, in which hourly load-weighted prices are calculated
                using load distributions created by ISO-NE’s State Estimator.
     4.         The standard deviations of the values in step 2 were calculated for each RTEP
                region.
     5.         The reference Hub price is the un-weighted average LMP of its 32 constituent
                nodes, taken across all hours for the three periods listed in step 3.
Process: ISO-NE constructed LMPs by RTEP region to assess whether prices between
zones within a state – such as Maine and Connecticut – are different enough to warrant
the creation of additional zones in such states.
Because RTEP regions are based on electrical, rather than geopolitical, utility service
territories, or other types of boundaries, the RTEP regions are somewhat different from
the existing SMD Load Zones, as indicated in the map in Figure 1. The map’s legend


4
  It is important to emphasize that the purpose of this analysis is to examine whether a node or group of
nodes have a level and pattern of prices similar to those of other nodes or groups of nodes. When
comparing levels and patterns of prices among nodes, the volume of sales at each node is not a relevant
factor. On the other hand, zonal LMPs are computed as the weighted average of nodal prices where the
weights are based on the volume of sales at each node – in this instance, the computation of weighted
averages is necessary to ensure that revenues collected for energy consumed equals the cost of energy.


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briefly describes the RTEP regions.5 The appendix contains a table from the RTEP03
report that more precisely maps RTEP regions to SMD Load Zones.


Figure 1: RTEP Zones6




                                                              BHE
                                             ME



          VT           NH            SME

                                                  BHE - Northeast Maine
                                                  ME - Western & Central Maine/Saco Valley, New Hampshire
                                                  SME - Southeast Maine
                                                  NH - North, East, & Central New Hampshire/Eastern Vermont & Maine
                                                  VT - Vermont/Southwest New Hampshire
                         CMA/NEMA
                                                  BOST - Greater Boston, including the North Shore
                              BOST                CMA/NEMA - Central Massachusetts/Northeast Massachusetts
           WMA
                                                  WMA - Western Massachusetts
                                                  SEMA - Southeast Massachusetts/Newport, Rhode Island
                              SEMA
                                                  RI - Rhode Island/bordering MA
               CT        RI                       CT - North and East Connecticut
                                                  SWCT – Southwest and Central Connecticut
      SWCT                                        NOR - Norwalk/Stamford, Connecticut

    NOR




4.2 Distribution of LMPs in Alternative RTEP-Based Load
Zones
Table 1 shows the means of the nodal prices by RTEP region for the entire post-SMD
period, as well as for the summer and winter periods. Annual average nodal prices in the
RTEP zones tend to fall within $1.25 of the Hub price, except in Connecticut and Maine.
Prices follow a similar pattern when the data are broken out by season, though price
differences between regions were much more pronounced in the summer than in the
winter. Note that price levels in the winter period – i.e., October 2003 through February
2004 – are much higher than during the summer period – May through September 2003 –
because of unprecedented high natural gas prices.



5
 Greater detail is found in the RTEP documentation on the ISO-NE website.
6
 The map drawn here is for illustrative purposes only. The boundaries of the RTEP zones are not precisely
drawn. Most of the RTEP regions cross state boundaries, while the regions in Figure 1are depicted as
wholly contained within state boundaries. Importantly, however, the RTEP regions of CT, SWCT, and
NOR lie almost entirely within the state of Connecticut; and the State of Maine contains within its
boundaries almost all of the RTEP regions of BHE, ME, and SME.


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Table 1: Mean Nodal Prices by RTEP Region, Post-SMD
                                                Annual               Summer                      Winter
               RTEP ZONE                     March 2003 –        May – September             October 2003 –
                                             February 2004            2003                   February 2004
NEPOOL Hub                                       49.86                   45.69                     52.76
Norwalk/Stamford                                 52.54                   50.53                     54.03
Southwestern Connecticut                         51.95                   49.62                     53.67
Connecticut                                      51.07                   48.12                     53.25
Central Massachusetts                            49.41                   45.94                     52.00
Vermont                                          48.88                   45.58                     51.33
Western Massachusetts                            50.05                   46.71                     52.54
Boston                                           50.48                   46.85                     53.17
Rhode Island                                     49.61                   45.90                     52.22
New Hampshire                                    50.30                   46.94                     52.80
Southeastern Massachusetts                       49.06                   45.67                     51.56
Southern Maine                                   46.56                   43.17                     49.07
West-Central Maine                               45.05                   41.69                     47.54
Northeastern Maine                               45.25                   40.72                     47.89


Figures 2 through 4 compare the distributions of average non-weighted nodal prices in
each of the RTEP regions. The average of these hourly averages was calculated for each
RTEP region for: (1) the entire year (figure 2); (2) the summer period (figure 3), May
through September 2003; and (3) the winter period (figure 4), October 2003 through
February 2004. The standard deviation of these period averages also was derived for
each RTEP region. Figures 2 through 4 show the average Hub LMP to provide a
reference point. In these figures, the width of the bars represents plus and minus one
standard deviation from the RTEP region’s average. Thus, each individual bar shows the
dispersion of average nodal LMPs within an RTEP region. The location of the bars on
the graph shows the differences in price levels across RTEP regions. What is important
to observe in these graphs is the relative pattern of prices across the regions.
The prices were then studied in more detail with statistical techniques, described later in
this report. The statistical analysis confirms the patterns seen in Figures 2 through 4.




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Figure 2: Distribution of Average LMPs by RTEP Zone – March 2003 – February 2004



            Norwalk/Stamford                      Average Hub LMP

    Southwestern Connecticut

                 Connecticut

       Central Massachusetts

                    Vermont

       Western Massachusetts

                     Boston

                Rhode Island

              New Hampshire

  Southeastern Massachusetts

              Southern Maine

          West-Central Maine

          Northeastern Maine

                               40        42       44      46        48      50       52   54     56     58      60
                                                                    Average LMP ($/MWh)




Figure 3: Distribution of LMPs by RTEP Region, May – September 2003



            Norwalk/Stamford
                                     Average Hub LMP
    Southwestern Connecticut

                  Connecticut

        Central Massachusetts

                     Vermont

       Western Massachusetts

                      Boston

                 Rhode Island

              New Hampshire

  Southeastern Massachusetts

              Southern Maine

           West-Central Maine

           Northeastern Maine

                                40        42       44      46       48      50       52   54     56     58     60
                                                                    Average LMP ($/MWh)




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Figure 4: Distribution of LMPs by RTEP Zone, October 2003 – February 2004



             Norwalk/Stamford
                                                       Average Hub LMP
      Southwestern Connecticut

                   Connecticut

         Central Massachusetts

                      Vermont

        Western Massachusetts

                       Boston

                  Rhode Island

               New Hampshire

  Southeastern Massachusetts

               Southern Maine

            West-Central Maine

            Northeastern Maine

                                 40   42     44   46      48       50      52    54     56     58     60
                                                           Average LMP ($/MWh)




4.3         Statistical Analysis
In addition to the previous section’s tabular and graphical representations of alternative
zonal LMPs based on the RTEP regions, rigorous quantitative analysis also was
conducted. The purpose of this analysis was to determine if price levels and patterns
between alternative zones are significantly different, as well as to evaluate whether nodal
prices within each zone are consistent. This analysis employed two statistical algorithms:
        Multiple Comparison Tests. These tests use either the averages or the standard
         deviations of nodal prices within a specific RTEP region to ascertain whether the
         nodal prices of one RTEP region are statistically different from those of the other
         regions. Two sets of evaluations were made – one comparing averages and the
         other comparing standard deviations of nodal prices between RTEP regions. To
         conduct this analysis, nodal prices were first grouped into specific RTEP regions.
         The mean (or standard deviation) of nodal prices for each RTEP region was
         computed based upon the average of the nodal prices assigned to each RTEP zone.
         The resulting means (or standard deviations) of the nodal prices for each RTEP
         zone were then compared to those of the other RTEP zones.
        Cluster Analysis. The means and standard deviations of the nodal LMPs were
         simultaneously subjected to a statistical clustering algorithm. This technique
         groups nodal prices together according to the similarity of their distributions, as
         described by the means and standard deviations. The objective of this technique is
         to minimize the differences within groups, while maximizing the differences
         between groups. This analysis computes the mean and standard deviation of prices
         for each node, and then groups nodes with statistically similar means and standard
         deviations into the same cluster.


