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					Niagara Mohawk Power Corporation
National Grid

ARRA 2009
New York Economic Stimulus Package

Consisting of:
Updated Stimulus Proposal & All Non-
Confidential Exhibits and
New York Smart Program Proposal &
All Non-Confidential Attachments

July 2, 2009

Submitted to:

New York State
Public Service Commission
Case 09-E-0310

Submitted by:
                                                  Niagara Mohawk Power Corporation
                                                                d/b/a National Grid
                                                                   Case 09-E-0310

                           Table of Contents
Stimulus Proposal
Exhibit 1         ARRA 2009 Utility Project List
Exhibit 2         Environmental Assessment Form
Exhibit 3         Information Responses in Case 09-E-0310 REDACTED
Exhibit 4         Summary of Changes:
                  April 17, 2009 Proposal to Updated Stimulus Proposal
Exhibit 5         PMU Program: Preliminary Equipment List
Exhibit 6         PMU Program: Cost Breakout REDACTED
Exhibit 7         Indicative Cost of Service REDACTED

New York Smart Program Proposal REDACTED
Attachment 1      Smart Grid Security Approach
Attachment 2      Program List
Attachment 3      Customer Maps
Attachment 4      Customers by Service Class
Attachment 5      Feeder Equipment Count
Attachment 6      Three Phases of Marketing
Attachment 7      Marketing Plan Tactics
Attachment 8      Smart Meter Marketing Plan Budget REDACTED
Attachment 9      Global Smart Services Development Program
Attachment 10     National Grid Smart Grid Request For Information
Attachment 11     Smart Grid Communications
Attachment 12     Information Systems
Attachment 13     Data Model
Attachment 14     Integration Outline
Attachment 15     Hardware and Software Specification REDACTED
Attachment 16     Smart Grid Information Security REDACTED
Attachment 17     Financial Analysis REDACTED
Attachment 18     Terms and Conditions for Smart Grid Pricing
Attachment 19     2006 – 2008 Load Duration Curves
Attachment 20     Results of Cluster Analysis
Attachment 21     2008 Critical Peak Daily Load Curves
Attachment 22     Illustrative Calculation of Proposed Rule 46.2.2 Critical Peak
                  Capacity Charge
Attachment 23     Illustration of Critical Peak Pricing Program Rule 46
                  Electricity Supply Service Charges by Load Zone
Stimulus Proposal
                                              Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                                   Case 09‐E‐0310 
                                                           Updated Stimulus Proposal – July 2, 2009 
                                                                                      Page 1 of 22 
I.       INTRODUCTION ......................................................................................... 2
II.      NATIONAL GRID ARRA PROJECTS ............................................................. 4
      A.  New York Smart Program – Syracuse and Albany (Capital District) ......... 5
      B.  Phasor Measurement Units Program ....................................................... 8
      C.  Statewide Capacitor Bank Program ........................................................ 12
III. COST RECOVERY ...................................................................................... 13
IV. CONCLUSION............................................................................................ 19
                                  Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                       Case 09‐E‐0310 
                                               Updated Stimulus Proposal – July 2, 2009 
                                                                          Page 2 of 22 
         Niagara Mohawk Power Corporation d/b/a National Grid (National 
Grid or the Company) is pleased to present an Updated Stimulus Proposal 
dated July 2, 2009 (this Filing) outlining its plans to seek funding from the U.S. 
Department of Energy (DOE), under the provisions of the American Recovery 
and Reinvestment Act of 2009 (ARRA), in order to make substantial 
investments that will bring the benefits of recent technology advances – the 
Smart Grid – to its customers.   This Filing reflects National Grid’s vision for 
the energy market of the future, in which advanced technologies allow 
electric utilities to operate their systems more efficiently, and provide 
customers with greater choice and control over their energy use.  This Filing 
also is informed by the Company’s ongoing discussions with the New York 
State Department of Public Service (DPS or Staff), with other transmission 
owners (TOs) and with the New York Independent System Operator (NYISO). 

         National Grid proposes to seek ARRA funding for three discrete 
projects, as follows:  

     •   Investment in a Smart Grid program centered in the Syracuse and 
         Albany (Capital District) areas, with supporting investments on the 
         distribution system, and integrating clean energy technologies (New 
         York Smart Program);  

     •   Investment in Phasor Measurement Units (PMUs) to be installed at 
         selected transmission substations as part of a statewide transmission 
         project potentially coordinated by the NYISO; and 

     •   Potential investment in capacitor bank installation on the Company’s 
         transmission system, as part of a statewide transmission project 
         potentially coordinated by NYISO, pending review of a cost‐benefit 
         study currently in progress. 
                                 Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                      Case 09‐E‐0310 
                                              Updated Stimulus Proposal – July 2, 2009 
                                                                         Page 3 of 22 
A project template incorporating these three projects is provided as Exhibit 1 
attached hereto.  An environmental assessment form (EAF) covering the three 
projects is attached as Exhibit 2. 

        This Filing builds on, and is a self‐contained update to, National Grid’s 
April 17, 2009 Stimulus Proposal (April 17 Proposal).  National Grid filed its 
April 17 Proposal in response to a DPS letter directing electric utilities to file 
their plans to seek ARRA funding with the Secretary to the Commission, to 
allow the Commission to consider issues related to cost recovery for these 
projects.  The April 17 Proposal described nine projects that the Company 
could pursue with ARRA funding.   

        By letter dated May 26, 2009, DPS directed New York utilities to 
update their ARRA Filings as needed to reflect guidance expected to be issued 
by the DOE on June 17, 2009 in the form of Funding Opportunity 
Announcement (FOAs) for the Smart Grid Investment Grant (SGIG) Program 
and the Smart Grid Demonstration (SGD) Program.  On that basis, DPS 
established June 22, 2009 as the deadline for updated ARRA Filings.  The 
issuance by DOE of the two FOAs was delayed until June 25, 2009.  
Consequently, by letter dated June 29, 2009, DPS established a July 2 deadline 
for updated filings.   

        Since filing the April 17 Proposal, National Grid has met or spoken with 
Staff on numerous occasions to discuss these projects, and has responded to 
four formal Information Requests from Staff; these interrogatories are 
provided in Exhibit 3.  National Grid also has participated in working groups 
on communications projects for the transmission and distribution systems, 
rate design, PMUs, and a statewide vision for Smart Grid.  This Filing reflects 
these substantive discussions.  A summary of the major differences between 
the April 17 Proposal and this Filing is provided as Exhibit 4. 
                                Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                     Case 09‐E‐0310 
                                             Updated Stimulus Proposal – July 2, 2009 
                                                                        Page 4 of 22 
       The estimated cost of the projects included in this Filing is 
approximately $273 million, excluding the costs associated with the 
provisional Capacitor Bank Program.  National Grid is proposing an 
investment of this scale and scope in order to bring the benefits of Smart Grid 
and advanced transmission technologies to a large segment of its customers 
using ARRA funding.  National Grid’s willingness to undertake this level of 
ARRA spending in New York is dependent on its ability to recover its costs 
concurrently with their incurrence and to earn a return consistent with 
national industry standards and commensurate with the size and timing of 
spending on ARRA projects.  In Section III of this Filing, National Grid outlines 
a cost recovery mechanism that would permit the Company to make the 
investments that will lay the foundation for a modern, “smart” electric 
transmission and delivery system that will benefit its customers in the years 
to come. 

       National Grid has identified three projects for which it may pursue 
ARRA funding: an integrated “New York Smart Program” serving over 81,000 
customers in the Syracuse and Albany (Capital District) areas; a PMU Program 
to be undertaken as part of a statewide transmission project potentially 
coordinated by the NYISO; and a Capacitor Bank Program, also to be 
undertaken as part of a statewide transmission project potentially 
coordinated by the NYISO.  National Grid will pursue the Capacitor Bank 
Program only if it concludes, upon review of a cost‐benefit study currently in 
progress, that this investment will provide significant benefits to its 
customers.  These three projects are summarized in Table 1, and are 
described in more detail below and in Attachment 1 hereto. 


                                Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                     Case 09‐E‐0310 
                                             Updated Stimulus Proposal – July 2, 2009 
                                                                        Page 5 of 22 
                         Table 1.  PROJECT SUMMARY 
                Project Description                         Jobs        Total Cost 
Smart Grid 
New York Smart Program – Syracuse and Albany             300 ‐500       $271 
(Capital District) areas                                                million 
Transmission‐Related Projects 
Phasor Measurement Units Program                              2         $2 million 
Capacitor Bank Program                                    Not yet       Not yet 
                                                          known         known 

A.  New York Smart Program – Syracuse and Albany Capital District   

Project Description:   National Grid believes that Smart Grid technologies can 
improve our customers' ability to make more informed energy decisions, 
while improving the Company’s ability to optimize system performance, as we 
quickly and safely introduce significant levels of clean distributed energy 
technologies.  To validate this belief through actual experience, National Grid 
proposes to deploy Smart Grid technology at two locations in New York, one 
in the Syracuse area and one in the Capital District area, located north of 
Albany.  The Syracuse Smart Program area will include approximately 40,000 
customers, while the Capital District Smart Program area will include 
approximately 42,000 customers.   These customers and associated meters, 
feeders, and substations represent a cross‐section of the Company’s 
customers and electric grid equipment.  This variety is an essential element 
for any test to be both statistically valuable and procedurally useful in 
informing our broader strategic decision related to smart grid and clean 

        The technology to be deployed in the New York Smart Program is 
described in detail in the “New York Smart Program Proposal” section of this 
Filing and is briefly summarized below: 
                                Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                     Case 09‐E‐0310 
                                             Updated Stimulus Proposal – July 2, 2009 
                                                                        Page 6 of 22 
       Communications Technology: National Grid will rely on a robust, two‐
way communications platform as the backbone of the New York Smart 
Program (the Smart Program).  The objective is to deploy a communications 
backbone capable of moving both data and commands at sufficient 
bandwidth and speed to enable an integrated, interactive approach to smart 
energy technologies in the home, at the meter, along the electric grid, in the 
substation and potentially beyond.  The Company is investigating a variety of 
wireless technologies to support this approach.  The infrastructure will 
leverage existing National Grid assets, new wireless technologies, and public 
       Advanced Metering: National Grid proposes to use advanced digital 
meters that can support interval measurements, remote disconnects and 
remote firmware upgrades, track both voltage and power factors, and serve 
as a gateway for communications into the home.   Smart meters will be a 
critical component of a system that will provide timely data for use by the 
customer, the grid operator, and possibly, third party service providers.     
       In‐Home Energy Management: Three levels of in‐home energy 
management technology will be provided to customers based upon the 
service offerings in which they participate.  At each level of participation, 
customers will be provided with energy consumption and pricing data to 
inform their energy decisions.  As customers become more informed as a 
result of these smart tools and programs, the information and tools available 
to them to actively manage their energy consumption will become 
increasingly interactive, providing more choices and flexibility.  
       Grid Monitoring and Automation Technology: Six categories of 
technology are being deployed in support of the Smart Program:  (1) new 
monitoring devices mounted directly on feeders; (2) retrofit communication 
devices installed on existing electric grid control and switching equipment to 
enable this equipment to be monitored and controlled remotely; (3) new 
                                 Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                      Case 09‐E‐0310 
                                              Updated Stimulus Proposal – July 2, 2009 
                                                                         Page 7 of 22 
electric grid control and switching equipment added to feeders in the 
Program area; (4) software applications that provide distribution grid 
operators with improved visibility and operational flexibility; (5) new 
substation monitoring and control that will provide a broader view of the 
entire operational system; and (6) digitally controlled subtransmission 
breakers to extend the smart system beyond the substation.  

       In addition to deploying the Smart Grid technology “spine” discussed 
above, National Grid proposes to demonstrate the effects of combining Smart 
and Green by integrating a robust set of clean energy modules into its Smart 
Program.  These clean energy technologies will include photovoltaics, plug‐in 
hybrid electric vehicles/electric vehicles (PHEV/EV), energy storage, wind 
power, micro‐CHP, micro‐grids, and holistic homes.  A summary of each 
technology and the logic and rationale for its inclusion is provided in the “New 
York Smart Program Proposal” section of this Filing. 

Project Rationale:  National Grid is proposing this Smart Program because we 
believe that the Smart Grid, integrated with distributed clean energy 
technologies, represents the future of the energy industry.  While we may be 
one of the first utilities to propose this type of robust program, ours is clearly 
a shared vision.  As we demonstrate in this Filing, the Company’s view is 
consistent with the strategic thought leadership of this industry.  Smart Grid 
has become a fundamental part of the national dialogue.  National Grid and 
the state of New York are at the forefront of the dialogue.  Congress has 
passed laws to encourage the adoption of smart energy technologies and they 
have now provided funding to “jump start” the deployment.  This unique 
funding opportunity will be taken up by those who share the vision and have 
the necessary regulatory support to meet the timeline and objectives.  
National Grid believes we are in that position and intend to use the 
opportunity to test our vision of the energy future.   
                               Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                    Case 09‐E‐0310 
                                            Updated Stimulus Proposal – July 2, 2009 
                                                                       Page 8 of 22 
Project Milestones:  The following chart provides an overview of key 
milestones for the proposed Smart Program.  For illustrative purposes, the 
chart below shows Month 0 as the Project start date.  It is assumed that at 
Month 0, National Grid has received all necessary regulatory approvals and 
funding commitments, the vendor equipment has met all Company‐required 
safety and standards testing, and vendor contracts have been signed.  
Additional detail on project milestones can be found in the “New York Smart 
Program Proposal” section of this Filing.


Cost Estimates:  National Grid’s preliminary analysis for the Smart Program 
projects a $271 million operating and capital expenditure requirement.  A 
detailed breakout of these cost projections can be found in the “New York 
Smart Program Proposal” section of this Filing. 

        As discussed below, National Grid believes that the Smart Program 
should be eligible for 50% funding from the DOE under the ARRA Program.  
National Grid has not identified any other non‐ratepayer source of funding for 
this program.  Consequently, National Grid is seeking cost recovery for the 
remaining 50% of project costs through the mechanisms outlined in Section 
III, below. 

Eligibility for Stimulus Funding:  The Company intends to apply for ARRA 
funding for the New York Smart Program under both the Smart Grid 
Investment Grant (SGIG) program (DOE –FOA‐0000058), as authorized by Title 
XIII, Section 1306 and Smart Grid Demonstration (SGD) Program (DOE‐FOA‐
0000036), authorized by Title XIII, Section 1304.  The FOAs for these 
                                 Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                      Case 09‐E‐0310 
                                              Updated Stimulus Proposal – July 2, 2009 
                                                                         Page 8 of 22 
programs, released by DOE on June 25, 2009, have made it necessary to 
consolidate clean energy modules in one deployment area and use the other 
area for a rapid roll out of existing Smart Grid technology.  Accordingly, 
National Grid will focus its SGIG application in the Albany (Capital District) 
area, and its SGD application in the Syracuse area. 

       In addition, National Grid has partnered with Ford Motor Company on 
the DOE's Transportation Electrification FOA (DE‐FA‐0000028).  National 
Grid is a sub‐applicant with 15 other utilities.  The proposal is to build and test 
740 electric vehicles, including the necessary charging and electric distribution 
infrastructure.  National Grid's cost share commitment is in the form of 
infrastructure that will support charging of these vehicles (i.e., investments 
for which regulatory approval is being sought in this Filing).  

B.  Phasor Measurement Units Program 

Project Description:   National Grid proposes to participate in a statewide 
program, developed in coordination with the NYISO and other New York 
utilities, to install PMUs at locations across New York in an effort to provide 
appropriate observability for the transmission network.   As part of this 
program, National Grid anticipates installing approximately twelve PMUs, 
primarily at the major 345 kV and 230 kV stations on the Company’s 
transmission system that already boast data fault recorders (DFRs)which can 
be easily upgraded to provide PMU capabilities.  The PMU modules will need 
to be compatible with the Company’s existing DFRs; however, where possible 
National Grid will consider purchasing PMUs from manufacturers such as GE 
and Macrodyne who have a manufacturing presence in New York.   A location 
list for the PMUs will be finalized once the NYISO and TOs complete a 
comprehensive review of the New York State transmission system.  A 
preliminary location list is attached hereto as Exhibit 5.   
                                     Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                          Case 09‐E‐0310 
                                                  Updated Stimulus Proposal – July 2, 2009 
                                                                             Page 9 of 22 
        In recent months, National Grid has participated in discussions with 
other New York TOs and the NYISO regarding the structure of a coordinated 
PMU project.  The likely outcome of these discussions is that each 
participating TO will, in collaboration with the other TOs and the NYISO, 
identify locations for PMU installations in an effort to provide appropriate 
observability for the transmission network.  The current understanding is that 
the NYISO would lead the submission of a regional application to DOE for 
stimulus funding on behalf of the TOs for the necessary PMU investment 
funds.  All TOs would collaborate on data exchange and interchange and the 
data will be available to regional and national Phasor Data Concentrators 
(PDCs).1  The requisite communications infrastructure still needs to be 
defined, but the evidence suggests that each PMU will require the equivalent 
of less than a T1 circuit (1.544 Mbit/s) for real‐time streaming of data.  
National Grid will endeavor to share existing T1 circuits that are currently 
used for applications such as surveillance monitoring and remote access to 
digital fault recorders (DFRs) to provide remote access to the PMU data.  
However, “last mile” connectivity needs to be determined for each 
substation, and a communications backbone may need to be established as 
part of a future project.   

        Initially, the PMUs will be used to provide post‐event data in addition 
to providing data for calibrating National Grid’s state estimation model.  At 
some point in the future when PDC technology stabilizes and is commercially 
available, National Grid will determine if there is sufficient value in purchasing 
a PDC.  Until that time, National Grid intends to stream its PMU data to PDCs 
located at the NYISO and NASPI2 once they are configured to accept the 
Company’s data. 

   National Grid anticipates the data being shared with PDCs at the NYISO and the North 
American SynchroPhasor Initiative Network (NSPINET). 
   North American SynchroPhasor Initiative ( 
                                         Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                              Case 09‐E‐0310 
                                                      Updated Stimulus Proposal – July 2, 2009 
                                                                                Page 10 of 22 
            Finally, National Grid intends to deploy off‐the‐shelf software 
applications that are matured and commercially available.  The Company will 
collaborate with the NYISO and the other TOs that are participating in the 
NYISO’s regional application in the selection of specific application(s).  The 
data will meet all applicable NERC‐CIP3 security requirements. 

            National Grid is particularly well suited to deliver on our proposal to 
provide observability into our bulk transmission system since many of the 
core elements are already in place.  We have already or are planning to 
deploy DFRs that will sample the voltage and current waveforms so as to 
provide analytic data of system stability anomalies.  The progression from a 
DFR to a PMU is primarily the addition of a circuit board to the DFR.  Since the 
Company’s proposal is predicated on upgrading existing DFRs where available, 
it will be a relatively straightforward deployment process. 