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As described above, these analyses used nodal price observations for 604 load nodes in
New England for the first full year of SMD. In addition to conducting the analysis on the
full year’s worth of data, seasonally differentiated data were analyzed in order to see if
price levels and patterns between RTEP regions vary by season. The means and standard
deviations of the nodal prices for each RTEP region were derived for the following
periods:
     a.         March 2003 through February 2004.
     b.         May 2003 through September 2003.
     c.         October 2003 through February 2004.

4.4        Statistical Results and Observations
Multiple Comparison Tests. The results of the Multiple Comparison Tests are illustrated
in Figures 5 through 7. Multiple Comparison Tests examine the difference between the
LMP means of all of the RTEP regions on a pair-wise basis, and groups together those
found not to be significantly different. Accordingly, the means that group zones together
are considered not significantly different from one another. Figures 5 through 7 show the
groups in descending order of the size of their mean LMPs. Notice that the groups in the
middle of the diagrams overlap; that is, the mean LMPs for a given RTEP region could
be close to those of two or more other RTEP regions. While the results differ markedly
between the summer and winter periods, they tend to show that nodal prices in the states
of Connecticut and Maine clearly differ from those of the other zones, and consistently
stand out at the high (Connecticut) and low (Maine) ends of the price spectrum,
confirming the patterns pictured in Figures 2 through 4. Connecticut average nodal price
levels are consistently above the central tendency of New England nodal LMPs. Within
Connecticut, nodal prices in the Norwalk/Stamford and Southwestern Connecticut RTEP
regions are higher than those in the rest of Connecticut, but on average by less than $2.00
per MWh on an annual basis.
Maine has a significant amount of “locked-in” generation, and often experiences negative
congestion costs and losses. However, as in Connecticut, the overall difference in annual
average prices among the three RTEP regions in Maine is less than $2.00 per MWh.
The prices in the other zones do not appreciably diverge from each other, and tend to
center around the hub price. These patterns are more pronounced during the summer
months, but are similar in the winter period.
More details of the Multiple Comparison Test are in the appendix.




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Figure 2: Multiple Comparison Tests of Mean LMPs – March 2003 – February 2004




Figure 6: Multiple Comparison Test of Mean LMPs – May 2003 – September 2003




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Figure 7: Multiple Comparison Tests – October 2003 – February 2004




Cluster Analysis. Figure 8 shows the results of the cluster analysis, described above, for
clusters containing at least 18 nodes (representing over 91 percent of New England’s load
nodes), for the post-SMD period March 2003 – February 2004. Statistical similarities in
the distributions of average nodal prices determine the assignment of nodes to clusters,
without regard to electrical or physical proximity.
Within each cluster, the first line in Figure 8 shows the number of nodes from each RTEP
region that fall within the cluster, and the second line shows the percentage of nodes in
the RTEP region assigned to that cluster. The last column gives the total number of
nodes in the cluster. For example, cluster 7 is the largest, containing 90 nodes. The
RTEP region VT contributes 21 nodes to cluster 7, representing 63.6 percent of the total
nodes in the VT region. The WMA region contributes 35 nodes to cluster 7, which is
close to half of the nodes in WMA. Eleven nodes from the CT region and 17 from
SWCT also comprise cluster 7. Nodes from the BOST, CMA/NEMA, and RI regions
make up an insignificant part of this cluster.
The point of this analysis is not to define which nodes should comprise pricing zones, but
to discern similarities in prices across existing RTEP regions. The average nodal prices
do tend to cluster into expected regional groupings, with few exceptions. Average nodal
prices are generally consistent within each RTEP region, and groups with similar nodal
prices are mainly comprised of nodes in the same RTEP region or in contiguous RTEP
regions. The RTEP regions CT and SWCT tend to group together, and NOR does not
cluster with any other regions. The RTEP regions in Maine tend to cluster together, and
not with other clusters.
More results of the cluster analysis are contained in the appendix.


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    Figure 8: Cluster Analysis of RTEP Regions – March 2003 – February 2004
Cluster                                                                                  CMA/
Number                           BHE       ME       SME       NH       VT       BOST     NEMA       WMA       SEMA     RI       CT       SWCT     NOR Total
         7 Number of Nodes            0        0        0         0       21         1        3         35         0       2       11        17       0   90
           % of Region's Nodes     0.00     0.00     0.00      0.00    63.64      1.20     8.33      49.30      0.00    3.57    16.18     34.00    0.00
        22 Number of Nodes            0        0        0         2        2        19       20         18         2      25        0         0       0   88
           % of Region's Nodes     0.00     0.00     0.00      4.26     6.06     22.89    55.56      25.35      3.03   44.64     0.00      0.00    0.00
        27 Number of Nodes            0        0        0         2        2         5        9          2        40      13        0         0       0   73
           % of Region's Nodes     0.00     0.00     0.00      4.26     6.06      6.02    25.00       2.82     60.61   23.21     0.00      0.00    0.00
        18 Number of Nodes            0        0        0         0        0         0        0          3         0       0       44        22       1   70
           % of Region's Nodes     0.00     0.00     0.00      0.00     0.00      0.00     0.00       4.23      0.00    0.00    64.71     44.00    4.76
         8 Number of Nodes            2       35       15         0        0         0        0          0         0       0        0         0       0   52
           % of Region's Nodes    18.18    72.92    83.33      0.00     0.00      0.00     0.00       0.00      0.00    0.00     0.00      0.00    0.00
        26 Number of Nodes            0        2        0        39        4         0        0          0         3       0        0         0       0   48
           % of Region's Nodes     0.00     4.17     0.00     82.98    12.12      0.00     0.00       0.00      4.55    0.00     0.00      0.00    0.00
        23 Number of Nodes            0        0        0         0        0        13        2          4         3       8        7         0       2   39
           % of Region's Nodes     0.00     0.00     0.00      0.00     0.00     15.66     5.56       5.63      4.55   14.29    10.29      0.00    9.52
         9 Number of Nodes            0        0        0         0        0        13        1          1         1       6        4         4       2   32
           % of Region's Nodes     0.00     0.00     0.00      0.00     0.00     15.66     2.78       1.41      1.52   10.71     5.88      8.00    9.52
        16 Number of Nodes             0        0         0        0        0      26           0         0       5         1        0       0       0    32
           % of Region's Nodes     0.00     0.00     0.00      0.00     0.00     31.33     0.00       0.00      7.58    1.79     0.00      0.00    0.00
        15 Number of Nodes            0        0        0         0        0         0        0          0         0       0        0         0      13   13
           % of Region's Nodes     0.00     0.00     0.00      0.00     0.00      0.00     0.00       0.00      0.00    0.00     0.00      0.00   61.90
         5 Number of Nodes            5       10        3         1        0         0        0          0         0       0        0         0       0   19
           % of Region's Nodes    45.45    20.83    16.67      2.13     0.00      0.00     0.00       0.00      0.00    0.00     0.00      0.00    0.00




    4.5            Impact of Reliability Resources
    Locational Marginal Prices may not fully capture the differences in the costs of providing
    energy within an SMD Load Zone. Occasionally, generating units must be dispatched in
    out-of-merit order to meet local reliability needs.
    Reliability Resources consist of two types of generators: Reliability Must Run (RMR)
    units and Special Constraint Resources (SCR). The ISO identifies RMR Resources on a
    daily basis as necessary for providing Operating Reserve requirements and adhering to
    NERC, NPCC and NEPOOL reliability criteria for a Reliability Region. At the request
    of a Transmission Owner or distribution company, the ISO commits and dispatches SCR
    units in order to maintain area reliability, providing relief for constraints not reflected in
    the ISO’s systems for operating the NEPOOL Transmission System.
    To be eligible to set LMPs, generating units must be operating above their Economic
    Minimum level of output. When RMR and SCR are dispatched to address a local
    reliability situation, they rarely become eligible to set LMP. To compensate the RMR
    and SCR units when called to operate below their Economic Minimum, they are entitled
    to receive Operating Reserve Credits (ORC) equal to the difference between their bid
    price and the LMP, in addition to the LMP for the energy they produce while operating at
    or above their Economic Minimum level.7 Thus, operating an out-of-merit-order
    generator may reduce the LMP in the zone it serves, which could depress the difference
    in LMP across regions.


    7
     When receiving ORC, the bid price for RMR and SCR units exceeds the LMP. For those hours in which
    LMPs rise to the level in which RMR and SCR units are in-merit-order, ORC goes to zero.


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Alternatives to Full Nodal Pricing of Load                    Compliance Filing for the Federal Energy Regulatory Commission



During the first year of SMD, ORC amounted to $54 million; of which $53 million went
to units serving Boston and Connecticut. Most of the Connecticut charges were incurred
in Norwalk/Stamford, and in Northern and Eastern Connecticut (i.e., the non-Southwest
portion of Connecticut). This revenue is charged to load in the SMD Load Zone, raising
the costs of unit commitment. These data suggest that the impact of RMR and SCR
resources brings real-time LMPs in Southwest Connecticut and the rest of Connecticut
closer together, but separates Norwalk/Stamford prices from the rest of the state.
Figure 9 shows the per-MWh distribution of Operating Reserve Credits for RMR and
SCR units, by RTEP region. To derive the per-MWh ORC values, the total ORC dollars
in an RTEP region were divided by the total output from RMR and SCR units in the
region.


Figure 3: Average Operating Reserve Credit – March 1 2003 – February 29 2004


                Norwalk/Stamford




                 S.W. Connecticut




                      Connecticut
   RTEP Zone




                          Boston




               S.E. Massachusetts




                         Vermont



                                0.00   0.25   0.50   0.75     1.00     1.25     1.50      1.75     2.00      2.25     2.50
                                                     Average Operating Reserve Credit ($/MWh)




4.6               Load Zones for Markets Other than Energy
The nodal pricing compliance order of January 28, 2004, directed ISO-NE and NEPOOL
to assess the appropriateness of the current configuration of energy market zones, and
evaluate whether zonal energy pricing is an adequate substitute for full nodal pricing.
This analysis and the resulting recommendations have therefore been based only on
conditions in the energy market.
However, the energy zones are used for other markets, specifically locational capacity.
The planned locational operating reserve market may also use energy market zones.


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Alternatives to Full Nodal Pricing of Load        Compliance Filing for the Federal Energy Regulatory Commission



While the existing zones may be adequate for the energy market based on this analysis,
no assessment has yet been made as to whether these zones are appropriate for other
markets. Such an analysis could potentially create a need for an optimal configuration of
zones for the energy, locational reserves, and capacity markets. This issue, and the
timing, will be addressed through the stakeholder process and the regional resource
adequacy dialog.

4.7        Findings
As a result of the analyses described in the previous sections, we find that the present
eight Load Zones are adequate for pricing energy for load. This finding is based on the
following points:


           1. Prices are relatively consistent within the existing SMD Load Zones. The
              only exceptions are Connecticut and Maine. Within these particular states, the
              Norwalk/Stamford and the Southern Maine RTEP zones stand out the most
              from the rest of their respective states.
           2. While the prices in Norwalk/Stamford and Southern Maine are statistically
              different from the rest of their respective states, annual average differences are
              quite small – less than $2.00/MWh.
           3. At $2.00/MWh price differential, it is unlikely that the additional price
              transparency created by splitting off Norwalk/Stamford and Southern Maine
              from the rest of their respective states would produce any noticeable increase
              in demand response. Our experience with Real-time Demand and Price
              Response programs show that typical program participants require a price of
              $100/MWh or more in order to produce a discernable amount of demand
              response.
           4. Reconfiguring pricing zones would require installing new meters, mapping
              meters to zones, creating new load assets, and related software changes.
              These changes would impose additional costs on the system and would take
              nine months to one year to implement.
           5. Changing zonal configurations could conflict with state pricing policies. The
              existing bilateral arrangements made to supply Provider of Last Resort
              (POLR) service would be disrupted, particularly in Connecticut, where
              Transitional Standard Offer service is available at capped rates to all
              customers through December 31, 2006. In Maine, Standard Offer service is
              available until March 2005 for all customers not served by a competitive
              supplier.
           6. Changing the definition of Load Zones would have unknown impacts on
              existing bi-lateral supply arrangements.
           7. As electrical interfaces change over time (e.g., as a result of transmission
              upgrades) zonal configurations also change. Planned transmission upgrades in
              Connecticut are expected to alleviate congestion within the state, further



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Alternatives to Full Nodal Pricing of Load       Compliance Filing for the Federal Energy Regulatory Commission



                reducing the differences between LMPs and perhaps reducing local ORC as
                well.
           8. Since it would take nearly a year to implement new zonal configurations, the
              pricing differences from the introduction of new zones would be effective for
              only the next several years, assuming that currently planned transmission
              upgrades go into service as planned.
           9. Given the relatively modest pricing differences indicated by the analysis, the
              resources and time it would take to implement new Load Zones, the impact of
              such changes on state pricing policies, and the potentially short period over
              which these changes would be effective, changing zonal configurations based
              on energy price differentials alone is not justified.
           10. For the locational installed capacity and/or other markets, the creation of new
               zones may be warranted. If new zones are created for the locational installed
               capacity or for other purposes, it would be prudent to re-compute zonal energy
               prices consistently with the new zonal configuration.
           11. We recommend implementing Special Case Nodal Pricing along the lines of
               the program proposed by the NEPOOL Industrial Customers Coalition,
               NECPUC, and other stakeholders, as a better alternative to reconfiguring the
               existing Load Zones for energy pricing purposes. This approach would
               provide pricing transparency, further demand response objectives, and
               provide a mechanism that would result in a gradual transition of loads to nodal
               pricing to the extent cost-effective. The next section outlines the salient
               features of such a program.




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Alternatives to Full Nodal Pricing of Load    Compliance Filing for the Federal Energy Regulatory Commission




5          Special Case Nodal Pricing
5.1        Introduction
Full nodal pricing of load would impose transaction costs (e.g., administrative, metering,
and other infrastructure costs) on all loads, regardless of whether they stand to lose or
gain from the changes. In contrast, SCNP requires participating loads benefiting from
nodal-based settlement to pay these transaction costs. This alternative produces a more
economical, financially viable, and equitable solution than full nodal pricing. Special
Case Nodal Pricing is an economical and financially viable solution because only those
loads for which the benefits of nodal settlement outweigh the transaction costs would
elect nodal settlement. It is an equitable solution because SCNP does not require non-
participants to subsidize the transaction costs of those who stand to benefit from nodal
settlement.
Over the long run, SCNP would result in a gradual transition of loads to nodal pricing to
the extent that it is cost-effective. As customers at lower cost nodes migrate to nodal
settlement, those loads would be excluded from the calculation of zonal LMP, and the
weighted average zonal price would go up to some extent. Such marginal increases in
zonal prices may lead to additional loads finding nodal settlement beneficial. This
process would continue until the transaction costs of nodal settlement exceed the benefits.
Non-participating customers would continue to be settled on a zonal price basis.
Special Case Nodal Pricing would increase Demand Resources in the market, and would
better integrate demand response directly into the market design without requiring non-
participants to subsidize program participants. Because loads participating in SCNP are
likely to dispatch off at high prices, participating loads could potentially dampen price
volatility. Additionally, participants in the dispatchable load option under SCNP would
enhance system reliability.


5.2 Special Case Nodal Pricing: General Program
Requirements
To meet the Commission’s goals, the ISO developed Special Case Nodal Pricing (SCNP),
in cooperation with the NEPOOL Industrial Customers, NECPUC, and other
stakeholders. This program permits specific loads to settle at nodal prices in limited and
defined circumstances. Load Serving Entities (LSEs) are allowed to enroll certain loads
that are capable of being mapped to a specific SCADA point and node, that are in
compliance with certain technical and administrative criteria, and that are of a certain
size. An end-use customer with a qualifying load is allowed to enroll its own load into
SCNP, provided the customer is the LSE of its load and is a NEPOOL Participant with a
settlement account with ISO-NE. Load Serving Entities with the responsibility to serve




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Alternatives to Full Nodal Pricing of Load            Compliance Filing for the Federal Energy Regulatory Commission



the loads enrolled in SCNP are still required to meet all applicable wholesale and retail
requirements related to the enrolled load.8
A participating load that elects SCNP would be responsible for the costs of applicable
metering, telecommunications, administrative, and technical requirements. Additionally,
participating loads could opt for a non-dispatchable9 or a dispatchable option. Those
loads opting for dispatchable status would be considered ICAP Resources10 available for
dispatch by ISO-NE, and eligible to receive ICAP credit. Special Case Nodal Pricing
would be implemented by leveraging the existing Dispatchable Load logic in the SMD
platform, which is only used by pumped storage hydro units at this time.