Interoperability:  National Grid plans to leverage its existing base of DFR’s and 
upgrade them to provide PMU capability.  For those locations that lack an 
existing DFR, the Company plans to install a new PMU.  These devices will be 
compliant with the IEEE C37.118‐2005 protocol.4  This standard defines the 
measurement, provides a method of quantifying the measurements, and 
defines quality test specifications.  It also defines data transmission formats 
for real‐time data reporting. 
Physical security:  Because PMUs provide data from locations that may be 
subject to NERC critical cyber‐security regulations, the locations where the 
PMU’s are installed and the data communications between the PMUs and the 
control facilities must be secure.  National Grid will provide cyber security and 
physical security at the substation. 
Project Milestones:  The Company will work collaboratively with the other 
TOs and the NYISO to establish a schedule for the deployment of PMUs and 

     North American Electric Reliability Corporation Critical Infrastructure Information 
     IEEE Standard for Synchrophasors for Power Systems
                                 Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                      Case 09‐E‐0310 
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                                                                        Page 11 of 22 
associated software applications.  Because we plan to upgrade many existing 
DFRs, National Grid’s ability to deploy its share of the PMUs will require 
minimal time relative to new installations. 
Cost Estimates:  National Grid estimates the cost of the PMU project as $2 
million, including both initial engineering design, procurement and installation 
costs and the ongoing cost of operations and maintenance.  A breakout of 
these cost projections can be found in Exhibit 6 attached hereto. 
Stranded Investment Risk:  National Grid recognizes the potential for 
stranded costs with the deployment of PMUs, but considers this to be a very 
low risk in this instance.  Most of the DFR devices are already installed and 
will remain in service for their anticipated 10 to 15 year life span.  The PMU 
cards will be compatible with the DFRs and would be expected to have a 
similar life although firmware and software upgrades may be necessary 
during the PMU life cycle.  Generally however, upgrades of this nature only 
require connection to a computer where the software or firmware can be 
downloaded into the device.  This is an unavoidable fact with modern 
microprocessor‐based relay and control devices.   
Jobs Created:  This project will result in acquisition of technically skilled 
individuals to design and install PMU installations.  National Grid estimates 
that approximately two new jobs could be created as a result of this project.  
The Company also expects that deployment of PMU devices will result in 
additional up‐skilling of our workforce so as to be able to perform the 
required O&M on digital devices. 
Eligibility for Stimulus Funding:  The PMU Program provides both: 
    •   “The ability to develop, store, send and receive digital information 
        concerning electricity use, costs, prices, time of use, nature of use, 
        storage, or other information relevant to device, grid, or utility 
        operations, to or from or by means of the electric utility system, 
        through one or a combination of devices and technologies”; and  
    •   “The ability to sense and localize disruptions or changes in power 
        flows on the grid and communicate such information instantaneously 
                                 Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                      Case 09‐E‐0310 
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       and automatically for purposes of enabling automatic protective 
       responses to sustain reliability and security of grid operations.” 
                                                      DOE‐FOA‐0000058, at 14. 

Therefore, this proposed PMU Program qualifies for ARRA funding under the 
SGIG Program. 

C.  Statewide Capacitor Bank Program 

Project Description:  National Grid is working in collaboration with the NYISO 
and the New York TOs to understand the needs, costs and benefits of a 
statewide capacitor bank investment program.  The NYISO is currently 
undertaking a study to update the optimal power flow assessment they 
performed earlier in the year.  This new assessment includes more likely 
locations for the capacitor installations as well as more realistic sizes and 
costs.  The NYISO will then review the resulting savings from reduced system 
loss.  The results of this study are only now becoming available.  It is 
anticipated that this study will provide National Grid with a better 
understanding of the case for a statewide program.  

Project Rationale:  The installation of capacitors on both the transmission and 
distribution system for increased reactive power support and improvement of 
voltage profile is an approach that has been adopted by National Grid for a 
number of years.  National Grid currently has a number of such installations, 
as part of existing reliability projects, both planned and under development. 

Project Milestones:  Milestones for this project would need to be developed. 
Project Costs:  A full understanding of the cost benefit case associated with a 
statewide capacitor deployment, and particularly that part of such a 
deployment on National Grid’s network, will need to be based on a careful 
analysis of the results of the study undertaken by the NYISO.  Once the results 
                                Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                     Case 09‐E‐0310 
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of this study become available, National Grid, together with the NYISO and 
the other New York TOs, will seek to consider the inclusion of such 
investments in our application. 

       National Grid has identified potential ARRA projects in New York State 
with total estimated capital and operating costs of $273 million, excluding the 
cost of the provisional Capacitor Bank program.  The level of spending 
outlined in this filing assumes that the Commission will set rates that enable 
National Grid to recover these costs concurrently with their incurrence and to 
earn a return consistent with national industry standards and commensurate 
with the size and timing of the spending outlined above. 

       National Grid’s proposed investment in advanced technologies is 
beyond the levels of investment in our proposed 5‐year Capital Investment 
Plan through fiscal year ending March 30, 2014.  These investments also 
involve the deployment of advanced technologies that were not at a 
development stage at the time of the National Grid and KeySpan mergers, 
and therefore were not contemplated utility investments at that time.  For 
these reasons, the Company is proposing special ratemaking treatment as 
outlined below.  We believe that investment in Smart Grid technology is in 
the best interest of customers.  National Grid is willing to make this 
investment, as outlined in this Filing and related attachments, provided that 
the Commission sets rates that permit the Company to recover its costs in a 
timely manner and earn a return on investment reflective of the significant 
increase in Company investment that this plan represents.  These programs 
are also subject to National Grid’s internal review and approval process, 
which is occurring concurrently with the Commission’s review. 
                               Niagara Mohawk Power Corporation d/b/a National Grid 
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       National Grid notes the increasing recognition of the need for 
infrastructure investment nationally and in New York and the increasing 
understanding of the need for a regulatory framework that facilitates and 
supports such investment.  This support in the form of cost recovery is 
particularly important in this effort to promote advanced technology in New 
York State.  National Grid notes that recent approvals of return on equity 
have been above the levels previously provided, recognizing that an attractive 
investment climate is critical for encouraging the deployment of new 
technology and infrastructure development.  Furthermore, the regulatory 
approval of an investment tracker mechanism for an electric utility, and 
continued Staff support for a tracker, represents another positive 
development to support investment.  These policies and mechanisms are 
essential in developing a regulatory environment that encourages and 
rewards investments that are in the public interest, including the Smart 
Program proposed herein. 

       Regarding cost recovery, National Grid requests that the Commission 
implement a surcharge with a tracking mechanism for these costs that allows 
for concurrent recovery of the Smart Grid investment and O&M expense.  As 
the Commission is aware, financial markets are very volatile during this period 
and further investment above the Company’s current capital plan may require 
additional financing.  An order from the Commission which allows recovery of 
costs as incurred will promote the appropriate level of assurance to the 
financial markets that the investment will be recovered on a timely basis and 
will make funding these investments less expensive for customers.  The 
Company’s ability to access the lowest cost funds offered by financial markets 
will be dependent on clear support from the Commission for recovery of 
these investments and expenses in real‐time, without a lag. 

       In order to recover the incremental funding needed for the ARRA 
projects after taking into account DOE grant awards, the Company proposes 
                                 Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                      Case 09‐E‐0310 
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forward‐looking mechanisms that will track and reconcile to actual incurred 
costs for these projects.  National Grid believes concurrent recovery is the 
only appropriate funding mechanism and that deferral accounting should be 
avoided due to the implications on cash flow and financing costs. 

       National Grid is currently earning less than its allowed rate of return 
and asking the Company to invest in a significant amount of infrastructure 
without timely recovery would magnify this earnings challenge.  Furthermore, 
National Grid is subject to International Financial Reporting Standards (IFRS).  
There are fundamental differences between U.S. Generally Accepted 
Accounting Principles (US GAAP) and IFRS.  Of particular relevance, under US 
GAAP, regulatory assets such as deferral of expenses as regulatory assets are 
recognized on the balance sheet.   Under IFRS, regulatory assets are not 
recognized on the balance sheet.  As a consequence, to the extent that 
National Grid is not permitted concurrent recovery of expenses incurred in 
the delivery of ARRA projects, National Grid plc is required to recognize the 
current period expense as opposed to recognizing a regulatory asset.  These 
deferred items generally reduce National Grid plc’s earnings in the year they 
are incurred and reported under IFRS.  In addition, as the Commission is no 
doubt aware, these deferred amounts generally create an obligation on the 
part of future customers to pay costs that arguably, in many instances, are 
more properly assigned to current customers.  While National Grid 
understands that the use of deferral accounting is an important tool available 
to the Commission to assure just and reasonable rates for customers and 
utilities, the Company also submits that creation of additional deferrals 
should be avoided when circumstances indicate that permitting the pass‐
through of a cost on a current basis will provide benefits to both customers 
and utilities.  Avoiding unnecessary deferrals will enable National Grid plc to 
present a clearer financial profile to investors, and put it in the best position 
possible to achieve an optimal cost of capital.    
                                  Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                       Case 09‐E‐0310 
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                                                                         Page 16 of 22 
         Another benefit of permitting the Company to recover the costs 
concurrently is that it will enable National Grid plc and the Company to 
achieve and present to the investment community more favorable financial 
results during a period in which National Grid will be seeking the most 
economical way to finance an aggressive capital campaign directed at 
providing its service territory with an energy infrastructure that will support 
the demands of its customers and meet public policy objectives for many 
years to come.  In approaching the investment community for new debt, 
National Grid is facing significant financial challenges associated with the facts 

    •    National Grid’s balance sheet already contains significant deferrals of 
         largely uncontrollable costs such as pension and other post‐
         employment benefit costs and manufactured gas plant remediation 

    •    National Grid’s rates reflect the imputation of significant levels of 
         synergy savings arising from National Grid plc’s acquisition of KeySpan 
         Corporation; and 

    •    National Grid is absorbing 50% of the revenue requirement impact 
         associated with $1.5 billion of prudently incurred capital investments.   

         The Company proposes to treat transmission and distribution revenue 
requirements separately, but collect them through the same billing surcharge.  
For the Smart Program‐related distribution projects, National Grid proposes 
to recover the revenue requirement associated with these investments, 
including annual operating expenses and return on rate base inclusive of 
                                    Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                         Case 09‐E‐0310 
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                                                                           Page 17 of 22 
construction work in progress (CWIP), at the Company’s weighted average 
cost of capital (WACC)5, through a surcharge applied to customer bills. 

        For the PMU and Capacitor Bank Programs, since the PMU Smart Grid 
technology will be wholly deployed on, and provide benefits to the operation 
of, the transmission system National Grid believes it is appropriate that, as far 
as practicable, existing mechanisms associated with the recovery of 
investment costs associated with the transmission system should be used as 
well as the surcharge.  Thus, the Company intends to make use of its existing 
FERC‐approved transmission specific formula for the calculation of an 
appropriate cost of capital and associated revenue requirement for the PMU 
deployment.  The Company believes that this approach to cost recovery is the 
most suitable for an investment such as the deployment of PMU Smart Grid 
technology on the transmission network.  Recovery from wholesale load will 
remain unchanged; the Company will continue to include PMU investment 
costs into its FERC‐filed wholesale transmission tariff though the existing 
transmission service charge (TSC) rate structure.  The TSC will provide for a 
portion of the investment costs to be paid by wholesale customers.  The 
existing rate mechanisms will also credit the wholesale payments received 
through the TSC to retail customers via the Transmission Retail Access Cost 
(TRAC) mechanism.  In order to provide for such recovery from retail load 
National Grid proposes to recover such costs through a surcharge applied to 
customer bills in the same manner as for the Smart Program‐related 
distribution projects.  

        National Grid also requests assurance that if these cost recovery 
proposals are abandoned for reasons beyond the control of the Company or 
otherwise rendered obsolete or no longer necessary beyond the 

  See Case 01‐M‐0075 – Joint Petition of Niagara Mohawk Holding, Inc., Niagara Mohawk 
Power Corporation, National Grid plc and National Grid USA for Approval of Merger and Stock 
Acquisition, Revisions to Joint Proposal dated November 6, 2001, Attachment 1, at 5 of 14. 
                                 Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                      Case 09‐E‐0310 
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demonstration phase, recovery of investments incurred or committed and not 
cancelable and abandoned are recoverable over an appropriate timeframe.  
The Company believes a policy and support for this treatment will be 
perceived positively by the financial marketplace, allowing attractive capital 

          The Company proposes that all capital costs related to these Smart 
Grid proposals, including costs related to metering and communications 
technologies as well as software and any associated hardware, and the costs 
of all associated transmission and distribution assets related to advanced 
technology, be included in the surcharge mechanism along with a return 
thereon.  Incremental customer outreach and education, marketing, and 
operation and maintenance costs should also be recovered as part of the 

          An indicative cost of service and revenue requirements for these 
proposals based on current estimates from our Smart Program proposal 
development process is shown in Exhibit 7.  The result is indicative because 
National Grid must select its partners in Smart Grid, negotiate terms, finalize 
design and re‐calculate expected cost for the program on an annual basis.  
Also, the tax treatment of the grant and the amount of grant will have an 
effect on the costs to provide these services proposed in this Filing.  This 
indicative cost of service provides a framework for comprehension of our 
proposal for cost recovery; however, the Commission should recognize that it 
will require adjustment as additional facts become known.  As the proposal 
encompasses both electric and gas customers, the Exhibits include estimated 
revenue requirements calculations for each.  

          The scope and size of the eventual Smart Program will be dependent 
on disbursement of and specific accounting and taxes associated with DOE 
grants awarded to National Grid and the remaining costs to be recovered 
                                  Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                       Case 09‐E‐0310 
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from ratepayers.  The Company has assumed a 50% match of the capital 
portion of the proposed Smart Program investment and that 
grant/demonstration monies are disbursed by DOE when the assets are 
placed in‐service.  For illustrative purposes, we have not assumed any tax 
consequences of the DOE grants.  Assets employed in the Smart Grid 
deployment are assumed to be depreciated based on industry standard lives.  
For the purposes of this illustration, National Grid has assumed that displaced 
meters and associated assets are retired.  In addition, to the extent that any 
fixed costs can be shared among other approved Smart Grid deployments by 
National Grid affiliates in other jurisdictions, it will lessen the rate impact on 
National Grid customers.  

          National Grid proposes to establish a mechanism to forecast annual 
operating and capital costs which would determine the increment to be 
added to the surcharge.  At least annually, forecasted costs would be 
reconciled with actual costs and any refund due or incremental recovery from 
customers would be incorporated in the next rate year’s surcharge along with 
the relevant forecasted operating and capital costs through a “carryforward” 
mechanism to reflect under‐ or over‐spending in any one year against the 
targets set for subsequent years and any difference in actual surcharge 
collection versus forecasted surcharge revenues.  

          National Grid has identified three projects, with a total estimated cost 
of approximately $273 million, excluding the cost of the provisional Capacitor 
Bank Program, for which it may pursue ARRA funding.  These projects include:  

      •   Investment in a Smart Grid program centered in the Syracuse and 
          Albany (Capital District) areas, with supporting investments on the 
          distribution system (New York Smart Program);  
                                 Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                      Case 09‐E‐0310 
                                              Updated Stimulus Proposal – July 2, 2009 
                                                                        Page 20 of 22 
    •    Investment in Phasor Measurement Units (PMUs) to be installed at 
         selected transmission substations as part of a statewide transmission 
         project potentially coordinated by the NYISO; and 

    •    Potential investment in capacitor bank installation on the Company’s 
         transmission system, as part of a statewide transmission project 
         potentially coordinated by the NYISO, pending review of a cost‐benefit 
         study currently in progress. 

National Grid believes that each of these programs has the potential to 
provide substantial benefits to its customers, and that each is eligible for 
ARRA funding. 
         With this Filing, National Grid submits a detailed proposal for its New 
York Smart Program.  This proposal, which will serve as the basis for National 
Grid’s funding proposal to DOE, provides a detailed description of program 
scope, location, technologies, and costs, as well as proposals for a Critical 
Peak Pricing Program, a Peak Time Rebate, and an Hourly Pricing Program.  
National Grid and National Grid affiliates have been developing a Smart 
Vision, which integrates Smart Grid equipment with in‐home devices and 
renewable technologies, over the past two years.  The Company is uniquely 
prepared to deliver a Smart program of this scope and scale.  National Grid 
therefore respectfully requests that the Commission approve its New York 
Smart Program and establish a cost recovery mechanism that would support 
this ambitious undertaking, consistent with the discussion in Section III of this 
         National Grid also has provided information on the likely scope, 
locations, technologies and costs of its proposed PMU Program, as well as 
initial location and cost data for a potential statewide Capacitor Bank 
Program.  While this information is subject to change, it provides an adequate 
basis on which evaluate the potential benefits of these programs and 
                                Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                     Case 09‐E‐0310 
                                             Updated Stimulus Proposal – July 2, 2009 
                                                                       Page 21 of 22 
establish appropriate cost recovery mechanisms.  National Grid therefore 
respectfully requests that the Commission approve the PMU Program, 
provisionally approve the Capacitor Bank Program, and establish a cost 
recovery mechanism consistent with the discussion in Section III of this Filing.   
       National Grid thanks the Commission for this opportunity to present 
its potential ARRA projects and proposals for cost recovery principles, and 
looks forward to working cooperatively with the Commission, the NYISO, the 
TOs, and others on these subjects. 
Exhibit 1
EXHIBIT 1                                                                                                                               American Recovery Reinvestment Act 2009 Utility                                                                                                          Page 1 of 1
                                                                                                                                                         Project List

Brief Description                             Priority Purpose, Rationale or Justification                                   List Expected                   Jobs     Total                Amount           Project Type - e.g. Shovel       Utility          Utility      Project Contact Email
                                              Scale 1                                                                        Benefits (Quantify              Created Project               Requested        smart grid,         Ready        Submitting       contact name
                                              (High) to                                                                      Where Possible)                 or       Costs                (assuming        disruption                       Project
                                              5 (Low)                                                                                                        Retained                      50%              recovery, etc.
New York Smart Program (Syracuse and           1        National Grid's Smart Program is designed to be fully consistent     National Grid’s Smart             300 - 500   $271,000,000    f di
                                                                                                                                                                                           $135,500,000     Smart Grid           Partial     National Grid    Keith Gossage
Albany): Deploy a Smart Grid "spine",                   with the Smart Grid guiding principles articulated in the Energy     Program is designed to
including a two-way communications network              Independence and Security Act of 2007, with the proposed DOE         demonstrate that a large
(Wide Area Network, Local Area Network, and             ARRA funding criteria recommended by the FERC-NARUC Smart            scale Smart Grid
Home Area Network), smart meters, in-home               Grid Collaborative, with the FERC Smart Grid Policy Statement
                                                                                                                             deployment may provide
energy management software and grid                     and Action Plan, and with the Electric Advisory Committee's vision
                                                                                                                             significant benefits to
monitoring and automation technology to                 of Smart Grid as an enabler of a new energy economy. We
                                                        therefore anticipate that National Grid's Smart Program proposal
                                                                                                                             customers and society by
serve 81,000 customers in the Syracuse and
Albany (Capital District) areas. The program            should meet EDER funding criteria with minimal changes.              enabling more efficient
will integrate energy storage units, wind                                                                                    energy consumption that
generation, photovoltaics, micro-CHP, PHEV                                                                                   results in reduced energy
infrastructure, holistic home equipment, and                                                                                 usage, better energy quality,
micro-grid infrastructure into the Syracuse                                                                                  improved reliability, and a
area. The program will also incorporate                                                                                      general reduction in the
SCADA equipment and circuit breakers to                                                                                      carbon emissions required
support the Spine and new Distribution and                                                                                   to produce and deliver
Outage Management Systems. Syracuse                                                                                          electricity to customers.
University has agreed to partner with National                                                                               Additionally, we hope to
Grid on elements of this program.
                                                                                                                             develop an understanding of
                                                                                                                             how significant Green
                                                                                                                             enabling technologies can
                                                                                                                             be integrated with the Smart
                                                                                                                             Grid Spine. The Smart
                                                                                                                             Program will support New
                                                                                                                             York's developing clean
                                                                                                                             energy vision, as most
                                                                                                                             recently articulated in the
                                                                                                                             March 31, 2009 Draft State
                                                                                                                             Energy Plan.

Phasor Measurement Units: Deploy              1         Knowledge of the state of the system at any given moment             PMU's can provide real-time 2                 $2,000,000      $1,000,000       Smart Grid           Partial --   National Grid   Alan Roe
approximately twelve Phasor                             can offer unprecedented insight and control over the                 state information of the                                                                            PMU
Measurement Units to acquire real-time                  network. Real-time analysis can offer the opportunity to             system. This allows the                                                                             Boards can
state information of the transmission                   "see" cascading events before they cause system instability          system operator to                                                                                  be readily
system, as part of a statewide program                  and corrective actions can be taken immediately by pre-              anticipate any system                                                                               installed in
coordinated by the NYISO.                               programmed algorithms. These devices can also be used to             instability and react prior to                                                                      existing
                                                        validate models against real time data allowing the modeling         an emergent situation. The                                                                          DFR's.
                                                        software to become much more accurate across a variety of            real time data can also be
                                                        differing system conditions.                                         used to model actual
                                                                                                                             alternative scenarios in case
                                                                                                                             of a system element failure.

Capacitor Upgrades -- Transmission:           3         NYISO is currently conducting a study to assess the costs            Enhance efficiency and          Estimate under Estimate under Estimate under   Grid Modernization   No          National Grid    Alan Roe
Install capacitors as part of a potential               and benefits of a state-wide capacitor bank program to               reliability of the New York     development    development    development
statewide initiative coordinated by the                 address line losses in New York. After reviewing the study           Transmission System
NYSIO to address line loss issues.                      results, National Grid will assess whether it is in our
                                                        customers interest to proceed with such a program. If so,
                                                        National Grid would pursue ARRA funding for this project
Exhibit 2
                              STATE OF NEW YORK
                          PUBLIC SERVICE COMMISSION

      Case 09-E-0310 - In the Matter of the American Recovery and Reinvestment Act of 2009
             - Utility Filings for New York Economic Stimulus Package


                 Niagara Mohawk Power Corporation d/b/a National Grid
                 Updated New York Economic Stimulus Package Proposal

                                                          Prepared By:

Dated: July 2, 2009
                              State Environmental Quality Review
                                Environmental Assessment Form


        An environmental assessment is an evaluation of the known or potential environmental
consequences of a proposed action. Such an assessment also determines whether additional
relevant information about such impacts is needed. Environmental assessments help involved
and interested agencies identify their concerns about the action and provide guidance to the lead
agency in making its determination of significance. This document provides the substantive
information solicited by Appendix C of 6 NYCRR 617.20, part of the regulations promulgated
by the New York State Department of Environmental Conservation pursuant to the State
Environmental Quality Review Act ("SEQRA"), Article 8 of the New York Environmental
Conservation Law. Because the proposed action is in the nature of policy-making and for the
Public Service Commission’s approval of the substantive merits of the proposed projects and
corresponding cost recovery mechanism rather than physical construction, a narrative exposition
of impact categories was chosen to communicate the information solicited rather than using the
standard form of the Environmental Assessment Form (“EAF”).

         An EAF provides an organized approach to identifying the information needed by the
lead agency to make its determination of significance. A properly completed EAF describes a
proposed action, its location, its purpose and its potential impacts on the environment. The EAF
is the first step in the environmental impact review process and leads to either a positive
declaration (requiring further analysis of the environmental impacts) or a negative declaration
(requiring no further action) of potentially significant adverse environmental impact(s).


1.     Applicant/Sponsor:

       Niagara Mohawk Power Corporation d/b/a National Grid
       300 Erie Boulevard West
       Syracuse, New York 13202

2.     Name of Action:

       Public Service Commission approval of the merits of the proposed projects and
       corresponding cost recovery mechanism comprising National Grid’s updated stimulus
       plan filing in Case 09-E-0310.

3 & 4. Location of the Action:

       New York State

5.   The Proposed Action:

     The proposed action under consideration is new.

6.   Description of Action:

     On February 17, 2009, President Obama signed into law the American Recovery and
     Reinvestment Act of 2009 (“ARRA”), which makes supplemental appropriations for job
     preservation and creation, infrastructure investment, energy efficiency and science,
     assistance to the unemployed, and State and local fiscal stabilization, for the fiscal year
     ending September 30, 2009. Among its other provisions, the ARRA appropriated $4.5
     billion to programs administered by the Office of Electricity Delivery and Energy
     Reliability (“EDER”) of the U.S. Department of Energy (“DOE”) for “electric delivery
     and energy reliability activities to modernize the electric grid, to include demand
     responsive equipment, enhance security and reliability of the energy infrastructure,
     energy storage research, development, demonstration and deployment, and facilitate
     recovery from disruptions of the energy supply, and for implementation of programs
     authorized under title XIII of the Energy Independence and Security Act of 2007.”

     On April 2, 2009, the State of New York Department of Public Service (“DPS”) issued a
     letter addressing cost recovery for projects to be undertaken in New York with funds
     from the EDER program. The letter noted that grants made by the DOE under the EDER
     program may not cover more than 50% of the costs of qualifying investments, and that,
     consequently, successful applicants would need to find other sources to cover the
     remaining costs of such investments. Where such funding sources included ratepayer
     funds, recovery of these costs from New York utilities’ ratepayers will require a
     determination by the Commission that such costs are reasonable. The April 2 letter
     instructed utilities planning to apply to the DOE under the EDER program to file their
     plans with the Commission on or before April 17, 2009 to allow the regulatory process
     for cost recovery to begin as soon as possible. In response, on April 17, 2009, Niagara
     Mohawk Power Corporation d/b/a National Grid (“National Grid” or the “Company”)
     submitted a description of those projects then under consideration for EDER funding that
     would also require funding by the Company’s ratepayers.

     On June 19, 2009, DPS extended the requested date for filing of updated stimulus plans
     by electric utilities from June 22, 2009 to within three business days following the
     issuance by the DOE of the final Funding Opportunity Announcement (“FOA”) for the
     Smart Grid Investment Grant Program (“SGIG”).

     On June 29, 2009, following the June 25, 2009 issuance by DOE of the final FOAs for
     the SGIG as well as the Smart Grid Demonstration Program (“SGD”), DPS further
     extended the date for filing of updated stimulus plans by utilities to July 2, 2009.

     National Grid’s July 2, 2009 updated stimulus plan filing with the Commission proposes
     to seek DOE funding for three discrete projects as follows:

              •   Investments in a Smart Grid program centered in the Syracuse and Albany
                  areas with supporting investments on the distribution system that will
                  integrate selected clean energy technologies such as photovoltaics, plug-in
                  hybrid electric vehicles, energy storage, wind power, micro-CHP, microgrids,
                  and holistic homes (the “New York Smart Program”);

              •   Investments in Phasor Measurement Units (“PMUs”) at certain substations on
                  the Company’s transmission system as part of a statewide transmission project
                  coordinated by the New York Independent System Operator (“NYISO”); and

              •   Potential investment in capacitor bank installations on the Company’s
                  transmission system, as part of an overall statewide transmission project
                  coordinated by the NYISO, pending review of the results of a benefit-cost
                  study currently in progress.

       National Grid’s updated stimulus plan filing provides a detailed proposal for the New
       York Smart Program, including program scope, location, technologies and costs, which
       will serve as the basis for the Company’s funding proposal to the DOE. Although
       National Grid’s updated stimulus plan filing also provides information on the likely
       scope, locations, technologies and costs of the proposed PMU program, as well as initial
       location and preliminary cost data for a potential statewide capacitor bank program,
       sufficient to evaluate the potential benefits and establish cost recovery mechanisms, the
       information for these two programs remains subject to change.

7-9.   Land Affected, Zoning and Land Use:

       The action to be undertaken by the Commission does not include direct approval for the
       siting of equipment or construction of facilities. Therefore, a consideration of site-
       specific amounts of land affected, and compliance with existing zoning or other land use
       controls are inapplicable to this evaluation.

10-12. Permits:

       The action will ultimately involve funding from the DOE for up to 50% of the investment
       costs. Otherwise, the projects are not anticipated to involve any permit approvals or
       permit modifications from any other governmental agency.


1.     The action does not exceed any Type I threshold as set forth in 6 NYCRR
       Part 617.4.

2.     There are no other "involved agencies" (state or local agencies with permitting or
       regulatory authority) regarding the action. Therefore, a "coordinated review" as provided
       for in the unlisted action in 6 NYCRR, Part 617.6 is inapplicable.

3.   Potential for Adverse Effects:

     The described action is not likely to cause any direct environmental effects, since the
     action alone does not involve physical activities that might have impacts on the
     environment. Instead, the action would likely create circumstances that subsequently
     induce activities, which in turn may cause environmental effects. This environmental
     assessment sets out an evaluation of a range of conceivable secondary consequences of
     the action. The evaluation relies on qualitative judgments as to the potential changes
     resulting from the proposed actions and the magnitude and importance of the
     corresponding potential environmental impacts.

     a.     Impact to Air

            The action is not likely to cause any direct adverse environmental effects, since
            the action is intended to and would likely reduce the demand for electricity
            generated by the combustion of coal, oil, and natural gas in large central
            generating plants which in turn should result in reductions in the emissions of
            sulfur dioxide, nitrogen oxides, particulates, and carbon dioxide emitted as
            byproducts of such combustion processes employed in the burning of fossil fuels.
            To the extent that clean energy technologies such as photovoltaics, plug-in hybrid
            electric vehicles, energy storage, wind power, and micro-CHP are successfully
            integrated into the proposed New York Smart Program, the result could be larger
            reductions in emissions of sulfur dioxide, nitrogen oxides, particulates and carbon

     b.     Impact to Water

            The implementation of the action would likely not have any significant adverse
            impact on water resources.

     c.     Impact to Land

            The implementation of the action would likely not have any significant adverse
            impact on land drainage or soil erosion.

     d.     Impact on Plants and Animals

            The implementation of the action would likely not have any significant adverse
            impact on fragile terrestrial and aquatic plant and animal species. To the extent
            that siting of additional wind power generation facilities is a conceivable
            consequence of the action, the result may create concern over possible detrimental
            impact to certain species of wildlife.

     e.     Impact on Agricultural Land Resources

            The implementation of the action would likely not have any significant adverse
            impact on agricultural land resources.

f.   Impact on Aesthetic Resources

     The implementation of the action would likely not have any significant adverse
     impact on aesthetic resources. To the extent that siting of additional wind power
     generation facilities is a conceivable consequence of the action, the result may
     impede on visual aesthetics due to viewshed impacts.

g.   Impact on Historic and Archaeological Resources

     The implementation of the action would likely not have any significant adverse
     impact on historic and archaeological resources.

h.   Impact on Open Space and Recreation

     The implementation of the action would likely not have any significant adverse
     impact on open space and recreation. To the extent that siting of additional wind
     power generation facilities is a conceivable consequence of the action, the result
     may impede on open space.

i.   Impact on Transportation

     The implementation of the action would likely not have any significant adverse
     impact on transportation. To the extent that plug-in hybrid electric vehicles
     achieve a significant penetration as a conceivable consequence of the action, the

j.   Impact on Energy

     The implementation of the action would likely result in reduced demand for
     electricity and natural gas. However, the action, as described above, could
     involve changes in policy, practices and economic arrangements affecting the
     choice and development of new generation sources and dispatch and retirement
     decisions of existing sources. Also, any decrease in electricity demand would
     likely result in a corresponding decrease in demand for commodity fuels
     consumed in the generation of electricity. To the extent that high levels of market
     penetration of plug-in vehicles are realized as a conceivable consequence of the
     action, New York’s dependency on foreign oil would be reduced as well as the
     fuel cost of transportation for end users. With adequate sensing and control, plug-
     in vehicles could also provide grid-level benefits of fixed energy storage.

k.   Noise and Odor Impact

     The implementation of the action would likely not have any significant adverse
     impacts related to Noise or Odor. To the extent that high levels of market
     penetration of plug-in vehicles are realized as a conceivable consequence of the
     action, there would be reduced traffic noise.

       l.      Impact on Public Health

               In the event that there is a reduction in the use of fossil fuel-fired generation due
               to implementation of the action, reductions in the emission of sulfur dioxide,
               nitrogen oxides and particulates could occur. Such a reduction could reduce
               asthma and other respiratory impacts on humans. To the extent that high levels of
               market penetration of plug-in vehicles are realized as a conceivable consequence
               of the action, the resulting reduced emissions from fossil-fueled vehicles could
               further reduce asthma and other respiratory impacts on humans.

       m.      Impact on Growth and the Character of a Community or Neighborhood

               The implementation of the action would likely not have any significant adverse
               impact on the growth and the character of any communities or neighborhoods.
               The action under consideration would likely induce some new construction that
               would introduce new structures into the landscape, but such structures are
               expected to be of small scale and generally accessory to existing structures
               already in the landscape. The action may also induce increased economic
               development opportunities in the renewable resources industry and the attraction
               of renewable technology manufacturers and installers to New York State.

       n.      Cumulative Impacts

               There are no other long-term, short-term, cumulative, or other effects not
               identified above.


1.      The approval of the action does not include direct approval for the siting or construction
of any facilities. Therefore, a consideration of potential site-specific impacts on the
environmental characteristics that cause the establishment of a critical environmental area is
inapplicable to this evaluation.

2.     There is not likely to be significant public controversy related to potential adverse
environmental impacts that may result from the approval of this action.

New York State Public Service Commission
Name of Lead Agency

Print or Type Name of Responsible Officer in Lead Agency

Title of Responsible Officer

____________________________________                                 ______________________
Signature of Responsible Officer in Lead Agency                      Date

Exhibit 3
Date of Request: May 21, 2009                   Request No.: National Grid-1
                                                NMPC Req. No.: NM 1 PSC-1 Staff-1

                 ELEC-NY Stimulus Filing Case 09-E-0310
                       Request for Information

FROM: PSC Staff Team


Are there any projects included in the Company’s April 17 filing that the Company
intends to seek recovery of associated costs through a FERC filed tariff?


National Grid currently has two tariffs through which it undertakes transmission cost
recovery: i) a retail tariff that addresses transmission assets as well as distribution assets;
and ii) a FERC filed wholesale tariff that only addresses transmission assets.

Currently, recovery of costs associated with investments that are solely associated with
National Grid’s transmission system is apportioned via both the retail tariff and the FERC
filed wholesale tariff.

For transmission based stimulus projects National Grid is developing a proposed cost
recovery mechanism it believes to be appropriate to the incremental nature of stimulus

The mechanism would continue to make use of apportioned cost recovery between
National Grid’s FERC jurisdictional wholesale and retail tariffs. The FERC jurisdictional
tariff would continue to be used as at present, while cost recovery via the retail tariff
would be adjusted to provide for timely recovery via a formula based mechanism more
suitable for transmission type investments.

Name of Respondent:                                             Date of Reply:

Tim Martin                                                      May 29, 2009

Form 103
Date of Request May 21, 2009                   Request No. National Grid-2
                                    NMPC Req. No. NM 2 PSC-2 Staff-2

           NIAGARA MOHAWK POWER CORPORATION d/b/a National Grid
                   ELEC-NY-NE Stimulus Filing Case 09-E-0310
                           Request for Information


Form 103                                                     CONFIDENTIAL
Name of Respondent: Larry Sturm   Date of Reply: May 27, 2009

Form 103                                              CONFIDENTIAL
Date of Request: May 21, 2009                Request No.: National Grid-2
                                             NMPC Req. No.: NM 2 PSC-2 Staff-2

           NIAGARA MOHAWK POWER CORPORATION d/b/a National Grid
                   ELEC-NY-NE Stimulus Filing Case 09-E-0310
                           Request for Information

FROM: PSC Staff Team


For the power point slides presented during the Company’s May 8, 2009 meeting with
Staff, provide a breakdown of operations and maintenance costs based upon O&M costs
associated with initial project start-up and ongoing operation (see, p. 7, item 6 of SGIG-
Indicate whether the O&M costs associated with the project, both initial and on-going
costs, are included in the project cost data included in the April 17 filing.


Niagara Mohawk Power Corporation d/b/a National Grid (“National Grid” or the
“Company”) has interpreted this question as a request to clarify how much of the
proposed New York Program will qualify under the U.S. Department of Energy's
(“DOE”) Investment Criteria.
Under the DOE investment criteria, as detailed in the Smart Grid Investment Grant
Program Notice of Intent (SGIG-NOI), the DOE appears to disqualify all operational and
capital spend funds related to the on-going operations of Smart Grid programs:
       6. Expenditures for ongoing salaries, benefits, or personnel costs not incurred in
       the initial installation, training, or startup of smart grid functions.
This will impact the qualified investment opportunity for which matching funds are
available and the funds for which National Grid would seek rate recovery.
For the “Spine”, the Company believes those disqualified funds will likely include
backhaul related and IT operational expenses (i.e., power costs, IT "run the business"
(“RTB”) costs, hardware and software maintenance licenses). National Grid views
marketing expense as a critical part of Smart Grid start-up costs and thus eligible for
matching funds. The success of the Company’s marketing program will be a key driver
of Smart Grid benefits and we believe DOE and the industry may benefit from access to
any marketing insights gained.
For the “Module”, the Company believes those disqualified funds will likely include only
the cost of ongoing operations. Items related to the start-up and integration with the
“spine” are included as operational expenditures eligible for matching grants. National
Grid believes that management and reporting are distinct from the cost of operations and
are eligible for matching grants from the DOE.

Form 103
Of the Company’s total $249.1 million estimated cost for its proposed Smart Grid
Demonstration Program, National Grid estimates that $241.5 million, or 96.9% of the
total, would meet DOE eligibility requirements. At this time, the Company is not aware
of any other expenditures that are likely to be “disqualified” under the terms of the DOE
Attachment A provides more detailed cost estimates that the Company deems
confidential and for which trade secret protection is being sought from the DPS Records
Access Officer. As such, Attachment A is not enclosed.

Name of Respondent: Larry Sturm                     Date of Reply: May 27, 2009

Form 103
Date of Request: May 21, 2009                Request No.: National Grid-2
                                             NMPC Req. No.: NM 2 PSC-2 Staff-2

           NIAGARA MOHAWK POWER CORPORATION d/b/a National Grid
                   ELEC-NY-NE Stimulus Filing Case 09-E-0310
                           Request for Information

FROM: PSC Staff Team


For the power point slides presented during the Company’s May 8, 2009 meeting with
Staff, provide a breakdown of operations and maintenance costs based upon O&M costs
associated with initial project start-up and ongoing operation (see, p. 7, item 6 of SGIG-
Indicate whether the O&M costs associated with the project, both initial and on-going
costs, are included in the project cost data included in the April 17 filing.