In order to participate in the SCNP program, all participating loads must comply with the
following general requirements:11

               The non-coincident peak demand of a load participating in the program must
                be at least five MW.
               A participating load, at its own expense, must satisfy all metering and
                telemetering requirements, including those mandated under NEPOOL
                Operating Procedures (OP) 14 and OP 18.
               Participating loads must submit billing quality meter data on a daily basis to
                the ISO and report it to their metering domain, in accordance with Manual M-
                28.
               A participating load must be identifiable as an individual SCADA point
                within a single pricing node on the system – aggregation of loads across
                diverse pricing nodes is not allowed.
               Once in the program, participating loads would not be permitted to switch
                back to zonal pricing for at least 12 months.
               Because participating loads benefit directly from real-time nodal pricing
                settlement and are eligible for ICAP credit under the dispatchable option, such
                loads would not be eligible to participate in other Load Response programs.




8
  In discussions of this proposal during the stakeholder process, some LSEs expressed concern that SCNP
may allow certain customers to by-pass certain wholesale and/or retail market requirements such as
wholesale ICAP requirements and retail transition charges (such as those financing the recovery of stranded
costs). Additionally, some expressed concern that SCNP allows the ISO to become a retail supplier. SCNP
is not designed to allow bypassing of wholesale or retail market requirements, and is certainly not intended
to allow the ISO to become an LSE.
9
  This option was originally labeled “nodal settlement only.” Because the term “settlement only” is used in
other contexts, there was some confusion over the use of this term. Therefore, the term was changed to
avoid any potential confusion.
10
   At the time of this writing, Commission approval of ISO-NE’s proposed Locational Installed Capacity
market is pending.
11
   These requirements are consistent with those proposed by the NEPOOL Industrial Customer Coalition.


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Alternatives to Full Nodal Pricing of Load         Compliance Filing for the Federal Energy Regulatory Commission




5.3         SCNP Non-Dispatchable Option
Loads satisfying the general program requirements listed above, and electing to
participate in the non-dispatchable option, must register with ISO-NE in accordance with
asset registration requirements. Such loads would be settled at the real-time nodal LMP
for real-time metered consumption. Because loads participating in this option are
exposed to real-time nodal LMP, they are expected to become more price sensitive, and
more likely to self-dispatch in response to varying price levels. Therefore, the presence
of such loads should increase the amount of price-sensitive demand in the New England
control area.

5.4         SCNP Dispatchable Option
As mentioned above, a load participating under the dispatchable option would be
considered an ICAP Resource, available for dispatch by ISO-NE and therefore eligible to
receive ICAP credit. As proposed, such Dispatchable Loads would receive ICAP credit
in the same manner as 30-minute Real-Time Demand Response Program assets, as
defined in ISO-NE’s Load Response Program Manual. In addition to increasing the
amount of price-sensitive demand in the New England control area, such resources could
be called upon by the ISO during capacity deficiencies, which would better enable system
operators to maintain system reliability.
For loads choosing the SCNP dispatchable option, the following requirements would
apply:
               A participating load must register with the ISO as a Dispatchable Load and
                designate a “Lead Participant” and a “Designated Entity,” in accordance with
                asset registration requirements.
               Participating loads must register the amount of interruptible load, which
                would receive LICAP credit:
                o This amount must not exceed the participant’s non-coincident peak
                  demand.
                o The registered amount must be at least five MW of interruptible load in
                  full MW amounts.
                o While less than 100 percent of the participant’s load may be registered as
                  interruptible, the entire load is subject to nodal price settlement under this
                  option.
               Loads must be connected to a Remote Intelligence Gateway Unit (RIG), as
                defined by OP 14.
               Within 30 minutes of an ISO request, Load must curtail at Action 9 of OP 4 –
                Actions During a Capacity Deficiency.12


12
  This is consistent with the 30-minute Real-Time Demand Response Program requirements for load
curtailment assets as defined in ISO-NE’s Load Response Program Manual.


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Alternatives to Full Nodal Pricing of Load            Compliance Filing for the Federal Energy Regulatory Commission



               To establish its dispatch rate, the participating load must submit a Day-Ahead
                Demand Bid for its registered load.
                o If its bid price were greater than or equal to the Day-Ahead nodal price,
                  the load would purchase energy in the Day-Ahead market.
                o If its bid price were less than the Day-Ahead nodal price, the load would
                  be scheduled to interrupt.
               Operating Reserve charges would apply to Load failing to follow its
                interruption schedule in Real-Time.
               Because fully integrated Dispatchable Load will not be available for Real-
                Time dispatch until proposed changes to the energy and reserve markets are
                completed, the participating load must monitor its Real-Time LMP and
                request “dispatch off” and “dispatch on” from ISO.
                o If load were dispatched off, any energy purchased Day-Ahead would be
                  credited at the Real-Time LMP.
               These loads may be able to participate in the Forward Reserve Market. The
                rules and procedures must be reviewed, and changes made if necessary to
                accommodate SCNP Dispatchable Loads.

5.5         Metering and Settlement
Special Case Nodal Pricing would not change the manner in which prices at specific
nodes are calculated. The loads of those opting for SCNP would settle at their specific
nodal price. However, to enable a subset of customers to settle on a nodal basis, SCNP
requires a few changes in the reporting of meter data to the ISO, and in the computation
of zonal prices for those customers remaining on zonal settlement.13
Settlement by ISO-NE must ensure revenue neutrality – i.e., the sum of revenues
collected from those opting for nodal settlement and from those remaining on zonal
settlement should equal the revenues collected under the current scheme, in which all
load is priced on a zonal basis. When determining weighted average zonal prices for the
remaining load (i.e., the load of customers remaining on zonal settlement), the loads of
those opting for nodal settlement must be excluded from the computation of load weights,
so that the money collected from load balances with the money owed to supply.
Under current practices, the zonal price for load is the weighted average price among the
nodes within the zone. The weights are based on the amount of load at each node in the
zone as a percentage of total load in the zone. For a specific period of time, the weighted
average zonal price in a zone equals the following:




13
  It is important to note that the issue of who should report such data to ISO-NE, and precise software
changes that need to be made by ISO-NE to implement what is described in this section, have yet to be
determined.


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Alternatives to Full Nodal Pricing of Load                               Compliance Filing for the Federal Energy Regulatory Commission




                             ZPcurrent   Pi       A   i
                                                                                                                                   (1)
                                             i       T

Where:

           ZPcurrent = Weighted Average Zonal Price as currently computed

           Ai            = Load at Node i
                                                                           
           T             = Sum of all loads at the nodes in the zone   Ai 
                                                                      i    
           Pi            = Nodal Price at Node i
At price ZPcurrent, total revenue (price times quantity) for a specific time period equals the
following:


                                                                     
                  Current Total Re venue  ZPcurrent  T   Pi * Ai  T , or
                                                            i     T                                                              (2)
                  Current Total Re venue   Pi Ai
                                                                 i

Under SCNP, a subset of load at specific nodes would settle at nodal prices. In order to
facilitate this settlement, the metered load of customers opting for nodal settlement must
be identifiable as a specific SCADA point. The load at a particular node is the
aggregation of all SCADA points that are directly tied to that node. Assume that the load
at any given Node i in a specific period is defined by equation 3:

                                                 A
                                                 i
                                                                S  j
                                                                            ji
                                                                                                                                   (3)


Where:
           Sji           = Load at SCADA point j at Node i

Assume that specific SCADA point k (where k ≤ j) at a given Node i opts to be settled at
nodal prices. The amount of revenue paid by those opting for nodal settlement is the
LMP at the node multiplied by the load opting for nodal settlement at that location,
summed across all nodes:


       Total Re venue from Loads Settled at Nodal Pr ices                                        P   S 
                                                                                                  i
                                                                                                            i
                                                                                                                 k
                                                                                                                      ki
                                                                                                                                   (4)


Thus, the remaining Nodal load that would settle at zonal prices is defined by:


                                                     A       i
                                                                        Sk
                                                                                 k
                                                                                                                                   (5)




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Alternatives to Full Nodal Pricing of Load                                                                                 Compliance Filing for the Federal Energy Regulatory Commission



Additionally, the total remaining load that would settle at zonal prices across all nodes in
the zone is defined by:

                                                                                    T                    S
                                                                                                          i                k
                                                                                                                                        ki
                                                                                                                                                                                                                        (6)


Given the relationships outlined in (5) and (6), equation (7) below defines the new
weighted average zonal price for the remaining load to be settled at zonal prices:

                                                                                                                                         A S   i                        ki                                            (7)
                                                                                    ZP                      Pi                                         k
                                                                                                new
                                                                                                                       i                T   S                           ki
                                                                                                                                                      i       k


To ensure revenue neutrality, the sum of revenue from all remaining loads to be settled
under new zonal prices, ZPnew, and from those customers opting for nodal settlement must
equal the total revenue under the current system of zonal pricing for all load. To prove
that this is the case, equation (2) must equal the product of (7) and (6), plus (4), or:
                                                                                             
                                ZP                  T  ZPnew* T   S ki    Pi   S ki                                                                                                                          (8)
                                                                                             
                                        current
                                                                    i k       i        k


By substituting terms from equations (2) and (7):

                                              A S
                          P  A    P                                                                                                                                               
                                                                                                                                                                                                P  S
                                                                                    i                         ki

                                                                                               k
                                                                                                                                    T                         S                                                (9)
                        i
                                i       i
                                            T   S 
                                                    i
                                                            i
                                                                                                                   ki                    i                           k
                                                                                                                                                                                    ki
                                                                                                                                                                                          i      i
                                                                                                                                                                                                      k
                                                                                                                                                                                                          ki

                                                                                        i           k



                       
The term  T   S ki  appears in both the numerator and denominator of the middle
              i  k     
term. Canceling this term simplifies the formula:

                                                                                                        
                    P  A    P   A   S
                    i
                            i       i
                                               i
                                                        i               i
                                                                                    k
                                                                                                    ki
                                                                                                            Pi   S ki
                                                                                                            i      k
                                                                                                                                                                                                                    (10)


                                                                                                                      
Expanding the middle term                                P  A   S
                                                        i    
                                                                    i               i
                                                                                                k
                                                                                                                  ki
                                                                                                                        results in the following:
                                                                                                                       

                             P  A    P  A    P   S   P   S
                            i
                                    i       i
                                                            i
                                                                            i               i
                                                                                                              i
                                                                                                                               i
                                                                                                                                    k
                                                                                                                                                 ki
                                                                                                                                                                  i
                                                                                                                                                                                i
                                                                                                                                                                                         k
                                                                                                                                                                                             ki
                                                                                                                                                                                                                    (11)


The last two terms cancel out, which results in the following identity:

                                                             P  A    P  A 
                                                                i
                                                                                i                   i
                                                                                                                               i
                                                                                                                                             i                i
                                                                                                                                                                                                                    (12)

                                                                                                     (Q.E.D.)


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Alternatives to Full Nodal Pricing of Load        Compliance Filing for the Federal Energy Regulatory Commission




Accordingly, SCNP achieves the revenue neutrality requirement. While pricing loads
that opt for nodal settlement at nodal prices, Equation (7) derived above defines the new
weighted average zonal price (ZPnew) to be applied to all remaining load that settles at
zonal prices.


5.6         SCNP Implementation
In order to implement SCNP, several rules need to be more thoroughly reviewed by
subject matter experts at ISO-NE, and changes need to be finalized. The effected rules
are as follows:
               OP 14: Technical Requirements for Generation, Dispatchable, and
                Interruptible Loads.
               OP 18: Metering and Telemetering Criteria.
               Manual M-11: Operational requirements.
               Market Rule 1 and Manual M-28: Settlement needs.
               Manual M-20 – Conditions under which SCNP loads could receive
                LICAP/LUCAP credit.
               Manual M-36: Forward Reserve Market rules and procedures.
               Expand the Asset Registration process to allow SCNP participants to register
                into either the non-dispatchable and dispatchable options as previously
                discussed.
Additionally, changes are needed in the metering and settlement procedures and software
to ensure proper settlement of SCNP loads, and the appropriate recalculation of zonal
prices for the remaining loads.
               Work with the Meter Reader Working group to define settlement needs and to
                modify data reporting procedures to ensure the proper submission of meter
                data to ISO-NE.
               Modify settlement software to appropriately settle SCNP loads and to
                recalculate zonal prices for the remaining loads.
Finally, implementing SCNP requires other enhancements in computer software and
protocols. These include:
               Special computer displays for use by ISO-NE’s Control Room Operators.
               Training sessions for Lead Participants and Designated Entities.
               Verbal communication protocols for economic and emergency dispatch of
                dispatchable Loads.




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Alternatives to Full Nodal Pricing of Load   Compliance Filing for the Federal Energy Regulatory Commission




5.7        Timeframe for Implementing SCNP
The timeframe to develop and implement SCNP is a function of its priority relative to
other planned market enhancements. Considering that ISO-NE’s resources have already
been fully committed to implement other market system projects, and given that SCNP is
not currently a defined project, the priority of SCNP implementation relative to other
important market enhancements has not yet been established. In order to develop a
reasonable timeframe for implementing SCNP, the advice of market participants, subject
matter experts, and the region’s meter readers must be taken into account. ISO-NE plans
to discuss SCNP implementation details with the appropriate parties once NEPOOL
Participants have approved this alternative approach to full nodal pricing for load.




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Alternatives to Full Nodal Pricing of Load         Compliance Filing for the Federal Energy Regulatory Commission




6          Recommendations
In its January 28, 2004, Order, the Commission stated that:
           “… The Commission considers nodal pricing for load to be a just and reasonable
           pricing method, as it provides price transparency and accurate price signals for
           demand response. If, however, the parties can demonstrate that other pricing
           methods (whether designating sub-zones, or other methods) will also achieve
           much or all of the transparency provided by nodal pricing, while providing other
           benefits (for example, lower costs, the elimination of the liquidity problems that
           the Joint Movants discussed, and/or the elimination of the possibility of conflict
           with state pricing policies), the Commission will, at that time, reconsider the
           requirement to implement nodal pricing.”14

In order to achieve the Commission’s objectives for the New England Standard Market
Design, we recommend implementing Special Case Nodal Pricing as described in Section
5 of this report. Implementing full nodal pricing or defining additional sub-zones from
the existing zones imposes transaction costs (e.g., administrative, metering, and other
infrastructure costs) on those who stand to lose from such changes, as well as on those
who stand to win.15 In contrast, SCNP requires participating loads that stand to benefit
from nodal-based settlement to pay these transaction costs. This produces a more
economically correct, financially viable, and equitable solution than full nodal pricing or
defining additional sub-zones. Special Case Nodal Pricing is an economically correct
solution because only those loads that find it cost-effective to be priced on a nodal basis
would elect to pay the transaction costs associated with this option. It is more financially
viable because SCNP beneficiaries are in the best financial position to pay transaction
costs (because the benefits of price reduction outweigh the cost of the transaction).
Special Case Nodal Pricing is an equitable solution because it does not require non-
participants to subsidize the transaction costs of those who stand to win from the switch
to nodal settlement.
Over the long run, SCNP would result in a gradual transition of loads to nodal pricing, to
the extent cost-effective.16 As customers at lower cost nodes migrate to nodal settlement,
the weighted average zonal price would go up to some extent. This marginal increase in
zonal prices may lead to additional loads finding nodal settlement beneficial. This

14
   ORDER GRANTING REQUEST FOR EXTENSION OF TIME WITH REGARD TO
ALTERNATIVES TO NODAL PRICING,” Docket No. ER02-2330-019 (Issued January 28, 2004), P15
15
   Whenever prices are de-averaged, half of the load in the de-averaged zone will experience a price
increase and the other half a price decrease.
16
   Under the SCNP General Program Requirements noted in Section 5.2 above, loads participating in the
program are limited to those 5 MW and larger. Under these requirements, NICC estimated that about 150
MW would elect to participate in the program. Research conducted by the ISO regarding candidate loads
for day-ahead demand response programs indicates that 200 MW would potentially be interested in the
SCNP Dispatchable Option. Finally, among the current participants in the ISO’s load response program,
there are about 600 MW across the NEPOOL system consisting of customers with a non-coincident peak
load equal to or greater than 5 MW; roughly 300 to 400 MW may be located at nodes with below average
zonal prices. These data suggest that a few hundred MW across the NEPOOL system would elect to
participate in SCNP. As more experience is gained with SCNP, the general participation requirements
could be revisited.