Niagara Mohawk Power Corporation d/b/a National Grid (“National Grid” or the
“Company”) has interpreted this question as a request to clarify how much of the
proposed New York Program will qualify under the U.S. Department of Energy's
(“DOE”) Investment Criteria.
Under the DOE investment criteria, as detailed in the Smart Grid Investment Grant
Program Notice of Intent (SGIG-NOI), the DOE appears to disqualify all operational and
capital spend funds related to the on-going operations of Smart Grid programs:
       6. Expenditures for ongoing salaries, benefits, or personnel costs not incurred in
       the initial installation, training, or startup of smart grid functions.
This will impact the qualified investment opportunity for which matching funds are
available and the funds for which National Grid would seek rate recovery.
For the “Spine”, the Company believes those disqualified funds will likely include
backhaul related and IT operational expenses (i.e., power costs, IT "run the business"
(“RTB”) costs, hardware and software maintenance licenses). National Grid views
marketing expense as a critical part of Smart Grid start-up costs and thus eligible for
matching funds. The success of the Company’s marketing program will be a key driver
of Smart Grid benefits and we believe DOE and the industry may benefit from access to
any marketing insights gained.
For the “Module”, the Company believes those disqualified funds will likely include only
the cost of ongoing operations. Items related to the start-up and integration with the
“spine” are included as operational expenditures eligible for matching grants. National
Grid believes that management and reporting are distinct from the cost of operations and
are eligible for matching grants from the DOE.

Form 103
Of the Company’s total $249.1 million estimated cost for its proposed Smart Grid
Demonstration Program, National Grid estimates that $241.5 million, or 96.9% of the
total, would meet DOE eligibility requirements. At this time, the Company is not aware
of any other expenditures that are likely to be “disqualified” under the terms of the DOE
Attachment A provides more detailed cost estimates that the Company deems
confidential and for which trade secret protection is being sought from the DPS Records
Access Officer. As such, Attachment A is not enclosed.

Name of Respondent: Larry Sturm                     Date of Reply: May 27, 2009

Form 103
Date of Request: June 18, 2009                  Request No.:             National Grid-4
                                                NMPC Req. No.:        NM 4 PSC-4 Staff-4

                 ELEC-NY Stimulus Filing Case 09-E-0310
                       Request for Information

FROM: Staff Team


For each stimulus project identified in your April 17, 2009 filing and any subsequent
updates, please provide the following:

   1. Identify the specific communication technology and devices to be deployed and
      the communication protocol used by each element and/or segment in the system.

   2. For each separate device, technology and protocol deployed, identify all
      applicable device and communication standards used, describing the open or
      proprietary nature of each.

   3. Describe the interoperability of each network segment as it relates to the ability
      for similar, standards-based devices to operate within the network.

   4. Identify within each network segment, elements in the communications
      technology or protocol deployed that restrict operation to a single vendor or

   5. For systems or elements using proprietary protocols or technologies, please
      identify the elements and explain the reason why such system or element needs to
      be employed, and how the utility and vendor will ensure that there is no
      obsolescence of the element or system.


At this time, Niagara Mohawk Power Corporation d/b/a National Grid (“National Grid”
or the “Company”) is unable to respond completely to this request because the majority
of the questions asked have answers that are vendor dependent. National Grid is in the
beginning stages of implementing its Proof of Concept (PoC) test facility in which we
will be evaluating a number of different vendor offerings. The results of the PoC testing
will be used to decide the complete list of vendors the Company will engage for the
demonstration projects. Since vendors have not been selected at this time, National Grid
cannot define the exact technologies and protocols that will be implemented in each

National Grid is currently monitoring the fast track effort of the National Institute of
Standards and Technology (NIST) to develop a series of standards to be used for Smart
Grid. While the timing between the finalization of the standards and the deployment of
the Company’s Smart Grid demonstration project is not ideal, National Grid will continue
to follow NIST’s efforts and will consider the agreed upon standards as we further define
our demonstration project.

Finally, it is National Grid’s stated goal to minimize cost and maximize choice by
utilizing technology that adheres to open standards and is available from multiple sources
as much as possible.

Name of Respondent: Stephen Koscs               Date of Response: June 23, 2009

Date of Request: June 1, 2009                                Request No.: National Grid-3
                                                             NMPC Req. No.: NM 3 PSC-3 Staff-3 #1

                     ELEC-NY Stimulus Filing Case 09-E-0310
                           Request for Information

FROM: Staff Team

1. Provide the criteria that will be used to select the PMUs to be used.
2. Provide a list of the manufacturers that will be considered for PMUs.
3. Provide the technical spec that each manufacturer must meet in order to be selected.
4. Provide the criteria for selecting the location of each planned PMU and justify why
that location was selected.
5. Provide a description of the equipment the PMUs will be attached to, and the standards
the attachment equipment must meet.
6. Is any of the intended attachment equipment unable to meet the equipment standards
after the attachment? If so, provide a list of such equipment and specify what changes
will have to be made to the equipment to meet the applicable standards after attachment
and the associated cost?
7. Provide a technical description of the equipment architecture to be used for the PMUs.
8. Describe the software architecture to be used in the PMUs and the ability of the PMUs
to be made compatible with other platforms.
9. Provide a description of the communication mediums needed by the PMUs and the
speed needed to communicate, including the mediums for communication with the utility
control centers.
10. Provide the communication mediums needed to transmit the data to the PMU and to
the control center. Do those communication mediums exist presently at or near those
11. Provide the location of where the data of the PMUs will be sent to and processed.
12. Provide a time line for each planned PMU location.

1.    Provide the criteria that will be used to select the PMUs to be used.

            Niagara Mohawk Power Corporation d/b/a National Grid (“National Grid” or the
            “Company”) proposes to select Phasor Measurement Unit (“PMU”) devices that
            will comply with existing relevant standards such as IEEE C37.118. 1 In selecting
            these devices, we will also consider the total cost to establish PMU capability.
            Since National Grid is considering participation in regional and national
            synchrophasor projects, we will also require interoperability with current
            NASPInet and NYISO initiatives.

    IEEE Std C37.118-2005 (Revision of IEEE Std 1344-1995) IEEE Standard for Synchrophasors for Power Systems

2.      Provide a list of the manufacturers that will be considered for PMUs.

        The North American SynchroPhasor Initiative (“NASPI”) website 2 provides a list
        of IEEE C37.118 compatible PMU-capable devices. To the extent National Grid
        requires additional hardware; we would likely purchase PMUs or PMU-capable
        devices      from      the     manufacturers     on     this     list.    See

        It is currently the Company’s plan to leverage its installed base of ERLPhase
        Power Technologies’ Tesla 3000 Digital Fault Recorders 3 to provide phasor
        measurement capability. However, National Grid’s internal procurement rules
        will require us to evaluate any manufacturer devices that meet the design criteria.

3.      Provide the technical spec that each manufacturer must meet in order to be

        National Grid does not currently own any PMUs and thus has not developed
        technical standards to guide the selection and procurement of these devices. For
        new PMU devices, we will coordinate our requirements with the NYISO to
        ensure that our devices are fully compliant with applicable standards and will
        properly interoperate with NYISO devices. Should a technical specification
        become necessary, National Grid may leverage the specifications already
        developed for the NYISO and NASPI. The only specification we are aware of
        that is available today is the IEEE 37.118-2005. See the following for further

4.      Provide the criteria for selecting the location of each planned PMU and
        justify why that location was selected.

        National Grid initially intends to locate its PMUs where they will allow the
        Company to acquire post-event data and provide sufficient data to better calibrate
        our state estimation models.

        National Grid seeks to strive for full observability of its network with PMU
        devices over time. This goal will require a careful regional analysis of the
        transmission network. The locations will also depend on the nature of the
        software applications that National Grid ultimately deploys. As noted in our
        April 17, 2009 filing with the Commission, National Grid has proposed certain
        locations where either we have existing upgradable digital fault recorders
        (“DFRs”) or where the NYISO has recommended PMU installation.

 The ERLPhase Power Technologies’ Tesla 3000 can be upgraded to provide PMU capability. See

     National Grid may alter the proposed list of locations upon further analysis in
     conjunction with other regional entities including our neighboring Transmission
     Owners (“TOs”) and the NYISO.

5.   Provide a description of the equipment the PMUs will be attached to, and the
     standards the attachment equipment must meet.

     National Grid intends to connect the PMUs to existing relay class PTs and CTs.
     While these measurement devices have an accuracy of 0.6%, they represent the
     vast majority of the Company’s installed base. Given that a PMU may connect to
     multiple feeders, busses and other devices in a substation, the most cost- effective
     means is to use existing assets. The data from the PMU will in time be delivered
     to a phasor data concentrator (“PDC”) at a remote site whether it is located at a
     National Grid facility or a NYISO/NASPI facility.

6.   Is any of the intended attachment equipment unable to meet the equipment
     standards after the attachment? If so, provide a list of such equipment and
     specify what changes will have to be made to the equipment to meet the
     applicable standards after attachment and the associated cost?

     Because National Grid intends to use existing relay class PTs and CTs, we do not
     anticipate the need to upgrade the existing assets. There may be the occasional
     need for capacitor voltage transformer (“CVT”) style equipment to be replaced
     with wound CTs and PTs. However, the Company will not know that level of
     detail until a final list of locations has been determined in conjunction with the
     NYISO and our neighboring TOs.

7.   Provide a technical description of the equipment architecture to be used for
     the PMUs.

     The exact architecture that will be deployed is still under discussion with the
     NYISO. We expect that data from National Grid PMUs may in the future be
     streamed to a National Grid PDC which in turn will share data with a NYISO
     PDC and possibly PDCs at NASPI and other regional locations.

     A possible architecture includes a PMU located at a substation to be connected to
     PT and CT devices in order to capture the raw data. The raw data will then
     receive a timestamp from a GPS time source and be sent over a communications
     medium (e.g., private fiber or leased circuit) to a PDC. The PDC would then in
     turn be connected to: (a) other PDCs making data available to other system
     operators; and (b) National Grid computers running specific applications that
     make use of the data.

8.    Describe the software architecture to be used in the PMUs and the ability of
      the PMUs to be made compatible with other platforms.

      National Grid will endeavor to leverage any software developed by respondents to
      the U.S. Department of Energy (“DOE”) and NYS funding initiatives and other
      third parties for its operational use. National Grid will coordinate with the
      Electric Power Research Institute (“EPRI”), Rensselaer Polytechnic Institute
      (“RPI”) and the New York State Energy Research and Development Authority
      (“NYSERDA”) efforts to develop suitable applications for PMU data. We
      anticipate that the software developed under these programs will be compatible
      with a variety of the more commonly deployed hardware platforms.

      At this time, we do not expect the real-time streaming PMU data to be integrated
      into our Energy Management System (“EMS”) but rather would be available on a
      separate computer system. Perhaps in the future, when the EMS is upgraded, the
      Company may integrate the two systems.

9.    Provide a description of the communication mediums needed by the PMUs
      and the speed needed to communicate, including the mediums for
      communication with the utility control centers.

      The monies in National Grid’s April 17, 2009 proposal to the Commission only
      included the hardware but not the communication infrastructure since there is still
      engineering required to determine the final architecture. We believe that the
      bandwidth requirements will be driven by the application requirements (e.g.,
      post-event analysis will not be as bandwidth intensive as real-time streaming).

      National Grid believes that a deterministic, redundant and secure communications
      medium is necessary to meet the requirements for wide area phasor applications.
      A fiber-based ring system would be best whether the Company leases bandwidth
      from a commercial provider or deploys its own. A secondary alternative is to
      lease dedicated circuits from Verizon or other parties. However, in the latter
      approach, neither the TOs nor the NYISO would be able to exert control over the
      communications infrastructure.

      The latency requirements for the data would have a sizeable impact on the
      medium of choice.       This too is impacted by the final system architecture
      regarding connectivity between the PMUs and PDCs.

10.   Provide the communication mediums needed to transmit the data to the
      PMU and to the control center. Do those communication mediums exist
      presently at or near those substations?

      While each substation typically has some existing communications capability,
      additional investigation will have to be undertaken during the preliminary
      engineering phase to identify the excess capacity that might be available for

       streaming PMU data back to the Company’s control center. If the required
       bandwidth exceeds the bandwidth remaining, then additional communications
       infrastructure will have to be provided to the substation. In the event that real-
       time streaming of all data is required, the Company anticipates a bandwidth of
       greater than 19.8 kb/s to be required whereas post-event analysis may be able to
       suffice with slower data rates.

11.    Provide the location of where the data of the PMUs will be sent to and

       National Grid’s proposal is to initially install PMUs or PMU-capable devices
       inside certain substations. The data would likely initially be delivered from the
       PMU to existing PDCs whether at the NYISO, NASPI or both. However, we
       anticipate that in the future the Company would procure and operate its own PDC.

       Regardless of the physical location of the PDC, National Grid will require access
       to the data for our applications. The data could be accessed via a LAN or VPN
       depending on whether the Company has a PDC on-site or it is at a remote
       NYISO/NAPSI facility.

12.    Provide a time line for each planned PMU location.

       A timeline has not yet been established. Any timeline would be predicated upon
       internal National Grid approval for this project plus detailed engineering results
       and DOE award.

       DOE provides up to 3 years to fully implement the awarded project. National
       Grid expects to continue development and refinement of our plans throughout the
       DOE process so that we can be best prepared to proceed upon receipt of an award.

Comments: National Grid believes that deployment of PMUs will bring the operation of
the transmission grid to a new level. However, PMU deployment is still in a nascent
stage. Phasor measurements will need to be acquired and delivered in a timely fashion to
be of value to the operators and applications will have to be coded to allow system
operators to better manage the electric system. Both of these initiatives will take time to
mature, but we have the opportunity to begin the process now.

Coordination between stakeholders will be required to ensure that PMU deployments are
efficient and cost-effective. Shared use of assets for data collection, software analysis
tools and communications infrastructure will allow the Company to keep the costs down
while expanding the capabilities of its system operators. In this way, technological
innovations can be applied to the system at a least-cost to National Grid’s customers who
will ultimately benefit from these investments.

Name of Respondent: Alan Roe                           Date of Response: June 5, 2009

Exhibit 4
Exhibit 4 – Comparison of April 17 Proposal with Updated Stimulus Filing 
         In the April 17 Proposal, National Grid identified nine projects with potential for 
ARRA funding, including a Smart Grid investment and demonstration project in the 
Albany (Capital District) and Syracuse areas, four transmission projects (PMUs, advanced 
relays, capacitor upgrades, and physical security at nine high‐priority sites), and four 
distribution projects (SCADA, line reclosers, line‐based capacitors, and subtransmission 
circuit breakers).  Based upon further analysis and feedback from DPS Staff, National 
Grid has consolidated its Smart Grid Demonstration Project with supporting elements of 
the distribution projects to create the New York Smart Program, which encompasses 
Smart Grid installations in the Syracuse and Albany (Capital District) areas, supporting 
SCADA equipment and subtransmission circuit breakers, and new distribution and 
outage management technology.  We have also refined the Green Modules by 
decreasing the funding allocated to certain technologies while increasing funding for 
others, based on requirements in the final DOE FOA and to further strengthen our 
planned grant application to DOE. 
         Additionally, based on further analysis and feedback from DPS Staff, National 
Grid has determined that it will not pursue ARRA funding for two of the four 
transmission projects: the electro‐mechanical relay project and the physical security 
project.  National Grid continues to pursue the PMU Program and will evaluate the 
transmission capacitor bank program in conjunction with the NYISO and other New York 
         Table 1 summarizes the differences between the April 17 Proposal and this Filing 
for these three categories of projects.
                                                                  Table 1. PROJECT SUMMARY 

April 17 Proposal Description            April 17         Status in Updated Stimulus Proposal                                                       Updated Cost 
                                         Proposal Cost 
Smart Grid 
New York Smart Program ‐‐                $249,100,000     •  Smart Grid Program – Syracuse and Albany (Capital District) areas (additional          $250,230,000 
Syracuse and Albany (Capital                                 $1.23 million  is a result of an additional 12 months of program life per the final     
District) areas                                              guidelines under the DOE Smart Grid Demonstration Program)                              
                                                          • SCADA enablement of 17 substations                                                            4,000,000 
                                                          • Digitizing subtransmission circuit breakers at 9 substations                                  1,450,000 
                                                          • Digital Distribution and Outage Management Systems                                          14,990,000 
                                                          TOTAL:                                                                                    $270,670,000 
Transmission‐Related Projects 
Advanced Relaying System                 $20,000,000      Removed from proposal                                                                     ‐0‐ 
Substation Physical Security             $9,000,000       Removed from proposal                                                                     ‐0‐ 
System State Analysis (deployment        $2,000,000       Retained                                                                                  $2,000,000 
of PMUs on the transmission 
Installation of capacitors on the        NA               Provisionally retained                                                                    Not yet 
transmission system                                                                                                                                 known 
Distribution‐Related Projects 
SCADA equipment at 32 distribution       $8,100,000       Scaled back to support Syracuse and Albany area projects and incorporated into the        (see above) 
substations                                               New York Smart Program 
Deployment of reclosers at               $2,500,000       Removed from proposal                                                                     ‐0‐ 
distribution substations 
Installation of line‐based capacitors    $4,000,000       Removed from proposal                                                                     ‐0‐ 
on the distribution system 
Installation of subtransmission          $3,000,000       Scaled back to support Syracuse and Albany area projects and incorporated into the        (see above) 
circuit breakers at nine distribution                     New York Smart Program 
Distribution Management                        ‐0‐        Added in Updated Stimulus Proposal; incorporated into New York Smart Program              (see above) 
System/Outage Management 
Exhibit 5
                Exhibit 5: Proposed PMU Locations 

Bulk Power Station        Field Location         State 
345 kV 
Clay 345 kV               Syracuse               NY 
Scriba                    Oswego                 NY 
Volney*                   Oswego                 NY 
Edic                      Mohawk  Valley         NY 
New Scotland              Capital                NY 
Leeds                     Capital                NY 
230 kV 
Porter                    Mohawk  Valley         NY 
Rotterdam                 Capital                NY 
Gardenville               Buffalo                NY 
Packard                   Buffalo                NY 
Huntley                   Buffalo                NY 
Dunkirk                   Buffalo                NY 
     * Existing DFR cannot be upgraded and will need to be replaced. 
Exhibit 6

Exhibit 6: Budgetary Estimate for PMU Program 
  Budgetary Estimate for DFR Upgrades 
  NY PSC Filing July 2, 2009 
  Category                                            Cost 
Exhibit 7

                                                                                                                                                                                          Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                                                                                                                              Case 09-E-0310
                                                                                                                                                                                                      Updated Stimulus Proposal – July 2, 2009
                                                                   New York Smart Program Proposal                                                                                                                                   Exhibit 7
                                                               Total Program (Spine, Modules and T&D)                                                                                                                              Page 1 of 9
                                                          Summary - Total Estimated Annual Revenue Requirement

                                                                              Year 1                     Year 2                    Year 3                    Year 4                    Year 5

            Total Smart Grid Program
          1       Year-end Rate Base
          2       Return and Taxes                                                 $718,970                $2,444,927                $9,485,971              $11,168,945                $9,713,307
          3       Operating Expenses
          4       Book Depreciation                                                  $17,241                  $43,604                $3,453,953              $10,382,292               $11,233,875
          5       Property Taxes                                                     $26,800                  $26,800                   $26,800                 $202,770                $3,534,133
          6       COR Tax Benefit Flow Thru                                         ($10,758)                ($13,447)                ($235,379)               ($235,660)                ($235,731)
          7         Annual Revenue Requirement
          9 Electric Total
         10       Year-end Rate Base
         11       Return and Taxes                                                 $702,865                $2,264,691                $8,565,364              $10,104,066                $8,815,563
         12       Operating Expenses
         13       Book Depreciation                                                  $17,241                  $43,604                $3,042,273               $9,386,195               $10,202,921
         14       Property Taxes                                                     $26,800                  $26,800                   $26,800                 $202,770                $3,315,222
         15       COR Tax Benefit Flow Thru                                         ($10,758)                ($13,447)                ($225,096)               ($225,376)                ($225,424)
         16         Annual Revenue Requirement
         18 Gas Total
         19       Year-end Rate Base                                               $150,654                $4,379,641              $10,497,502                $9,426,116                $7,770,984
         20       Return and Taxes                                                  $16,105                  $180,236                 $920,607                $1,064,879                  $897,744
         21       Operating Expenses
         22       Book Depreciation                                                         $0                        $0               $411,680                  $996,097               $1,030,954
         23       Property Taxes                                                            $0                        $0                     $0                        $0                 $218,911
         24       COR Tax Benefit Flow Thru                                                 $0                        $0               ($10,283)                 ($10,284)                ($10,308)
         25         Annual Revenue Requirement

            Line   Source                                                                                          Line    Source
              1    Line 10 + Line 19                                                                                14     Sum of Pages 3, 6, 8 and 9, Line 5 for the respective year
              2    Line 11 + Line 20                                                                                15     Sum of Pages 3, 6, 8 and 9, Line 6 for the respective year
              3    Line 12 + Line 21                                                                                16     Sum of Lines 11 - 15
              4    Line 13 + Line 22                                                                                19     Sum of Pages 4 and 7, Line 1 for the respective year
              5    Line 14 + Line 23                                                                                20     Sum of Pages 4 and 7, Line 2 for the respective year
              6    Line 15 + Line 24                                                                                21     Sum of Pages 4 and 7, Line 3 for the respective year
              7    Sum of Lines 2 - 6                                                                               22     Sum of Pages 4 and 7, Line 4 for the respective year
             10    Sum of Pages 3, 6, 8 and 9, Line 1 for the respective year                                       23     Sum of Pages 4 and 7, Line 5 for the respective year
             11    Sum of Pages 3, 6, 8 and 9, Line 2 for the respective year                                       24     Sum of Pages 4 and 7, Line 6 for the respective year
             12    Sum of Pages 3, 6, 8 and 9, Line 3 for the respective year                                       25     Sum of Lines 19 - 24
             13    Sum of Pages 3, 6, 8 and 9, Line 4 for the respective year

1 of 1                         07/02/2009 3:55 PM C:\Documents and Settings\bonner\Desktop\09-E-0310 EconStimulus 20090417\Source 20090702\temp\ NY Smart Grid Project Total Rev Req Proposal - Spine & Module Summary DRAFT III.xls Smart Grid Total Program #2

                                                                                                                              Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                                                                  Case 09-E-0310
                                                                                                                                          Updated Stimulus Proposal – July 2, 2009
                                                                                                                                                                         Exhibit 7
                                                                                                                                                                       Page 2 of 9

                                                     Niagara Mohawk d/b/a National Grid
                                                          Technology Solution (Spine)
                                          Summary - Total E&G Estimated Annual Revenue Requirement

                                                                 Year 1                      Year 2                      Year 3                     Year 4                     Year 5
    Annual Incremental Rate Adjustments

1          Year-end Rate Base
2          Return and Taxes                                           $183,497                 $1,362,608                 $5,426,393                  $6,864,045                 $6,336,017
3          Operating Expenses
4          Book Depreciation                                                   $0                         $0              $2,608,052                  $5,582,647                 $5,850,665
5          Property Taxes                                                      $0                         $0                      $0                          $0                 $1,909,279
6          COR Tax Benefit Flow Thru                                           $0                         $0               ($221,932)                  ($222,213)                 ($222,284)
7            Annual Revenue Requirement

    Line   Source
      1    Page 3, Line 1 + Page 4, Line 1, for the respective year
      2    Page 3, Line 2 + Page 4, Line 2, for the respective year
      3    Page 3, Line 3 + Page 4, Line 3, for the respective year
      4    Page 3, Line 4 + Page 4, Line 4, for the respective year
      5    Page 3, Line 5 + Page 4, Line 5, for the respective year
      6    Page 3, Line 6 + Page 4, Line 6, for the respective year
      7    Sum of Lines 2 - 6

                                                 C:\Documents and Settings\bonner\Desktop\09-E-0310 EconStimulus 20090417\Source 20090702\temp\NY Smart Grid Project Rev Req Proposal - Spine DRAFT II.xls

                                                                                                                        Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                                                            Case 09-E-0310
                                                                                                                                    Updated Stimulus Proposal – July 2, 2009
                                                                                                                                                                   Exhibit 7
                                                                                                                                                                 Page 3 of 9

                                                  Niagara Mohawk d/b/a National Grid
                                                      Technology Solution (Spine)
                                        Summary - Electric Estimated Annual Revenue Requirement

                                                           Year 1                      Year 2                      Year 3                     Year 4                     Year 5
    Annual Incremental Rate Adjustments

1        Year-end Rate Base
2        Return and Taxes                                       $167,392                 $1,182,372                 $4,605,447                  $5,905,638                 $5,529,857
3        Operating Expenses
4        Book Depreciation                                               $0                         $0              $2,201,053                  $4,698,896                 $4,932,057
5        Property Taxes                                                  $0                         $0                      $0                          $0                 $1,752,231
6        COR Tax Benefit Flow Thru                                       $0                         $0               ($211,649)                  ($211,929)                 ($211,976)
7          Annual Revenue Requirement

                                           C:\Documents and Settings\bonner\Desktop\09-E-0310 EconStimulus 20090417\Source 20090702\temp\NY Smart Grid Project Rev Req Proposal - Spine DRAFT II.xls

                                                                                                                       Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                                                           Case 09-E-0310
                                                                                                                                   Updated Stimulus Proposal – July 2, 2009
                                                                                                                                                                  Exhibit 7
                                                                                                                                                                Page 4 of 9

                                               Niagara Mohawk d/b/a National Grid
                                                    Technology Solution (Spine)
                                        Summary - Gas Estimated Annual Revenue Requirement

                                                          Year 1                      Year 2                      Year 3                     Year 4                     Year 5
    Annual Incremental Rate Adjustments

1        Year-end Rate Base
2        Return and Taxes                                        $16,105                  $180,236                    $820,946                   $958,407                    $806,161
3        Operating Expenses
4        Book Depreciation                                              $0                         $0                 $406,999                   $883,751                    $918,607
5        Property Taxes                                                 $0                         $0                       $0                         $0                    $157,048
6        COR Tax Benefit Flow Thru                                      $0                         $0                 ($10,283)                  ($10,284)                   ($10,308)
7          Annual Revenue Requirement

                                          C:\Documents and Settings\bonner\Desktop\09-E-0310 EconStimulus 20090417\Source 20090702\temp\NY Smart Grid Project Rev Req Proposal - Spine DRAFT II.xls

                                                                                                                              Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                                                                  Case 09-E-0310
                                                                                                                                          Updated Stimulus Proposal – July 2, 2009
                                                                                                                                                                         Exhibit 7
                                                                                                                                                                       Page 5 of 9

                                                     Niagara Mohawk d/b/a National Grid
                                                               Green Modules
                                          Summary - Total E&G Estimated Annual Revenue Requirement

                                                                 Year 1                      Year 2                      Year 3                     Year 4                      Year 5
    Annual Incremental Rate Adjustments

1          Year-end Rate Base                                                  $0                          $0
2          Return and Taxes                                                    $0                          $0              $3,021,483                 $3,094,701                 $2,532,064
3          Operating Expenses                                                  $0                          $0
4          Book Depreciation                                                   $0                          $0                $163,748                 $3,929,950                 $3,929,950
5          Property Taxes                                                      $0                          $0                      $0                         $0                 $1,422,084
6          COR Tax Benefit Flow Thru                                           $0                          $0                      $0                         $0                         $0
7            Annual Revenue Requirement                                        $0                          $0

    Line   Source
      1    Page 6, Line 1 + Page 7, Line 1, for the respective year
      2    Page 6, Line 2 + Page 7, Line 2, for the respective year
      3    Page 6, Line 3 + Page 7, Line 3, for the respective year
      4    Page 6, Line 4 + Page 7, Line 4, for the respective year
      5    Page 6, Line 5 + Page 7, Line 5, for the respective year
      6    Page 6, Line 6 + Page 7, Line 6, for the respective year
      7    Sum of Lines 2 - 6

                                               C:\Documents and Settings\bonner\Desktop\09-E-0310 EconStimulus 20090417\Source 20090702\temp\NY Smart Grid Project Rev Req Proposal - Modules DRAFT II.xls

                                                                                                                         Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                                                             Case 09-E-0310
                                                                                                                                     Updated Stimulus Proposal – July 2, 2009
                                                                                                                                                                    Exhibit 7
                                                                                                                                                                  Page 6 of 9

                                                  Niagara Mohawk d/b/a National Grid
                                                             Green Modules
                                        Summary - Electric Estimated Annual Revenue Requirement

                                                            Year 1                      Year 2                      Year 3                     Year 4                      Year 5
    Annual Incremental Rate Adjustments

1        Year-end Rate Base                                               $0                          $0
2        Return and Taxes                                                 $0                          $0              $2,921,822                 $2,988,229                 $2,440,480
3        Operating Expenses                                               $0                          $0
4        Book Depreciation                                                $0                          $0                $159,067                 $3,817,603                 $3,817,603
5        Property Taxes                                                   $0                          $0                      $0                         $0                 $1,360,221
6        COR Tax Benefit Flow Thru                                        $0                          $0                      $0                         $0                         $0
7          Annual Revenue Requirement                                     $0                          $0

                                          C:\Documents and Settings\bonner\Desktop\09-E-0310 EconStimulus 20090417\Source 20090702\temp\NY Smart Grid Project Rev Req Proposal - Modules DRAFT II.xls

                                                                                                                         Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                                                             Case 09-E-0310
                                                                                                                                     Updated Stimulus Proposal – July 2, 2009
                                                                                                                                                                    Exhibit 7
                                                                                                                                                                  Page 7 of 9

                                               Niagara Mohawk d/b/a National Grid
                                                          Green Modules
                                        Summary - Gas Estimated Annual Revenue Requirement

                                                            Year 1                      Year 2                      Year 3                     Year 4                      Year 5
    Annual Incremental Rate Adjustments

1        Year-end Rate Base                                               $0                          $0
2        Return and Taxes                                                 $0                          $0                  $99,661                  $106,472                     $91,583
3        Operating Expenses                                               $0                          $0
4        Book Depreciation                                                $0                          $0                   $4,681                  $112,347                    $112,347
5        Property Taxes                                                   $0                          $0                       $0                        $0                     $61,863
6        COR Tax Benefit Flow Thru                                        $0                          $0                       $0                        $0                          $0
7          Annual Revenue Requirement                                     $0                          $0

                                          C:\Documents and Settings\bonner\Desktop\09-E-0310 EconStimulus 20090417\Source 20090702\temp\NY Smart Grid Project Rev Req Proposal - Modules DRAFT II.xls

                                                                                                                           Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                                                               Case 09-E-0310
                                                                                                                                       Updated Stimulus Proposal – July 2, 2009
                                                                                                                                                                      Exhibit 7
                                                                                                                                                                    Page 8 of 9

                                              Niagara Mohawk d/b/a National Grid
                                                       Distribution Projects
                                  Summary - Total Electric Estimated Annual Revenue Requirement

                                                             Year 1                       Year 2                      Year 3                     Year 4                      Year 5
    Annual Incremental Rate Adjustments

1        Year-end Rate Base
2        Return and Taxes                                         $404,620                    $955,494                    $915,975                 $1,092,544                    $731,811
3        Operating Expenses
4        Book Depreciation                                               $0                     $26,362                   $664,912                    $852,454                 $1,436,019
5        Property Taxes                                                  $0                          $0                         $0                    $175,970                   $175,970
6        COR Tax Benefit Flow Thru                                 ($10,758)                   ($13,447)                  ($13,447)                   ($13,447)                  ($13,447)
7          Annual Revenue Requirement

                                        C:\Documents and Settings\bonner\Desktop\09-E-0310 EconStimulus 20090417\Source 20090702\temp\NY Smart Grid Project Rev Req Proposal - Distribution DRAFT II.xls

                                                                                                                                         Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                                                                             Case 09-E-0310
                                                                                                                                                     Updated Stimulus Proposal – July 2, 2009
                                                                                                                                                                                    Exhibit 7
                                                                                                                                                                                  Page 9 of 9

                                                           Niagara Mohawk d/b/a National Grid
                                                                 Phasor Measurement Units
                                               Summary - Total Electric Estimated Annual Revenue Requirement

                                                                          Year 1                   Year 2                  Year 3                 Year 4                  Year 5
             Annual Incremental Rate Adjustments

         1       Year-end Rate Base
         2       Return and Taxes                                             $130,853                $126,826                $122,120               $117,656                $113,415
         3       Operating Expenses
         4       Book Depreciation                                             $17,241                 $17,241                 $17,241                 $17,241                 $17,241
         5       Property Taxes                                                $26,800                 $26,800                 $26,800                 $26,800                 $26,800
         6       COR Tax Benefit Flow Thru
         7         Annual Revenue Requirement

1 of 1            07/02/2009 3:53 PM C:\Documents and Settings\bonner\Desktop\09-E-0310 EconStimulus 20090417\Source 20090702\temp\NY Smart Grid Project Rev Req Proposal - PMU DRAFT II.xls Filing sheet Final
NY Smart Program
                                                         Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                                              Case 09‐E‐0310 
                                                                           New York Smart Program Proposal 
                                                                                                 Page 1 of 98 
Table of Contents 

I.       EXECUTIVE SUMMARY ................................................................................................... 4 
      A.  BACKGROUND ............................................................................................................... 5 
      B.  SMART PROGRAM RATIONAL ............................................................................................ 7 
         i.  Electricity Advisory Committee (EAC) ..................................................................... 8 
         ii.  New York Green Energy Vision ............................................................................... 9 
         iii.  Energy Independence and Security Act (EISA) 2007 .............................................. 10 
         iv.  FERC‐NARUC Smart Grid Collaborative ................................................................. 11 
         v.  FERC Smart Grid Policy Statement and Action Plan............................................... 12 
      C.  PROGRAM OBJECTIVES .................................................................................................. 13 
      D.  SMART GRID SECURITY .................................................................................................. 16 
      E.  PROGRAM APPROACH ................................................................................................... 18 
      F.  CUSTOMER ASPECTS ..................................................................................................... 19 
      G.  UTILITY ASPECTS .......................................................................................................... 21 
      H.  TECHNICAL AND FUNCTIONAL GUIDING PRINCIPLES ............................................................. 22 
      I.  SMART GRID FUNCTIONAL STRATEGY ............................................................................... 23 
      J.  PROGRAM SCALE ......................................................................................................... 25 
      K.  PROPOSED PROGRAM SITES ........................................................................................... 26 
      L.  SITE CHARACTERISTICS .................................................................................................. 28 
      M.  PROGRAM COST .......................................................................................................... 29 
      N.  AMERICAN RECOVERY AND REINVESTMENT ACT OF 2009 (ARRA) ......................................... 32 
II.  CUSTOMER AND STAKEHOLDER EXPERIENCE ............................................................... 33 
      A.  SERVICE LEVELS............................................................................................................ 35 
         i.  Level One. ............................................................................................................ 35 
         ii.  Level Two............................................................................................................. 35 
         iii.  Level Three........................................................................................................... 36 
      B.  MARKETING PLAN ........................................................................................................ 36 
      C.  COMMUNITY OUTREACH ............................................................................................... 39 
      D.  CUSTOMER SERVICE ...................................................................................................... 39 
      E.  BILLING ...................................................................................................................... 40 
III.  SMART GRID TECHNOLOGY SOLUTION......................................................................... 41 
      A.  SMART GRID ‐ GUIDING PRINCIPLES ................................................................................. 41 
         i.  Scalability and Flexibility ...................................................................................... 44 
         ii.  Leveraging Existing Systems ................................................................................. 44 
         iii.  Future Outlook..................................................................................................... 44 
      B.  SMART GRID ‐ REQUEST FOR INFORMATION ............................................................ 45 
                                                   Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                                                                 Case 09‐E‐0310 
                                                                                    New York Smart Program Proposal 
                                                                                                                      Page 2 of 98 
   C.  SMART GRID ‐ TECHNOLOGY SOLUTION ................................................................... 45 
       i.  Communications Technology................................................................................ 46 
       ii.  Smart Metering.................................................................................................... 49 
       iii.  In‐Home Energy Management.............................................................................. 49 
       iv.  Grid Monitoring and Automation Technology ...................................................... 51 
   D.  SMART GRID – CLEAN ENERGY MODULES .......................................................................... 53 
       i.  Photovoltaics (PV) Smart Grid Module – Scoping Description ............................... 53 
       ii.  PHEV/EV Smart Grid Module – Scoping Description.............................................. 56 
       iii.  Energy Storage Smart Grid Module – Scoping Description .................................... 59 
       iv.  Wind Power Smart Grid Module – Scoping Description ........................................ 60 
       v.  Micro Combined Heat and Power (micro‐CHP) Module – Scoping Description ...... 62 
       vi.  Microgrid Smart Grid Module – Scoping Description ............................................ 64 
       vii.  Holistic Homes Module – Scoping Description ...................................................... 66 
   E.  SMART GRID ‐ INFORMATION SYSTEM SOLUTION..................................................... 70 
   I.      NEW APPLICATIONS ...................................................................................................... 71 
   II.  EXISTING APPLICATIONS ................................................................................................ 72 
   III.  DATA IMPACTS ............................................................................................................ 72 
   IV.  INTEGRATION .............................................................................................................. 72 
   V.  HARDWARE AND SOFTWARE SPECIFICATIONS ..................................................................... 73 
   VI.  SECURITY.................................................................................................................... 73 

IV.  SMART GRID FINANCIALS............................................................................................. 74 
   A.  COST‐BENEFIT ANALYSIS STRATEGY.................................................................................. 75 
   B.  FINANCIAL MODELING APPROACH ................................................................................... 76 
   C.  FULL DEPLOYMENT COST‐BENEFITS .................................................................................. 76 
V.  DEPLOYMENT PLAN ..................................................................................................... 77 
   A.  PROJECT PLANNING ...................................................................................................... 77 
   B.  DEPLOYMENT TIMELINE ................................................................................................. 78 
   C.  DESCRIPTION OF RELEASE PHASES .................................................................................... 82 
      i.  Proof of Concept .................................................................................................. 82 
      ii.  Release One ......................................................................................................... 82 
      iii.  Release Two......................................................................................................... 83 
      iv.  Release Three....................................................................................................... 84 
   D.  SUMMARY .................................................................................................................. 84 
VI.  CONTINGENCY PLAN.................................................................................................... 84 
VII.  SMART GRID PRICING .................................................................................................. 86 
   A.  INTRODUCTION ............................................................................................................ 86 
                                           Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                                                          Case 09‐E‐0310 
                                                                             New York Smart Program Proposal 
                                                                                                               Page 3 of 98 
B.  ELIGIBILITY FOR SMART GRID PRICING .............................................................................. 87 
C.  TARIFF PROVISIONS ...................................................................................................... 88 
D.  RATE PROVISIONS AND DESIGN ....................................................................................... 89 
   i.  Critical Peak Pricing Program................................................................................ 89 
   ii.  Illustrative Rates .................................................................................................. 94 
E.  RECONCILIATION OF SMART GRID PRICING ........................................................................ 94 
                                    Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                         Case 09‐E‐0310 
                                                      New York Smart Program Proposal 
                                                                            Page 4 of 98 

        Niagara Mohawk Power Corporation d/b/a National Grid (National Grid or the 
Company) believes that the U.S. electricity industry will face significant change over 
the coming years.  There will be a shift from a model in which electricity is generated 
and controlled centrally, to one in which energy is more dispersed and integrated at a 
local level taking advantage of renewable energy sources.  Additionally, environmental 
awareness and rising prices will require the energy industry to become increasingly 
responsive to the need for more timely energy usage and pricing information, more 
tailored energy options, and greater individual customer control.   
        National Grid recognizes the transformation to a new carbon economy will 
require significant investment in the energy delivery infrastructure as well as utilization 
and control technologies that will enable value creation. Federal Smart Grid matching 
funds opportunities have been designed as a "pump primer" for Smart Grid 
investments for progressive utilities and states.  National Grid proposes to take 
advantage of this opportunity in partnership with New York such that a large 
proportion of the $271 million first phase of deployment can be achieved with these 
matching funds to the benefit of New York State and the Company’s ratepayers.  This 
shared investment provides a unique opportunity to advance our Smart Grid Vision.    