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Alternatives to Full Nodal Pricing of Load    Compliance Filing for the Federal Energy Regulatory Commission



process would continue until the transaction costs of nodal settlement exceed the benefits.
Throughout the process, non-participating customers would continue to be settled on a
weighted average zonal price basis.
Additionally, SCNP would increase Demand Resources in the market, and would better
integrate demand response directly into the market design without requiring non-
participants to subsidize program participants. Because loads participating in SCNP are
likely to dispatch off at high prices, participating loads could potentially dampen price
volatility. Additionally, participants in the dispatchable load option under SCNP would
enhance system reliability.
Finally, SCNP would support economic development and retention of large Commercial
and Industrial customers in those areas of the New England system where such customers
are located at relatively inexpensive nodes.
Special Case Nodal Pricing is the most efficient, equitable, and timely way for New
England to meet Commission objectives. Accordingly, ISO-NE urges the Commission to
waive the full nodal pricing requirement and adopt the SCNP program as an effective
alternative.
While the Commission has stated that it supports full nodal pricing for load and continues
to do so now, that support would not preclude the acceptance of other pricing methods
that may also be found to be just and reasonable. Accordingly, ISO-NE conducted this
study to explore ways in which other pricing methods could achieve the price
transparency and accurate price signals for demand response sought by the Commission.
Based on the analytical results summarized in Section 4 of this report, we recommend the
continued use of the present eight Load Zones for pricing zonal load on a weighted
average basis. As indicated above, nodal prices are relatively consistent within the
existing SMD Load Zones. If prices among nodes within a zone are consistent, little is
gained by changing from a system of zonal pricing to nodal pricing, especially
considering the cost of implementing nodal pricing.
The only exceptions to this general observation are Connecticut and Maine. Within these
states, the prices of Norwalk/Stamford and the Southern Maine RTEP regions stand out
from prices in the rest of their respective states. However, the analysis also shows that
annual average price differences of Norwalk/Stamford and the Southern Maine, when
compared to the prices of the other RTEP regions within the same state, are quite small –
less than $2/MWh. At this level of price difference, it is unlikely that the additional price
transparency created by splitting off Norwalk/Stamford and Southern Maine from the rest
of their respective states would produce any noticeable increase in demand response. Our
experience with Real-time Demand and Price Response programs shows that typical
program participants require a price of $100/MWh or more in order to produce a
discernable amount of demand response or other market response.
Considering the time and resources required to define additional zones (such as installing
new meters, mapping meters to zones, creating new load assets, and related software
changes), splitting Norwalk/Stamford and Southern Maine from the rest of their
respective states for energy pricing purposes is ill advised at this time. Additionally,
changing zonal configurations could conflict with state pricing policies for POLR service



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Alternatives to Full Nodal Pricing of Load    Compliance Filing for the Federal Energy Regulatory Commission



and existing bilateral supply arrangements. Finally, as electrical interfaces change over
time (e.g., as a result of transmission upgrades) zonal configurations will change. Since it
would take nearly a year to implement new zonal configurations, the pricing differences
from the introduction of new zones would be effective for only a few years, assuming
that currently planned transmission upgrades go into service within a few years as
planned. Given the relatively modest pricing differences indicated by the analysis, the
resources and time it would take to implement new Load Zones, the impact of such
changes on state pricing policies, and the potentially short period over which these
changes likely would be effective, changing zonal configurations based on energy price
differentials alone is not justified. For the locational installed capacity, reserves, and
other such markets, however, the creation of new zones may be warranted. If new zones
are created for the locational installed capacity, reserves, or for other purposes, it would
be prudent to re-compute zonal energy prices to be consistent with the new zonal
configuration.




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        Alternatives to Full Nodal Pricing of Load        Compliance Filing for the Federal Energy Regulatory Commission




        Appendix A: RTEP Sub-areas, the New England States,
        and SMD Load Zones
                                                                                           2003
                                                                                          Summer Percent Percent of
                                                                                         Peak Load of RTEP State Peak
                    RTEP Sub-area                           SMD Load Zone          State Forecast Sub-area    Load
BHE: Northeast Maine                                                                        312
                                                                   ME               ME      312     100.0     17.2
ME: Western & Central Maine / Saco Valley NH                                                956
                                                                   ME               ME      921      96.4     50.9
                                                                   NH               NH       35       3.6      2.2
SME: Southeast Maine                                                                        533
                                                                   ME               ME      533     100.0     29.4
NH: North, East, &Central New Hampshire/Eastern VT&ME                                      1617
                                                                   ME               ME       45       2.8      2.5
                                                                   NH               NH     1501      92.8     83.9
                                                                   VT               VT       72       4.5      7.2
VT: Vermont and Southwest New Hampshire                                                    1203
                                                                   NH               NH      323      26.9      9.6
                                                                   VT               VT      880      73.1     85.1
BOSTON: Greater Boston Incl. North Shore                                                   5222
                                                              NEMA/Bost             MA     5148      98.6     44.6
                                                                 NH                 NH       74       1.4      3.3
CMA/NEMA:Central and Merrimack Valley Massachusetts                                        1635
                                                             West/Cent MA           MA     1513      92.5     13.1
                                                                  NH                NH      122       7.5      0.9
WMA: Western Massachusetts                                                                 1963
                                                             Connecticut            CT       68       3.5      1.0
                                                             West/Cent MA           MA     1825      93.0     15.8
                                                                  VT                VT       70       3.6      7.6
SEMA:Southeast Massachusetts and Newport RI                                                2550
                                                            South East MA           MA     2405      94.3     20.8
                                                                  RI                RI      145       5.7      8.2
RI: Rhode Island and Bordering Massachusetts                                               2266
                                                            South East MA           MA      644      28.4      5.6
                                                                  RI                RI     1622      71.6     91.8
CT: North and East Connecticut                                                             3350
                                                              Connecticut           CT     3350     100.0     48.3
SWCT: South Central Connecticut                                                            2263
                                                              Connecticut           CT     2263     100.0     32.6
NOR: Norwalk/Stamford Connecticut                                                          1251
                                                              Connecticut           CT     1251     100.0     18.1
        Source: Executive Summary, Regional Transmission Expansion Plan 2003 (RTEP03), p. 21, available on
        the ISO-NE website: http://www.iso-ne.com.




                                                                                                                  A-1
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Appendix B: Multiple Comparison Tests
The multiple comparison tests reported here are based on the "Honestly Significantly
Different" (HSD) test developed by John Tukey. This procedure tests all possible pair-
wise comparisons among means, using a formula that takes into account the number of
means under consideration. For the current analysis, standard deviations were also
tested.
This appendix presents the results of these Multiple Comparison Tests. In this case, (1)
the mean nodal average LMP for each RTEP region is sequentially compared to the mean
nodal average LMP for all of the other RTEP regions. (2) The standard deviation for
each RTEP region is also compared to all of the other RTEP regions’ standard deviations,
one at a time. Six sets of multiple comparison tests were run:
           1.         Mean LMPs for the entire post-SMD period: March 2003 – February
                      2004.
           2.         LMP standard deviations for the entire post-SMD period.
           3.         Mean LMPs for the post-SMD summer period: May 2003 – September
                      2003.
           4.         LMP standard deviations for the post-SMD summer period.
           5.         Mean LMPs for the post-SMD winter period: October 2003 – February
                      2004.
           6.         LMP standard deviations for the post-SMD winter period.
The tables in this appendix show the mean LMPs and standard deviations for each RTEP
Region, and show the RTEP Region’s group assignment. These groupings are based
solely on statistical analysis, and are unrelated to the physical location of the nodes. The
groups are not mutually exclusive. When an RTEP region falls in more than one group,
the values for that region are shown in all of the groups to which it belongs. For
example, Table B-1 shows that the RI region falls into two groups: Group E and Group F.
It should be noted that the standard deviations computed for the multiple comparison
tests are different from those computed in Figures 2-4 of Section 4 of this report. The
standard deviations computed for the multiple comparison tests take into account
variations in prices both between and within nodes. In contrast, the standard deviations
shown in Figures 2-4 are based on variations between nodes only. The standard
deviations computed in the multiple comparison tests are substantially larger than the
standard deviations computed in Figures 2-4. This reveals an interesting observation –
variation in energy prices within any particular node is substantially greater than
variations between nodes.