         National Grid’s vision is to deploy Smart Grid technology in order to optimize 
the flow of green energy resources, enhance the performance of the electric 
transmission and distribution grid, and provide customers with the ability to make 
informed decisions about how they use energy.  
         A Smart Grid will be the fundamental service platform for future years. It will 
help towards reducing energy consumption and greenhouse gas emissions.  A Smart 
Grid will drive optimization; improve utilization and efficiencies and enhance the 
reliability of National Grid’s transmission and distribution infrastructure. 
         This service platform will provide and act as a catalyst for current green 
technologies (e.g., wind, energy efficiency, demand response) and the emerging next 
generation of green technologies (e.g., photovoltaic, energy storage, plug‐in hybrid 
electric vehicles) that National Grid believes are essential to meet societal and 
customers’ future needs.  
                                                Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                                     Case 09‐E‐0310 
                                                                  New York Smart Program Proposal 
                                                                                        Page 5 of 98 
             A Smart Grid will provide customers with choice over how the electricity they 
use is generated and control over how and when they use energy in their homes and 
businesses.  Through this redefined relationship with National Grid, customers will be 
able to participate in the power of action and contribute to a sustainable future.    
A.           Background 
             The State of New York Department of Public Service (DPS) letter dated April 2, 
2009, “Re: U.S. Department of Energy – Electricity Delivery and Energy Reliability 
Program’, instructed utilities planning to apply to the DOE under the Electric Delivery 
and Energy Reliability (EDER) program in the American Recovery and Reinvestment Act 
of 2009 (ARRA) to file their plans with the Secretary to the Commission as soon as 
practicable due to the added advantage applicants may have by securing non‐federal 
funding sources.  The letter requested that this filing should include a list of all projects 
under consideration that require funding by ratepayers, in a summary format, in 
priority order using the spreadsheet format that has been used to facilitate discussions 
about potential projects.   
             On April 17, 2009, National Grid complied with the DPS directive by providing 
descriptions of nine projects that the Company could pursue with ARRA funding (the 
April 17 Proposal).  These projects included an approximately                                         million investment 
in Smart Grid technologies, covering over 81,000 customers in the Syracuse and Albany 
             Since making the April 17 Proposal, National Grid has met or spoken with Staff 
on numerous occasions to discuss the proposed projects described therein.  In a letter 
from Staff dated May 26, 2009, DPS directed New York utilities to update their ARRA 
filings by June 22 2009 as needed to reflect changes resulting from the anticipated 
issuance by the DOE of the Final Funding Opportunity Announcement (FOA) for ARRA 
funds.  On June 19, 2009, DPS extended the filing date for such updates to within three 
business days of the issuance of the FOA.  Following the issuance by the DOE of the 
final FOA on June 25, 2009, DPS set July 2, 2009 as the date for filing updated ARRA 
plans.  In response, the Company is providing this updated filing (this Filing) to replace 
the April 17, 2009 Proposal. 
             One key change from the April 17 Proposal is the title of the program.  The 
original filing was referred to as a Demonstration Program.  Since the ARRA funding 
includes a category referred to as a Smart Grid Demonstration, we consider the use of 
this term to describe our entire program as potentially confusing.  Accordingly, 
                                    Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                         Case 09‐E‐0310 
                                                      New York Smart Program Proposal 
                                                                            Page 6 of 98 
National Grid’s program will now be referred to as the “New York Smart Program” 
(Smart Program).   The table below lists the Smart Programs that the Company is 
proposing in this Filing.  

        SMART GRID 
Site       Customers  Components                                          Jobs     Cost 

                          Meters, WAN, LAN, HAN, DA 

NY Smart                  PV, Energy Storage, PHEV/EV, Wind, Micro‐       300‐
Grid      81,821          CHP, Holistic Homes, Micro‐Grid                 500 


         The April 2, 2009 DPS letter advised that such filings with the Secretary should 
provide to the Commission all known and relevant detail regarding the projects that 
the utility may include in its DOE applications for the EDER program.  The May 26, 2009 
letter requested updates.  The following details were suggested as relevant in both 
         1.  The rationale/justification for the project, given all known and anticipated 
criteria for project selection, including but not limited to the FERC‐NARUC smart grid 
criteria, the smart grid criteria from the Energy Independence and Security Act of 2007 
(EISA) (Title XIII, Sec. 1301), and the smart grid criteria of the policy statement from 
the Federal Energy Regulatory Commission (FERC) or the industry standard for smart 
grid).; and 
         2.  A detailed project description, including location, equipment list, and 
associated supporting facilities; 
         3.  A project milestone schedule, including an assessment of the readiness for 
undertaking the project and when any construction could begin; 
         4.  Detailed cost estimates, including a breakdown for various phases where 
         5.  The number of jobs created by the project; 
         6.  A statement as to the availability of EDER funds, any non‐ratepayer, non‐
federal funds that may be applied, an estimate of the net costs that must be recovered 
from ratepayers, and a proposed method for recovering those costs.  
         It is important to note that since collectively National Grid and National Grid 
affiliates operate in four states, National Grid affiliates have either filed or expect to 
                                                               Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                                                    Case 09‐E‐0310 
                                                                                 New York Smart Program Proposal 
                                                                                                       Page 7 of 98 
soon file Smart Program proposals in Massachusetts and Rhode Island.  The Smart 
Program, which we propose here, is part of a larger effort to analyze all aspects of the 
intelligent grid including those clean energy components such as renewables, storage, 
PHEV/EV, and micro‐grids that together represent what the Company believes will be 
the energy environment of the future.  In each Program, we have attempted to include 
sufficient scale to ensure that we learn the appropriate lessons so that we can quickly 
expand to a wider segment of our customers.   
B.       Smart Program Rational 
         National Grid is proposing the New York Smart Program (Smart Program), 
because we believe the Smart Grid and the addition of clean energy technologies to 
make a “Green Grid” represent the future of the energy industry.  While we may be 
one of the first utilities to propose this type of program, ours is a shared vision.  Our 
approach is consistent with the vision developed within the Office of EDER by the 
Electric Advisory Committee (EAC), which describes the Smart Grid as an enabler of the 
new energy economy.1  Our vision and our proposed Smart Program are consistent 
with the New York vision of the Smart Grid as a catalyst of a green energy future.2  We 
understand and are aligned with the Smart Grid guiding principles articulated in the 
EISA 2007 legislation3 and our approach is consistent with DOE ARRA funding 
guidelines4  and recommended guidelines by the FERC‐NARUC Smart Grid 
Collaborative.5  The Company’s approach to security and standards is consistent with 
the recently released FERC Smart Grid Policy Statement.6  We recognize that digitizing 
the electric grid and adding millions of new control points along that grid will require a 
robust and ongoing focus on security.  We will rapidly create smart and green jobs for 
small and medium size companies as part of the Smart Program that may well result in 
significant new long‐term job creation as we move from the roll out  phase to full 
deployment.  What follows is a brief description of the principles and/or guidelines 
                                   Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                        Case 09‐E‐0310 
                                                     New York Smart Program Proposal 
                                                                           Page 8 of 98 
from each of these organizations that collectively informs and influences our proposed 
Smart Program.   
       i. Electricity Advisory Committee (EAC) 
           The EAC is part of the DOE Office of Electricity Delivery and Energy 
       Reliability.  Their mission is to provide advice to the U.S. Department of Energy 
       in implementing the Energy Policy Act of 2005, executing the Energy 
       Independence and Security Act of 2007, and modernizing the nation's 
       electricity delivery infrastructure.  National Grid is a member of the Committee 
       and the Smart Grid Subcommittee.  In this capacity, we participated in 
       development of the December 2008 report, “Smart Grid: The Enabler of the 
       New Energy Economy”.    
           National Grid believes the EAC Smart Grid Report is a complete vision of 
       why a Smart Grid is an enabler of the Green Grid and the new energy economy.  
       As they suggest, “studies have shown that the potential economic and 
       environmental payoffs of transforming the current electric power delivery 
       system into a Smart Grid are numerous. From an economic perspective, a Smart 
       Grid can enable reduced overall energy consumption through consumer 
       education and participation in energy efficiency and demand response / load 
       management programs. Shifting electricity usage to less expensive off‐peak 
       hours can allow for better utilization of equipment and better use of capacity. 
       From an environmental standpoint, a Smart Grid can reduce carbon emissions 
       by maximizing demand response / load management, minimizing use of peak 
       generation, and replacing traditional forms of generation with renewable 
       sources of generation. A Smart Grid also holds the promise of enhanced 
       reliability and security of the nation’s power system.”   
           National Grid believes the Commission recognizes the challenges that must 
       be addressed to enable the Smart Grid and the potential of the Green Grid.  
       The Smart Program that we propose is designed to address these smart grid 
       challenges while including sufficient Green Grid components to determine 
       exactly how all of the pieces will work together from a business, technical and 
       regulatory perspective.  As the EAC report suggests, “the challenges faced by 
       the energy sector emanate from transitioning an existing and operational 
       energy model toward a Smart Grid. These challenges include increasing 
                               Niagara Mohawk Power Corporation d/b/a National Grid 
                                                                    Case 09‐E‐0310 
                                                 New York Smart Program Proposal 
                                                                       Page 9 of 98 
    customer awareness and participation, allocating costs appropriately and fairly 
    among stakeholders, developing and executing business case models, 
    identifying and implementing best practices and standards throughout the 
    industry, and establishing a coordinated strategy that capitalizes on using 
    smarter technology to evolve to a Smart Grid.” 
        National Grid’s vision is to use the lessons learned during the Smart 
    Program to answer many of these questions and in the process, develop a 
    strategy for a full deployment of Smart and Green.  
    ii. New York Green Energy Vision 
        New York State is conducting an extensive review of the current and future 
    energy market for the state and will publish its final report in October 2009.  
    Progress to date has been significant and an initial report was made available 
    on March 31, 2009.  This initial report outlines findings and provides market 
    participants with the strategic vision and priorities for New York.  Governor 
    Paterson has called for 45% of the State’s electricity needs to be met through 
    improved energy efficiency and green renewable energy by the year 2015.  This 
    aggressive plan expands upon the existing programs and will act as a catalyst 
    for developing the New York green energy industries. 
       National Grid believes the vision of the leadership team in New York is to 
    create an energy infrastructure that enables a new market evolution.  Specific 
    aspects of that vision include:  
    o Security of supply through a diversity of green technology electricity 
       generation and sophisticated customer behaviors cognizant of cost and 
       carbon impacts. 
    o  A catalyst to new transportation choices, Plug‐in Hybrid Electric Vehicles 
       that challenge the reliance on gasoline and its associated 36% of carbon 
       dioxide make up of New York pollution.   
    o Further growth in New York of energy efficiency and sustainability.  
    o Economic development in the competitiveness of attracting industry to 
       New York in general and the specific jobs and skills created for the New 
       York workforce who would provide the Smart Grid components, construct, 
       operate and maintain the Smart Grid.    
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            o Customers with choice and control over how and when they utilize energy 
              to their best advantage both from a cost and carbon perspective. 
            The Smart Program will enable National Grid to demonstrate in action both the 
            Smart and the Green aspects of the New York Green Energy Vision. 
            iii. Energy Independence and Security Act (EISA) 2007 
                 This legislation was an update and expansion of the Energy Policy Act of 
            2005.  While it contains many specifics related to the Smart Grid, until the 
            passage of the ARRA, there was little actual funding for the Smart Grid 
            initiatives.  The Smart Grid Section of the legislation included the following 
            statement of policy: 
                It is the policy of the United States to support the modernization of the 
            Nation’s electricity transmission and distribution system to maintain a reliable 
            and secure electricity infrastructure that can meet future demand growth and 
            to achieve each of the following, which together characterize a Smart Grid: 
                1. Increased use of digital information and controls technology to improve 
                     reliability, security, and efficiency of the electric grid.  
                2. Dynamic optimization of grid operations and resources, with full cyber‐
                3. Deployment and integration of distributed resources and generation, 
                     including renewable resources. 
                4. Development and incorporation of demand response, demand‐side 
                     resources, and energy efficiency resources. 
                5. Deployment of ‘‘smart’’ technologies (real‐time, automated, interactive 
                     technologies that optimize the physical operation of appliances and 
                     consumer devices) for metering, communications concerning grid 
                     operations and status, and distribution automation. 
                6. Integration of ‘‘smart’’ appliances and consumer devices. 
                7. Deployment and integration of advanced electricity storage and peak‐
                     shaving technologies, including plug‐in electric and hybrid electric 
                     vehicles, and thermal‐storage air conditioning. 
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       8. Provision to consumers of timely information and control options. 
       9. Development of standards for communication and interoperability of 
           appliances and equipment connected to the electric grid, including the 
           infrastructure serving the grid. 
       10. Identification and lowering of unreasonable or unnecessary barriers 
         As this filing will demonstrate, the Company’s approach includes the 
    functionality outlined in the first eight items above, while being mindful of the 
    developing standards listed in Item 9.  With regard to Item 10, our expectation 
    is that the Smart Program will allow National Grid to understand what works 
    and what does not, and allow us to expose potential barriers preventing the 
    development of the Smart Grid.     
    iv. FERC‐NARUC Smart Grid Collaborative 
        The FERC‐NARUC Smart Grid Collaborative (the Collaborative) was formed 
    in March 2008 as a forum for a collective education of regulators (state and 
    federal) on Smart Grid technology and a forum for developing a consistent 
    approach to Smart Grid costs and benefits.  While it is too early in the process 
    for the Collaborative to develop a Smart Grid policy guideline, they did issue a 
    set of recommendations to DOE regarding Smart Grid Program Funding under 
    the EDER section of ARRA.  The proposed Funding Criteria was consistent with 
    the guidelines issued by DOE and focused on the following areas: 
        o Interoperability 
        o Security 
        o Standards 
        o Minimizing Stranded Investment 
        o Information Sharing 
        o Grid Reliability 
        In addition to these specific funding criteria, the Collaborative provided an 
    extensive list of what they call Overarching Criteria.  We have included the list 
    below and the Company’s filing will demonstrate our compliance with each.  
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                      o      Grid‐wide Projects (transmission, distribution and in‐home) 
                      o      Variety of Technologies  
                      o      Broad Reaching Projects with Broad Application 
                      o      Statistically Valid Scale 
                      o      Geographic and Demographic Diversity 
                      o      Customer and System Benefits 
              v. FERC Smart Grid Policy Statement and Action Plan 
                  EISA 2007 requires FERC to adopt interoperability standards and protocols 
              necessary to ensure Smart Grid functionality and interoperability in the 
              interstate transmission of electric power and in regional and wholesale 
              electricity markets.  The introduction of two‐way communications and millions 
              of new control points along the Smart Grid creates a potential Critical 
              Infrastructure Security issue requiring greater FERC involvement and potential 
              oversight beyond the bulk transmission system.  
                  FERC issued a Policy Statement on March 19, 20097 requesting comments 
              on their plan to prioritize the development of key interoperability standards, 
              provide guidance to the electric industry regarding the need for full cyber 
              security for Smart Grid projects, and provide an interim rate policy under which 
              jurisdictional public utilities may seek to recover the costs of Smart Grid 
              deployments before relevant standards are adopted through a Commission 
              rulemaking.  The following is a summary of the key areas of consideration: 
                o Cyber‐security ‐ Advise National Institute of Standards and Technology 
                     (NIST) to assure each standard and protocol is consistent with the 
                     overarching cyber security and reliability requirements of EISA and FERC 
                     Reliability Standards. 
                o Inter‐System Communications ‐ Identify standards for common 
                     information models for communication among all elements of the bulk 
                     power system – regional market operators, utilities, demand response 
                     aggregators and customers. 

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                   o Wide‐Area Situational Awareness ‐ Ensure that operators of the nation’s 
                     bulk power system have the equipment that gives them a complete view 
                     of their systems so they can monitor and operate their systems. 
                   o Coordination of the bulk power systems with new and emerging 
                     technologies ‐ Identify standards development that would help 
                     accommodate the introduction and expansion of renewable resources, 
                     demand response and electricity storage to help address several bulk 
                     power system challenges.  Also identify standards development that 
                     could help accommodate another emerging technology, electric 
              National Grid will continue to monitor the efforts of FERC and ensure that our 
              selected technologies and our business processes are consistent with standards 
              where they exist and we are fully engaged in the standards development 
              process where existing standards must be updated or where new standards are 
              We will also follow FERC guidelines for avoiding stranded Smart Grid 
              investments by attempting to adhere to the principles of the Gridwise 
              Architecture Council Decision‐Maker’s Interoperability Checklist8 and by 
              adherence to the following principles: (1) reliance to the greatest extent 
              practical on existing, widely adopted and open interoperability standards; and 
              (2) where feasible, reliance on systems and firmware that can be securely 
              upgraded readily and quickly.  Adherence to these two key principles should 
              minimize the possibility of stranded smart grid investment by making it less 
              likely that equipment replacement will be required once final standards are 
C.            Program Objectives 
      The Smart Program is designed to demonstrate that a large scale Smart Grid 
deployment may provide significant benefits to customers and society by enabling 
8 (Interoperability Checklist). 