                                                                                                           B-1
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Table B-1: Mean LMPs by RTEP Region, March 2003 – February 2004
                                                                Group
  RTEP Zone                 A                B    C         D            E            F            G            H
       NOR                52.54
      SWCT                51.95
        CT                              51.07
        RI                                                             49.41        49.41
      SEMA                                                                          48.88
      WMA                                        50.05    50.05
 CMA/NEMA                               50.48    50.48
      BOST                                                49.59        49.59
        VT                                       50.30
        NH                                                             49.06        49.06
       SME                                                                                       46.56
        ME                                                                                                    45.05
       BHE                                                                                                    44.68


Table B-2: LMP Standard Deviations by RTEP Region, March 2003 – February 2004
                                                                Group
  RTEP Zone                 A                B    C         D            E            F            G            H
       NOR                29.13
      SWCT                              28.30
        CT                                       26.41
        RI                                                             24.98        24.98
      SEMA                                                             24.98        24.98
      WMA                                                              24.97        24.97
 CMA/NEMA                                        25.76    25.76
      BOST                                                25.31        25.31
        VT                                                             24.87        24.87
        NH                                                                          24.32
       SME                                                                                       21.76
        ME                                                                                                    20.97
       BHE                                                                                       21.27




                                                                                                                 B-2
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Table B-3: Mean LMPs by RTEP Region, May 2003 – September 2003
                                                                       Group
  RTEP Zone                A            B         C         D            E           F              G           H      I
      NOR               50.53
     SWCT                             49.62
       CT                                        48.16
        RI                                                              45.95       45.95
     SEMA                                                                           45.59
     WMA                                                   46.72        46.72
 CMA/NEMA                                                  46.86
     BOST                                                               45.97       45.97
       VT                                                  46.95
       NH                                                                           45.74
      SME                                                                                        43.18
       ME                                                                                                  41.69
      BHE                                                                                                           40.81


Table B-4: LMP Standard Deviations by RTEP Region, May 2003 – September 2003
                                                                       Group
                RTEP Zone                    A        B            C            D            E            F
                     NOR                23.14
                    SWCT                           21.68
                      CT                                        17.45
                      RI                                                     13.73          13.73
                    SEMA                                                     13.71          13.71
                    WMA                                                      14.21
               CMA/NEMA                                                      13.95          13.95
                    BOST                                                     14.09
                      VT                                                     13.36          13.36
                      NH                                                                    12.71
                     SME                                                                                 10.93
                      ME                                                                                 10.30
                     BHE                                                                                 9.67




                                                                                                                     B-3
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Table B-5: Mean LMPs by RTEP Region, October 2003 – February 2004
                                                                   Group
                                RTEP Zone             A        B           C            D
                                    NOR              53.78
                                   SWCT              53.48
                                     CT              53.06
                                      RI             51.74   51.74
                                   SEMA              50.89   50.89       50.89
                                   WMA               59.20   52.20
                               CMA/NEMA              52.90
                                   BOST              51.89   51.89
                                     VT              52.40   52.40
                                     NH              51.18   51.18       51.18
                                    SME                      48.70       48.70        48.70
                                     ME                                               47.02
                                    BHE                                  47.33        47.33


Table B-6: LMP Standard Deviation by RTEP Region, October 2003 – February 2004
                                                                   Group
                                             RTEP Zone         A             B
                                               NOR           28.41
                                              SWCT           27.98
                                                CT           27.55
                                                RI           25.28        25.28
                                              SEMA           25.11        25.11
                                               WMA           25.18        25.18
                                             CMA/NEMA        26.01        26.01
                                               BOST          25.44        25.44
                                                VT           25.23        25.23
                                                NH           24.34        24.34
                                               SME                        21.53
                                                ME                        20.67
                                               BHE                        20.46




                                                                                                                     B-4
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Appendix C: Cluster Analysis
Cluster analysis is a statistical technique used to solve classification problems. Its objective is to categorize data into groups so that
the degree of association is strong between members of the same cluster and weak between members of different clusters. Cluster
analysis can reveal similarities in data that may have been otherwise overlooked.
This appendix presents tables of results summarizing cluster analysis applied to all of the load nodes in NEPOOL. Cluster analysis is
purely a statistical technique, which in this case groups nodes together according to the similarity of their means and standard
deviations. The cluster number is an index, and has no significance otherwise. The clusters are mutually exclusive; that is, a node can
be a member of one and only one cluster. The tables below show only those clusters with a substantial number of nodes. Several
clusters contain very few nodes, and often only a single node.
The purpose of this analysis is to confirm that the RTEP regions are reasonable pricing zones for energy, based upon similarity of
prices across the nodes that comprise the RTEP regions.


Table C-1: Nodes per Cluster, by RTEP Region – March 2003 – February 2004




                                                                                                                                         C-1
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  Cluster                                                                                                  CMA/
  Number                                     BHE       ME         SME         NH        VT       BOST      NEMA        WMA           SEMA     RI       CT       SWCT     NOR Total
           7 Number of Nodes                      0        0            0         0        21         1           3          35           0       2       11        17       0    90
             % of Region's Nodes               0.00     0.00         0.00      0.00     63.64      1.20        8.33       49.30        0.00    3.57    16.18     34.00    0.00
          22 Number of Nodes                      0        0            0         2         2        19          20          18           2      25        0         0       0    88
             % of Region's Nodes               0.00     0.00         0.00      4.26      6.06     22.89       55.56       25.35        3.03   44.64     0.00      0.00    0.00
          27 Number of Nodes                      0        0            0         2         2         5           9           2          40      13        0         0       0    73
             % of Region's Nodes               0.00     0.00         0.00      4.26      6.06      6.02       25.00        2.82       60.61   23.21     0.00      0.00    0.00
          18 Number of Nodes                      0        0            0         0         0         0           0           3           0       0       44        22       1    70
             % of Region's Nodes               0.00     0.00         0.00      0.00      0.00      0.00        0.00        4.23        0.00    0.00    64.71     44.00    4.76
           8 Number of Nodes                      2       35          15          0         0         0           0           0           0       0        0         0       0    52
             % of Region's Nodes              18.18    72.92       83.33       0.00      0.00      0.00        0.00        0.00        0.00    0.00     0.00      0.00    0.00
          26 Number of Nodes                      0        2            0        39         4         0           0           0           3       0        0         0       0    48
             % of Region's Nodes               0.00     4.17         0.00     82.98     12.12      0.00        0.00        0.00        4.55    0.00     0.00      0.00    0.00
          23 Number of Nodes                      0        0            0         0         0        13           2           4           3       8        7         0       2    39
             % of Region's Nodes               0.00     0.00         0.00      0.00      0.00     15.66        5.56        5.63        4.55   14.29    10.29      0.00    9.52
           9 Number of Nodes                      0        0            0         0         0        13           1           1           1       6        4         4       2    32
             % of Region's Nodes               0.00     0.00         0.00      0.00      0.00     15.66        2.78        1.41        1.52   10.71     5.88      8.00    9.52
          16 Number of Nodes                       0        0           0          0         0       26            0             0       5         1        0       0       0     32
              % of Region's Nodes              0.00     0.00         0.00      0.00      0.00     31.33        0.00        0.00        7.58    1.79     0.00      0.00    0.00
          15 Number of Nodes                      0        0            0         0         0         0           0           0           0       0        0         0      13    13
             % of Region's Nodes               0.00     0.00         0.00      0.00      0.00      0.00        0.00        0.00        0.00    0.00     0.00      0.00   61.90
           5 Number of Nodes                      5       10           3          1         0         0           0           0           0       0        0         0       0    19
             % of Region's Nodes              45.45    20.83       16.67       2.13      0.00      0.00        0.00        0.00        0.00    0.00     0.00      0.00    0.00