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more efficient energy consumption that results in reduced energy usage, better energy 
quality, improved reliability, and a general reduction in the carbon emissions required 
to produce and deliver electricity to customers.  Additionally, we hope to demonstrate 
in action how significant Green enabling technologies can be included, such as large 
scale energy storage, PV, PHEV/EV and selected Micro‐Grids and Micro‐CHPs.  The 
development and execution of the envisioned Smart Grid and the Smart Program will 
be a collaborative effort between National Grid, the leadership of New York State, 
customers, and market participants.  National Grid hopes that each will participate 
fully to reach the goals envisioned and we will be able to demonstrate in action the 
opportunity and value of Smart Grid. 
The Smart Program is designed to accomplish the following:  
         1.     Demonstrate how large scale regulated investments in Smart Grid 
                infrastructure can deliver significant benefits to customers and society. 
                    • Customer benefit will be measured by a reduction in load and 
                        associated cost, improvement in power quality and reliability. 
                    • Societal benefits are measured in reduction in load and 
                        associated carbon reduction.  
         2.     Demonstrate how customer energy consumption and peak demand can 
                be consistently and significantly reduced through the implementation of 
                technologies that provide timely energy usage information, diverse rate 
                plans, and automation to incent and enable customers to reduce load 
                or otherwise alter their consumption patterns. 
                    • Establish a baseline usage for the deployment area and then use 
                        control sets of customers with differing solution sets to 
                        determine the effectiveness of each approach. 
         3.     Demonstrate how electric distribution grid operating efficiency can be 
                improved measurably by improved monitoring and control available 
                through a new distribution monitoring system using the smart endpoint 
                    • This benefit is measured in terms of potential future reductions 
                        in line losses.  
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4.   Demonstrate how opportunities to optimize transmission network 
     performance through enhanced distribution network information and 
     control, and changes to customer behavior. 
         • This benefit is measured through reductions in critical peak 
             loads with the combination of technology and rate mechanisms. 
             These lower critical peak loads reduce the overall stress on the 
             system. Stress degrades equipment and causes reliability 
5.   Demonstrate how distribution feeder reliability can be improved 
     through the implementation of improved monitoring and control of the 
     distribution grid and the integration of automated meter outage 
     detection and restoration into a new digital distribution management 
     systems and a new outage management system.  
         • This benefit is measured by reductions in customer minute 
6.   Demonstrate how distributed resources (both generation and storage) 
     and electric transportation (electric and plug‐in hybrid vehicles) can be 
     safely and reliably incorporated onto the electric distribution grid 
     through the implementation of improved monitoring, protection and 
     control capabilities.   
         • The measurement will be the quality and usefulness of near real‐
             time information and controls and the benefit will be a 
             reduction in carbon‐based load and an increase in availability of 
             renewable generation.  
7.   Demonstrate how Smart Grid technologies (including advanced meters) 
     improve customer satisfaction by providing timely consumption and 
     conservation options, automated load control and alternative rate 
     plans, and improved monitoring and control of the distribution grid.  
         • The measurement will be greater customer satisfaction as 
             measured by improvement in energy savings and customer 
             satisfaction as measured through surveys. 
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           8.     Demonstrate how Smart Grid technologies can be deployed in 
                  configurations that are interoperable with both existing technologies 
                  and anticipated future technology enhancements. 
                     • The measurement will be a solution that is open and 
                          interoperable in accordance with existing industry standards and 
                          NIST/North American Electric Reliability Corporation 
                          (NERC)/FERC guidelines.  The benefit will be lower initial costs 
                          and long‐term technical flexibility to comply with emerging 
D.         Smart Grid Security 
           The advent of the Smart Grid, smart homes and smart metering all require 
communications and the ability to control devices that provide electricity to customers 
and manage the grid.  Communications security for the distribution grid has not been 
an issue in the past, since there were almost no automated controls or remote sensors 
in the distribution grid. Over the last few years, the issue has been explored by a 
number of industry working groups resulting in an extensive list of security standards, 
borrowed from the telecommunications community and other industries, to address 
Smart Grid security.   

        Under the Energy Independence and Security Act (EISA) of 2007, the National 
Institute of Standards and Technology (NIST) has “primary responsibility to coordinate 
development of a framework that includes protocols and model standards for 
information management to achieve interoperability of smart grid devices and 
systems…” [EISA Title XIII, Section 1305]. National Grid is participating in the NIST 
interoperability working groups directly and via strategic relationships with vendors 
such as Capgemini. Through this participation, National Grid is aware of the 
interoperability roadmap material developed by NIST, and more importantly, the raw 
information and processes it is based upon. National Grid’s end‐to‐end Smart Grid 
design incorporates industry standards already identified via the NIST process and will 
incorporate modifications and additional standards, as required, and in conjunction 
with key equipment and software vendors, when they are adopted by NIST.  
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        National Grid believes none of the specific objectives of its proposal will be 
impacted by the lack of existing, or the introduction of new, final interoperability 
standards.  This belief is based on the list of existing standards published by NIST on 
May 18, 2009.  While not final, none of the standards published to date, or 
recommended by the NIST workshop processes, lack adequate interoperability or the 
required level of security that would prevent National Grid from deploying an effective 
Smart Grid solution. 
        National Grid is also monitoring smart grid cyber security activities of FERC 
under the authority granted the agency in ESIA.  In the legislation, FERC was tasked to 
approve Smart Grid interoperability and Security Standards.  Accordingly, they have 
advised NIST to undertake the necessary steps to ensure that each standard and 
protocol that is developed as part of the Institute’s interoperability framework is 
consistent with the overarching cyber‐security and reliability mandates of the EISA as 
well as existing reliability standards approved by the Commission pursuant to Section 
215 of the Federal Powers Act.  The Commission proposes to make consistency with 
cyber‐ security and reliability standards a precondition to its adoption of Smart Grid 
standards.  While additional legislation may alter some of the roles for key agencies, 
the Company recognizes that NIST will likely remain the focal point for Smart Grid 
Standards.  In the interim, the recent efforts by FERC to add some degree of clarity to 
the standards discuss so the industry can move forward, provides National Grid with a 
set of guidelines within which we can confidently develop a Smart Grid Security 
approach.  We will, therefore, include the following activities in the Smart Program: 

       •   National Grid will endeavor to comply with the eight Critical Infrastructure 
           Protection (CIP) Reliability Standards of NERC. 
       •   National Grid will ensure that our selected vendor partners are participants 
           on the appropriate standards development groups and compliant with the 
           NERC CIP Reliability Standards.  
       •   National Grid has engaged one of the foremost authorities in Smart Grid 
           Security, Doug Houseman, Capgemini CTO, to oversee security compliance.  
           Mr. Houseman will make every effort to ensure that National Grid is aligned 
           with appropriate industry guidelines.   
       •   National Grid will not simply assume that compliance with standards is 
           adequate, we will test our systems using outside security experts to identify 
           vulnerabilities and adjust our approach to fill any gaps.  
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       •   National Grid will also program the processes and procedures required to 
           provide a long‐term secure environment. 
       •   National Grid will feed back to the various industry working groups lessons 
           learned to help accelerate the completion of good standards.  
         A general description of the overall scope of the National Grid Smart Grid 
Security Approach can be found in Attachment 1 hereto.  Information System security 
has been addressed in greater detail in the Section III of this Filing with applicable 
security details listed in an associated attachment.   
E.       Program Approach 
         National Grid has reviewed a variety of Smart Grid programs conducted by 
other utilities and has found that most focused on testing the functional characteristics 
of various technologies.  Such programs made important contributions to the 
maturation of Smart Grid technology, especially as they relate to the viability of 
various communications technologies and methods.  National Grid seeks to build on 
that work, not repeat it.  While the Company’s proposed Smart Program will confirm 
that the selected technologies offer a robust mix of capabilities to support Smart Grid 
and Clean Energy technologies, National Grid is also seeking to achieve a much 
broader understanding of the impact of both on its customers and business.   
         The proposed Smart Program is designed to demonstrate in action the Smart 
Grid with Clean Energy Modules in a manner, and at a scale, that will provide strong 
evidence to support the future deployment of technologies that enable a more 
interactive and cleaner energy system to all of our customers.  With a Smart Grid, 
customers can exercise greater choices about, and control of, their energy use.  At the 
same time, managers of the electric distribution and transmission grid will have a 
powerful new set of tools to improve efficiency, reliability, and security.  The existing 
performance of the network will be “base‐lined” (system performance data collected) 
before the Program is mobilized to enable a comparison of performance data before 
and after the Company’s Smart infrastructure is deployed.   
         Adding focused, but significant, levels of green components to specific sections 
of this Smart Grid will enable customers and the Company to test  PHEVs/EVs, PV, 
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Micro‐CHP, and Micro‐Grids, while the Company’s grid managers can study the impact 
to the grid and the business caused by these and other clean energy  or green‐enabling 
technologies.  The Smart Program will enable the scalable testing of the balancing 
potential of storage on intermittent clean energy generation as a deployable source of 
energy in location and during periods of congestion.  
         Similarly, the scale and embedded testing of smart and green will enable 
manufacturers of both technologies to improve their understanding of each and create 
a collaborative environment where both can be enhanced and more easily integrated.  
The need for a green car to talk to a smart meter and to communicate to the utility via 
a smart grid network to ensure proper identification and billing for remote recharging 
and potentially discharging will require each of the providers to interoperate.  National 
Grid’s Program will advance that dialogue.                   
F.       Customer Aspects   
         The proposed Smart Program will empower participants to reduce their energy 
consumption by first allowing them to understand their energy usage at a level of 
detail, timeliness, and ease that was previously impossible, and by providing new tools 
and services that will help them better manage energy usage.  National Grid’s Smart 
Grid enables new interfaces with customers such as web tools, text messaging, and 
home display units (in addition to improving information richness in traditional billing).  
These interfaces provide an essential link which will help to tailor solutions to 
individual customer needs and preferences, thus encouraging a dialog with customers 
on energy and its management. 
         National Grid believes customers will respond to the heightened awareness 
that the Smart Program can provide, but also believes that behavioral shifts can be 
best optimized if incentives are also available through innovative rates.  We will offer 
customers the opportunity to choose among three potential new P.S.C. No. 220 
Electricity Tariff Rule No. 46 Electricity Supply Service pricing alternatives (“Smart Grid 
Pricing”), i.e., Critical Peak Pricing, Peak Time Rebate, and Hourly Pricing Programs.  
This approach, together with a choice of interface channels, enables customers to 
choose pricing options, as well as their method and time of communications with 
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National Grid, resulting in greater customer choice, convenience, and a higher quality 
         The data and knowledge created by the Company’s Smart Program can also be 
combined with technologies that empower customers and electric distribution grid 
managers in other new and powerful ways, such as enabling a home area network and 
home automation tools that can monitor and optimize appliance performance and 
enable embedded demand response in a manner that is transparent to customers but 
sensitive to their needs as well as grid requirements. 
         National Grid’s Smart Program will also be an enabling technology for exciting 
new customer options such as plug‐in hybrid electric vehicles (“PHEV”).  For the Smart 
Program, we propose the introduction of 175 PHEVs/EVs.  We will focus the 
deployment of these vehicles to enable a true test of their acceptance, use and 
usefulness in reducing emissions, changing behavior and potential as a storage and 
supply resource.  We will also introduce new storage options to help balance the 
intermittent nature of certain distributed renewable resources, such as localized and 
distributed PV.  The Company also proposes to test several customer‐sited Micro‐
         National Grid proposes to coordinate with the New York State Energy Research 
and Development Authority (NYSERDA) to blend their energy efficiency programs with 
the Company’s existing and proposed programs.  Incorporating existing and proposed 
energy efficiency and demand response programs presents a great opportunity to 
blend National Grid’s energy efficiency initiatives with the Smart Grid and Clean Energy 
Modules to expand their effectiveness through the use of smart technologies.  We are 
especially interested in incorporating the seven (7) electric and eight (8) gas energy 
efficiency programs that we proposed in September 2008.   Including these programs 
in the Smart Grid areas offers a means to more directly measure the effectiveness of 
the energy efficiency programs and a chance to incorporate energy efficiency, smart 
and renewable on the same circuits.  We believe the information gained from the 
combination will be extremely important in developing increasingly effective energy 
efficiency programs.   Relevant energy efficiency programs can be found in Attachment 
2 hereto. 
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         If adopted, we believe the combination of The New York Energy Vision, 
National Grid’s Smart Grid, clean energy technologies and our energy efficiency 
Programs will create, in combination, a true leadership position that enables New York 
to provide a blueprint for the wider U.S. markets and a coherent integrated approach 
for future market evolution.  
G.       Utility Aspects 
         Electric utilities are at a transformational point in time.  Restructuring and 
other changes have affected the industry’s structure in recent years in sometimes 
radical fashion, but those transitions left essentially unchanged the roughly century‐
old manner in which electricity is generated, delivered, and consumed.  National Grid’s 
Smart Grid will enable significant changes in these areas by overlaying communications 
capability along the electric grid and inside the customer’s home or business, enabling 
the rapid flow of information (much of it never before available) and near real‐time 
control.  These new tools when combined with distributed generation and storage will 
require a variety of new approaches to service delivery, pricing and operational 
         The proposed Smart Program will allow National Grid to develop an 
understanding of the operational changes that can occur along its electric distribution 
system and within its business processes in order to better plan the transition to a 
smart and green grid.  This would include understanding how some clean energy 
technologies (such as energy storage, Smart PV inverters, and PHEVs/EVs) can be used 
by utilities to reduce peak demand, provide voltage support, and improve reliability.  
This crucial expertise cannot be developed simply by reading reports of the results of 
other utilities’ Smart Grid Programs.  In fact, we believe no other utility has included 
both the scope and the scale of our proposed Smart Program, particularly as it relates 
to green grid technologies.  The systems and processes at each utility are sufficiently 
distinct, and the transition to a Smarter Grid is so significant and affects so many 
fundamental processes, that learning by doing is the only way to transition to this new 
paradigm of energy delivery.  The Company’s Smart Program creates a process through 
which National Grid can achieve this knowledge.   
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H.     Technical and Functional Guiding Principles  
        The design principle National Grid has adopted is to think of the Company’s 
Smart Grid as a spine or backbone of core smart functionality to which we will be able 
to add elements in a modular fashion.  These elements or modules form part of the 
Company’s vision for the future, e.g., PHEV, Storage, and Renewable Energy, etc.  
While our Smart Program begins with the development of the spine, we also believe 
we can begin in parallel or even in advance of the smart grid deployment to 
manufacture and possibly deploy some of the modules, at least those, such as PHEVs, 
that may not require the full deployment of the spine to be useful.  The flexibility of 
this approach enables some of the proposed modules to be added quickly and 
expanded if desired making them more “shovel ready”. 
        National Grid’s approach to designing its Smart Grid Program also recognizes 
that the Company is at the beginning of a broad change to the electric industry.  The 
Company must continue seamless electric delivery operations during this transition.  
We must integrate legacy systems, business and operational processes, while we are 
adding new smart and clean energy technologies and changing key business 
operational functions.   The Company’s planning reflects this reality.   
        National Grid’s design approach considers both existing and developing 
standards and guidelines for interoperability.   This approach minimizes the risk of 
stranded investments, while ensuring that we are aligned with leading industry 
organizations.  Beyond those mentioned earlier, this includes the International 
Electrotechnical Commission’s interoperable communications and nomenclature 
standards for substation automation; and Common Information Model design 
principles under consideration by the NIST; National Electrical Manufacturers 
Association (NEMA) standards for plugs, reclosers and wiring; and the Institute of 
Electrical and Electronics Engineers (IEEE 802.x) for various Internet Protocol 
standards.  National Grid believes that open, interoperable systems are the most cost‐
effective approach and we recognize the key role that this approach will play in an 
industry that will rapidly evolve.    
        National Grid has recently conducted broad market testing via a request for 
information (“RFI”) process for Smart Grid, which involved over eighty vendors of 
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equipment and services.  The design of the process encouraged competition as 
vendors could bid on any combination of twenty‐two categories covering Grid 
Automation, Communications (Home, Local and Wide Area Networks), Systems, 
Advanced Meters, and Home Automation solutions.  We have also conducted a 
thorough review of the market for clean energy technologies and include a variety of 
these in our proposed Smart Program.   
I.      Smart Grid Functional Strategy   
        National Grid’s strategy overlays the electric grid with a two‐way 
communications network with speed and capacity sufficient to enable advanced 
metering, home energy automation and management, and distribution automation 
and management; and to support distributed generation and storage functions.  
National Grid already has components of the solution in terms of existing network 
assets that can be converted to Smart Grid components and communications 
infrastructure.  These include fiber and microwave facilities that can be used as part of 
the Smart Grid Program.  Wherever possible, National Grid incorporated these existing 
assets and systems into the Program design. 
    The specific business activities that the Smart Program will enable include:   
    Customer Facing Functions 
    • Provide interval metering for residential and commercial customers in the 
        Program footprint. 
    • Provide alternative rate plans including event‐based critical peak pricing, event‐
        based peak time rebate, and hourly pricing. 
    • Provide National Grid customer service representatives with meter status, 
        consumption and appropriate home automation related information. 
    • Provide energy consumption and pricing information to customers in their 
        home or business through a choice of media that they can select including: 
            o     Web 
            o     Home Display Unit 
            o     PDA/Text 
            o     Telephone 
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   •   Provide customers who choose the ability to control thermostats and energy 
       consuming devices in their homes or businesses manually or programmatically 
       (and via wireless mobile devices for those customers participating in certain 
       remote automation technology programs). 
          o     Enable (with customer agreement) remote control by National Grid of 
                thermostats and energy consuming devices in customer homes and 
Distribution Grid‐Facing Functions 
    • Enable monitoring and remote control of distribution equipment, including 
        monitoring feeders and transformers; and monitoring and control of 
        capacitors, reclosers, voltage regulators and switches. 
    • Enable distribution grid operators to use grid operational data to evaluate 
        switching alternatives in near real‐time, develop automated switching orders, 
        and remotely initiate automated switching orders. 
    • Incorporate automated meter outage and restoration events into a new digital 
        outage management system. 
    • Enable distribution operators to query remotely the outage / restoration status 
        of individual meters and groups of meters to confirm outage scale and 
        restoration status. 
    • Provide digital distribution grid operational data to grid operators via a new 
        Distribution Management System in a much shorter timeframe and at a level of 
        granularity sufficient for engineering analysis and asset management 
    • Install monitoring and control capability in substations and along the grid that 
        will enable National Grid to assess how to safely introduce and control a 
        significant quantity of distributed generation supply and storage (including 
        intermittent sources) onto the distribution grid. 
                       While a smart grid is not required to enable a certain level of 
                       distributed generation, our view is that the market is moving 
                       quickly to a distributed model in which both the adoption and 
                       concentration of these resources will quickly overwhelm the 
                       existing electric system.  Adding smart sensor along the grid will 
                       enable near real‐time monitoring of the system, while remote 
                       switching will enable rapid reaction to potential overloads or 
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                       rapid swings in loads associated with variations in distributed 
                       supply or demand.        
   •   Enable remote reconfiguration of loop or interconnected distribution network 
       assets to isolate and minimize outage impact.    
Green/Clean Energy Functions 
         Provide customers with different PHEV/EV charging options, such as smart 
         charging and green charging 
         Control PV smart inverters and integrated energy storage to provide voltage 
         support and to manage PV ramping and intermittency 
         Integrate micro‐CHP into the electric distribution system to enable grid isolated 
         operation and peak demand reduction 
         Dispatch energy storage to reduce peak demand and improve reliability 
         Manage a group of distributed resources to reduce peak demand and reduce 
         customer costs 
J.       Program Scale 
         National Grid is not proposing a technology program.  We are proposing the 
first phase of a Program that will ultimately transition the Company and our 
relationship with our customers.  Accordingly, we are proposing to deploy in two areas 
in significantly large volumes to enable a validation of our assumptions and to inform 
the larger transition.  National Grid proposes to include a total of approximately 
81,821 customers in this phase of our Smart Program.  This total will be equally divided 
between two geographic areas.  This sample size will support decision making for a 
scaled roll out, as it is a valid sampling of a range of customer segments (urban, 
suburban, rural), customer types (single family, multiple dwelling, small business), 
relevant and available third‐party demographics (such as income, education, and 
technology adoptions) and load profiles (low to high, average, peak and seasonal).  
This larger customer base will also allow the Company to include a sufficient number 
of distribution substations to test a broad variety of network infrastructure models.  
This will include radial and loop or interconnected feeders, and a large number of 
distribution system control devices, thereby offering a greater potential for 
introducing and testing distributed generation and storage options.   This approach will 
also provide sufficient scale to test a variety of renewable and storage options, a 
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significant number of PHEVs and associated remote charging stations, and a number of 
micro‐grid concepts.  
         Although these two areas within the National Grid service territory are unique, 
we have ensured geographical continuity in each to enable extremely comprehensive 
and thorough testing of Smart Grid in both and Clean Energy Modules in one.  This 
approach simplifies communications with external stakeholders, such as multiple 
mayors and city governments, and reduces marketing costs because we can focus in a 
limited media market.  This approach will also: (1) allow National Grid to focus internal 
resources in two geographic areas, reducing deployment time and costs; (2) enable 
automated switching along or between feeders in each area to test the potential of 
smart grid automation to limit outage impact; (3) permit testing of mission‐critical 
communications by providing an additional communications path for substation 
operations; and (4) enable a home‐to‐work testing of PHEVs within a single control 
K.       Proposed Program Sites 