                                                                                                                                                                                 C-2
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Table C-2: Nodes per Cluster, by RTEP Region – May 2003 – September 2003
 Cluster                                                                                         CMA/
 Number                               BHE       ME      SME       NH         VT       BOST       NEMA        WMA       SEMA         RI      CT      SWCT     NOR      Total
         2 Number of Nodes                  7      45       18         1          0          0          0          0            0       0       0        0        0            71
           % of Region's Nodes          70.00   93.75   100.00      2.13       0.00       0.00       0.00       0.00         0.00    0.00    0.00     0.00     0.00
       30 Number of Nodes                   0       0        0         0          0          0          0         23            0       0      40        0        0            63
           % of Region's Nodes           0.00    0.00     0.00      0.00       0.00       0.00       0.00      32.39         0.00    0.00   58.82     0.00     0.00
       20 Number of Nodes                   0       0        0         2          2          0          9          1           10      23       0        0        0            47
           % of Region's Nodes           0.00    0.00     0.00      4.26       6.06       0.00      25.00       1.41        15.15   41.07    0.00     0.00     0.00
       32 Number of Nodes                   0       0        0         0          0          0          1          1           35      10       0        0        0            47
           % of Region's Nodes           0.00    0.00     0.00      0.00       0.00       0.00       2.78       1.41        53.03   17.86    0.00     0.00     0.00
       31 Number of Nodes                   0       2        0        37          5          0          0          0            0       0       0        0        0            44
           % of Region's Nodes           0.00    4.17     0.00     78.72      15.15       0.00       0.00       0.00         0.00    0.00    0.00     0.00     0.00
         7 Number of Nodes                  0       0        0         0          1          0         19         15            4       1       0        0        0            40
           % of Region's Nodes           0.00    0.00     0.00      0.00       3.03       0.00      52.78      21.13         6.06    1.79    0.00     0.00     0.00
       24 Number of Nodes                   0       0        0         0          2          2          0          6           10       6       4        1        0            31
           % of Region's Nodes           0.00    0.00     0.00      0.00       6.06       2.47       0.00       8.45        15.15   10.71    5.88     2.00     0.00
       13 Number of Nodes                   0       0        0         1          0         24          0          1            0       2       0        0        0            28
           % of Region's Nodes           0.00    0.00     0.00      2.13       0.00      29.63       0.00       1.41         0.00    3.57    0.00     0.00     0.00
       21 Number of Nodes                   0       0        0         0          0          0          2          4            6       8       7        0        0            27
           % of Region's Nodes           0.00    0.00     0.00      0.00       0.00       0.00       5.56       5.63         9.09   14.29   10.29     0.00     0.00
       14 Number of Nodes                   0       0        0         0          0         26          0          0            0       0       0        0        0            26
           % of Region's Nodes           0.00    0.00     0.00      0.00       0.00      32.10       0.00       0.00         0.00    0.00    0.00     0.00     0.00
         6 Number of Nodes                  0       0        0         0          0          0          0          0            0       0       1       17        3            21
           % of Region's Nodes           0.00    0.00     0.00      0.00       0.00       0.00       0.00       0.00         0.00    0.00    1.47    34.00    14.29
       23 Number of Nodes                   0       0        0         0          0          1          0          2            0       0       1       16        1            21
           % of Region's Nodes           0.00    0.00     0.00      0.00       0.00       1.23       0.00       2.82         0.00    0.00    1.47    32.00     4.76
       12 Number of Nodes                   0       0        0         0          0         17          0          0            0       0       0        1        2            20
           % of Region's Nodes           0.00    0.00     0.00      0.00       0.00      20.99       0.00       0.00         0.00    0.00    0.00     2.00     9.52
       29 Number of Nodes                   0       0        0         0          0          0          0          0            0       0       3        5       11            19
           % of Region's Nodes           0.00    0.00     0.00      0.00       0.00       0.00       0.00       0.00         0.00    0.00    4.41    10.00    52.38




                                                                                                                                                                              C-3
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Table C-3: Nodes per Cluster, by RTEP Region – October 2003 – February 2004
 Cluster                                                                                            CMA/
 Number                               BHE       ME      SME         NH         VT        BOST       NEMA       WMA        SEMA         RI      CT      SWCT     NOR      Total
         2 Number of Nodes                  2      19        1           0          0          0          0          0             0       0       0        0        0            22
           % of Region's Nodes          18.18   39.58     5.56        0.00       0.00       0.00       0.00       0.00          0.00    0.00    0.00     0.00     0.00
       24 Number of Nodes                   0       0        0           0          0          5          2          2            39      11       0        0        0            59
           % of Region's Nodes              0       0        0           0          0       6.02       5.56       2.82         59.09   19.64       0        0        0
       10 Number of Nodes                   0       0        0           0          0          0          0          1             0       0      30       22        1            54
           % of Region's Nodes           0.00    0.00     0.00        0.00       0.00       0.00       0.00       1.41          0.00    0.00   44.12    44.00     4.76
       13 Number of Nodes                   0       0        0           0          0          0          1         29             0       0      21        3        0            54
           % of Region's Nodes              0       0        0           0          0          0       2.78      40.85             0       0   30.88        6        0
       21 Number of Nodes                   0       2        0          36          3          0          0          0             2       0       0        0        0            43
           % of Region's Nodes           0.00    4.17     0.00       76.60       9.09       0.00       0.00       0.00          3.03    0.00    0.00     0.00     0.00
         4 Number of Nodes                  0       0        0           0          2         13          2          4             4       8       7        0        2            42
           % of Region's Nodes              0       0        0           0       6.06      15.66       5.56       5.63          6.06   14.29   10.29        0     9.52
       20 Number of Nodes                   0       0        0           0          0         13          1          5            10       6       4        3        0            42
           % of Region's Nodes           0.00    0.00     0.00        0.00       0.00      15.66       2.78       7.04         15.15   10.71    5.88     6.00     0.00
       18 Number of Nodes                   0       0        0           2          1         19         12          6             1       0       0        0        0            41
           % of Region's Nodes              0       0        0        4.26       3.03      22.89      33.33       8.45          1.52       0       0        0        0
       30 Number of Nodes                   1      23       15           0          0          0          0          0             0       0       0        0        0            39
           % of Region's Nodes           9.09   47.92    83.33        0.00       0.00       0.00       0.00       0.00          0.00    0.00    0.00     0.00     0.00
       17 Number of Nodes                   0       0        0           0          0          0         13          3             0      22       0        0        0            38
           % of Region's Nodes              0       0        0           0          0          0      36.11       4.23             0   39.29       0        0        0
       31 Number of Nodes                   0       0        0           0          0         26          0          0             5       1       0        0        0            32
           % of Region's Nodes           0.00    0.00     0.00        0.00       0.00      31.33       0.00       0.00          7.58    1.79    0.00     0.00     0.00
       32 Number of Nodes                   0       0        0           0          1          1          2          4             1       2       3       16        2            32
           % of Region's Nodes              0       0        0           0       3.03        1.2       5.56       5.63          1.52    3.57    4.41       32     9.52
       15 Number of Nodes                   0       0        0           3         21          0          0          4             0       0       1        0        0            29
           % of Region's Nodes           0.00    0.00     0.00        6.38      63.64       0.00       0.00       5.63          0.00    0.00    1.47     0.00     0.00
       26 Number of Nodes                   0       0        0           2          3          0          2          9             2       5       0        0        0            23
           % of Region's Nodes           0.00    0.00     0.00        4.26       9.09       0.00       5.56      12.68          3.03    8.93    0.00     0.00     0.00
       11 Number of Nodes                   0       0        0           0          0          0          0          0             0       0       0        0       13            13
           % of Region's Nodes           0.00    0.00     0.00        0.00       0.00       0.00       0.00       0.00          0.00    0.00    0.00     0.00    61.90




                                                                                                                                                                                 C-4

								
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