        National Grid proposes two Smart Program areas, one in Syracuse and the 
other in the Capital District, north of Albany, based on the objectives and scope of the 
Smart Program outlined above as well as the following advantages: 
        1.     Size:  The Syracuse Program will include approximately 39,523 
               customers.  The Capital District Program will include 42,298 customers.  
               This combined total of over 81,821 customers allows National Grid to 
               choose a wide variety of customer types and grid equipment for the 
               overall Smart Program. 
        2.     Diverse Customer Demographics:  Because the two sites are relatively 
               dense, they offer the opportunity to test the value proposition of Smart 
               Program over a varied mix of customers.  Syracuse, Clifton Park and 
               Saratoga Springs are home to a diverse population of residential and 
               business customers making that location excellent for the introduction 
               of modules.  The behavioral characteristics of different customer groups 
               and differing rates and levels of automation will aid in understanding 
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         the implications and benefits of both smart and  green grid 
    3.   Diverse Distribution System Conditions:  The Company’s distribution 
         assets in these Smart Program areas are a representative mix of 
         overhead and underground distribution infrastructure as well as a 
         variety of substation types and network configurations (loop and radial).  
         Because of this variety, National Grid can extrapolate Program data 
         across National Grid’s entire service territory to better understand its 
         potential operational impact and benefits. 
    4.   Proximity to Existing and Proposed Distributed Generation:  A key 
         objective of the Smart Program is to provide the backbone for potential 
         distributed generation and storage resources, in order to determine 
         whether or how these resources can be safely and reliably incorporated 
         onto the distribution grid through the implementation of improved 
         monitoring, protection, and control of the distribution grid.  Both 
         Program areas have a number of existing and potential distributed 
         generation project sites, including a large PV project at SUNY 
         Environmental Sciences and Forestry Center in Syracuse and PV projects 
         at Curtis Lumber Yard in Malta and BJ’s Wholesale Club in Wilton. 
    5.   Access to Institutions of Higher Learning.  Syracuse is home to Syracuse 
         University and the Syracuse Center of Excellence in Environmental and 
         Energy Systems.  The University’s entire campus will be included in the 
         Syracuse Program area.  The Center of Excellence provides National Grid 
         with a network of researchers and innovators throughout the state.  
         Albany is home to a number of colleges and universities including 
         Rensselaer Polytechnic Institute (RPI).  While the RPI Campus is not in a 
         Program area, National Grid hopes to collaborate with RPI on this 
         Program from an engineering and research perspective.  Additionally, 
         Skidmore College in Saratoga Springs is in a Program area.  National 
         Grid believes that as a responsible corporate citizen and an advocate for 
         the smarter grid of the future, National Grid can take advantage of 
         opportunities to help the staff and students of these and other 
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                   institutions gain exposure to and knowledge of the developing green 
                   industry.  The Company hopes to partner with institutions such as 
                   Syracuse University, Stony Brook (AERTC), Skidmore College, Clarkson 
                   University, and RPI to participate in equipment testing, facility 
                   participation in energy efficiency and conservation programs, testing of 
                   energy management systems, community outreach, education, 
                   marketing and analysis. 
    L.     Site Characteristics 
           The Syracuse Program area includes seven substations, the feeders supplied by 
    these substations, and the customers supplied by the feeders.  These substations are: 
               • Bridgeport Substation 
               • Butternut Substation 
               • Duguid Substation 
               • Fly Road Substation 
               • Pebble Hill Substation 
               • Rock Cut Substation 
               • Southwood Substation 
           The Capital District Program area includes ten substations, some or all of the 
    feeders supplied by these substations, and the customers supplied by the feeders.  
    These substations are: 
               • Ballston Substation 
               • Brook Road Substation 
               • Elnora Substation 
               • Grooms Road Substation 
               • Saratoga Substation 
               • Shore Road Substation 
               • Smith Bridge Substation 
               • South Street Substation 
               • Weibel Avenue Substation 
               • Randall Road Substation 
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        Maps of the area covered by each substation are included in Attachments 3A 
and 3B hereto.  Based on the areas served by the substations listed above and the 
associated feeders, the total number of active customers to be covered by the 
Program as of April 1, 2009 would be 81,821.  The number of Smart Program 
customers in each rate class is outlined in Attachment 4 hereto.   A complete list of 
feeders together with number of customers and equipment on each feeder is included 
in Attachment 5 hereto. 
M.      Program Cost 
        The overall cost of the Smart Grid Program is estimated at         million for the 
Spine and       million for the Clean Energy Modules for a total project cost of        
million.  The cost of the Program is disproportionate to a volume deployment as the 
fixed costs are borne over a smaller number of installations.  The cost of the Smart 
Program will be shared across National Grid’s customers as discussed below.  This cost 
includes the following key categories: 
Smart Grid Spine 
    • Hardware                                     
    • Software                                     
    • Services                                     
Clean Energy Modules 
    • Hardware and Software                        
    • Services                                     
         The cost of the Spine on a per meter basis is       .  This number is not 
representative of the costs of an overall deployment, which would be closer to            
per meter.  The cost of equipment and associate software will be much lower when 
acquired at mass deployment scale.  The integration and services required to enable 
this Smart Program will lay the groundwork for the mass deployment, but cannot 
reflect that broader value in the cost analysis for a much smaller Smart Program.  
Additionally, while National Grid anticipates that the benefits of a Smart Grid will 
outweigh the costs in a mass deployment, not all potential benefits can be realized in 
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the Program.  One benefit that can be realized is the direct benefit of load reduction.  
Using the January 2009 EPRI Report9 on achievable potential in Energy Efficiency and 
Demand Response, National Grid believes that a five percent reduction is considered a 
reasonable range.  If the Company achieves this level of reduction in load, this benefit 
could provide an overall customer bill reduction for customers in the Smart Program of 
approximately                    per month.   
        The indicative cost analysis below illustrates how the cost per home decreases 
as the scale increases from the Smart Program volume to the full customer base: 
                                  Volume                              Cost ($M)                Cost per Customer ($) 
        With regard to a full deployment, as the graph below indicates, the first four 
columns of potential discounted benefits together equal                                          per meter, while the 
last two columns of estimated discounted costs equal                                     per meter.  The projections 
suggest a positive business case for the full deployment, but a key objective of the 
Smart Program will be to determine if the benefits can be actualized and the costs 

  Assessment of Achievable Potential from Energy Efficiency and Demand Response Programs in the U.S. 
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N.            American Recovery and Reinvestment Act of 2009 (ARRA)  
        Under ARRA, approximately $4B is allotted to the DOE’s Office of Electric 
Delivery and Energy Reliability to support implementation of the smart grid programs 
authorized by EISA 2007.  These include Smart Grid Investment Grant (SGIG) Program 
as authorized by Title XIII, Section 1306 and Smart Grid Demonstration (SGD) Program 
authorized by Title XIII, Section 1304.  Each program has a specific intent which 
collectively are designed to advance the realization of a Smart Grid:  
    • The intent of the SGIG FOA is to provide grants of up to one‐half of qualifying 
        smart grid investments to support the manufacturing, purchasing and 
        installation of smart grid devices and related technologies, tools, and 
        techniques for immediate commercial use in electric system and customer‐side 
        applications including electric transmission systems, electric distribution 
        systems, building systems, advanced metering, appliances, and equipment.  The 
        ultimate aim is to enable smart grid functions on the electric system as soon as 
    • The intent of the SGDP FOA is to provide financial support, up to one‐half of the 
        total project cost, to demonstrate how a suite of existing and emerging smart 
        grid technologies can be innovatively applied and integrated to prove technical, 
        operational and business‐model feasibility. The ultimate aim is to demonstrate 
        new and more cost‐effective smart grid technologies, tools, techniques, and 
        system configurations that significantly improve upon the ones that are either 
        in common practice today or are likely to be proposed in the SGIG Program.  
        Furthermore, these demonstration projects should serve as models for other 
        entities to readily adapt and replicate across the country. 
        The guidelines for funding under each program have now been released.10  The 
focus of the SGIG Program is rapid smart grid enablement using commercial 
technologies.  The focus of the SGD Program is to demonstrate creative application of 
existing and cutting edge smart applications that results in cost‐effective use and 
advancement of the technology.     

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The Company intends to apply for matching funds in SGIG and/or SGD programs.    The 
recently released guidelines have made it necessary to consolidate Clean Energy 
Modules in one deployment area and utilize the other area for a rapid roll out of 
existing smart grid technology.  In addition, National Grid has partnered already with 
Ford Motor Company on the DOE's Transportation Electrification FOA (DE‐FA‐
0000028).  National Grid is a sub‐applicant with 15 other utilities. The proposal is to 
build and test 740 electric vehicles, including the necessary charging and electric 
distribution infrastructure.  National Grid's cost share commitment is in the form of 
infrastructure that will support charging of these vehicles (i.e., investments as 
approved in this Filing). 

O.     Next Steps 
        While National Grid’s Smart Program proposal is pending before the 
Commission, we are preparing our DOE applications and our implementation plans.  
We are undertaking design, testing, training and furthering the commercial 
negotiations with vendors.  If and when the DOE application is successful and we 
receive matching ratepayer funding, National Grid’s lead time for implementation will 
be shortened.  A deployment plan is included in Section V of this filing showing the 
sequential steps.  National Grid anticipates that delivery lead times for certain critical 
Smart Grid equipment will begin to slip as the impact of ARRA funding begins to create 
greater demand.  For that reasons and given the funding guidelines from DOE, we 
agree with the Commission that prior regulatory approval will significantly improve the 
potential for developing delivery partnerships and winning ARRA funding.  Therefore, 
an expedited approval is essential to meeting the project timeline and improving the 
opportunity for matching funds.  In addition, the Smart Program is also subject to 
National Grid’s internal review and approval process, which is occurring concurrently 
with the Commission’s review. 
        National Grid’s SGIG and SGDP Programs will have both direct and indirect 
effects on the Company’s customers.  The Company will provide all participating 
customers smart electric, and where applicable, retrofit their gas meters with smart 
communications modules.  A subgroup of participating customers will receive 
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technology inside their homes or businesses with varying degrees of information and 
controls for managing energy usage.  In addition, new rate alternatives proposed will 
allow participating electric customers the flexibility of saving money as they adjust to 
the realities of market pricing.  Of course, these new technologies and new rates will 
require customer education, which we have anticipated in our deployment plan.  With 
the exception of the installation of in‐home devices, the above are traditional utility 
activities for which National Grid’s existing programs and policies are well adapted.  
Processes for in‐home installations, while not part of the Company’s existing services, 
are sufficiently close to National Grid’s core competencies that National Grid is 
confident in its ability to perform them.  We are also working closely with industry 
experts who have experience installing these devices to guide the Company’s efforts.        
          The Smart Program involves much more than equipment installation and new 
tariffs.  The capabilities enabled by our Smart and Clean Energy Program will result in 
fundamental changes in customer access to energy information and their ability to 
control and manage energy usage.  To effectively implement the Smart Program, 
customers must receive sufficient information to interpret and act on the new data 
and master the new capabilities that will be available to them.   National Grid will 
provide information in the following ways:   
          1.     Coordination with related marketing, education and outreach programs, 
                 including demand response, energy efficiency, conservation and low 
                 income programs. 
          2.     Coordination with providers with similar or related interests and 
                 services, such as local governments, community‐based organizations, 
                 local firms and any overlapping municipal authorities.  
          3.     Comprehensive use of internal methods to reach customers, including 
                 billing, bill inserts, company web page and call center.   
          4.     Comprehensive use of external methods to reach customers, including 
                 Internet, direct mail, and town hall meetings.  
          5.     Comprehensive outreach to local, state, and regional stakeholders 
                 focused on Smart, Clean Energy and Energy Efficiency activities to 
                 provide education material and access to subject matter experts. 
          6.     Targeted and tailored marketing that reflects the values, habits and 
                 demographics of different target communities and populations. 
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        The Smart Program will provide an opportunity to test these communications 
and education approaches in order to determine their effectiveness.  What National 
Grid learns will inform our broader rollout.   
            A. Service Levels 
        National Grid is working with internal and external resources to develop a 
comprehensive education plan for customers in the Program areas.  Three levels of 
service will be offered in phases; each service level will become available as enabling 
technology is added at the Company, along the grid, and in the customers’ facilities.   
All materials will emphasize the degree to which customers are now empowered to 
make choices and encourage them to use these tools to optimize energy usage.     
               i. Level One. 
                      The Level One program provides electric and gas customers (where 
                      applicable) with hourly consumption information for both electric 
                      and gas (where applicable), and information about actions they can 
                      take to lower their energy costs.  In this level, hourly energy 
                      consumption data is available to customers either on the Internet or 
                      via a Home Display Unit (HDU).  As technology and capabilities 
                      become available, customers will be encouraged to take control of 
                      their energy usage with the introduction of dynamic pricing.  
                      National Grid expects that time‐dynamic pricing programs will 
                      include Peak Time Rebate, Critical Peak Pricing Program and Hourly 
                      Pricing Program.  Dynamic pricing plans are not currently being 
                      planned for gas.     
                 ii.  Level Two. 
                      Under the Level Two services, customers can set a monthly energy 
                      expense target and National Grid will help them stay on course by 
                      providing on‐demand account status and suggestions to help them 
                      adjust their energy usage if it appears they are not on track.  
                      Customers will have access via the Internet  (as well as through an 
                      HDU, if they are participating in the Home Automation Program 
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                                    initiative) to hourly consumption information and progress reports 
                                    regarding their energy consumption, as well as access to strategies 
                                    to improve energy efficiency and savings.  This level will include 
                                    electric and natural gas (where applicable) customers. 
                                    In addition to the benefits outlined in Level One, customers who 
                                    chose Level Two will receive, via email or text message, National 
                                    Grid “Energy TARGET Plan Alerts” indicating their status (on‐
                                    track/off track) relative to their target.  Further, customers will 
                                    receive information about how they compare to their neighborhood 
                                    and to other customers with similar homes. 
                             iii.  Level Three.11 
                                   The Level Three offering will provide various home automation 
                                   options that enable a more robust integration of distributed 
                                   generation and storage.  This plan allows consumers to manage 
                                   their energy by programming a sophisticated panel that 
                                   communicates with the electric grid.  Customers will have the 
                                   option, either instead of or in addition to managing their home 
                                   automation capabilities themselves, to authorize National Grid to 
                                   take certain actions to reduce their energy use or shift their usage to 
                                   lower‐priced times during certain peak load conditions.  This activity 
                                   could include remotely resetting programmable thermostats by an 
                                   agreed amount or directly cycling certain high energy consumption 
                                   systems such as air conditioners off within agreed timelines.  
                                   Attachment 6 hereto summarizes the business capabilities under 
                                   each service level. 
              B.             Marketing Plan 
  As Green Modules are designed new customer programs and/or changes to existing customer 
programs will be indentified and designed.  Some or all of these program changes will require tariff 
changes.  Small numbers of customers will be served by these programs.  The Green Modules that are 
most likely to require these changes include PV, PHEV/EV, Wind Power, Micro‐CHP, Micro‐Grid and 
Holistic Homes. 
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        Aggressive marketing, education and outreach will be critical to achieving the 
objectives of the Smart Program.  The Program seeks to encourage a fundamental 
change in consumer behavior, while increasing customer satisfaction.  Significant 
education will be needed to inform customers of available service levels and the 
benefits of participating in the Programs.  National Grid’s education and marketing 
effort will target all residential customers in the Smart Program footprints, eligible 
commercial customers, and community leaders.  The specific objectives of the 
marketing plan are to: 
    • Create awareness of the Program and the information and options it provides.   
    • Educate customers about the benefits, to them and to society, of a Smart Grid. 
    • Encourage customers to take advantage of the new information and 
        capabilities offered by the Smart Grid. 
    • Motivate customers to permanently change their energy usage behavior. 
    • Inspire customers to become advocates of energy usage modification. 
        The customer education plan includes a phased marketing approach beginning 
at the time of regulatory approval and continuing throughout the Smart Program 
period.  Such a plan will communicate Smart Grid concepts in a clear and simple way, 
engage Program participants in one‐to‐one demonstrations, and make it easy for them 
to understand how to take advantage of all the benefits the Smart Grid has to offer.  
        In order to design the marketing plan for the Smart Program, National Grid 
conducted eight focus groups with residential and business customers throughout its 
service territory.  Two of these focus groups, one business and one residential, were 
held in Syracuse.  This research revealed that customers feel they lack control over 
their energy use.  They believe that having information available to them about their 
usage would be the first step in controlling their energy consumption.  Most focus 
group participants acknowledged that they needed additional information and 
motivation to modify their behavior.  National Grid used the information gathered 
from these groups to develop its customer education strategy, and will carefully 
analyze its experience during the Smart Program to refine these findings by 
determining which education approach is most effective. 
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         Customer and stakeholder education will focus on developing an 
understanding of the benefits that can flow from real time energy usage information 
and dynamic energy pricing as well as the positive environmental impact that targeted 
personal adjustments to energy usage can achieve using a Smart Grid.  National Grid 
will encourage greater participation in its energy efficiency programs.  A cornerstone 
of the marketing program is the development of the “Smart Squad.”  This outreach 
team will include twenty full time members – ten for Syracuse and ten for the Capital 
District – who are fully trained in Smart Grid technology.  The Smart Squad will conduct 
demonstrations of Smart Grid applications in both one‐on‐one and community‐based 
settings, and will serve as a neighborhood resource for Smart Grid Program 
         National Grid intends to establish two Smart Grid sites in the Smart Program 
footprints to help educate stakeholders.  In Syracuse, National Grid intends to utilize 
its technology demonstration facility at Henry Clay Boulevard as an evaluation and 
demonstration area for Smart and Clean Energy technologies.  In the Capital District, 
National Grid intends to rent and then outfit a “smart home”.  The home will include a 
full suite of home energy automation tools and Clean Energy technologies.    
         The customer education plan will have three phases; seed, share, and succeed.  
The seed phase begins with regulatory approval and concludes when the Smart Grid 
becomes operational in the Program areas.   This phase includes launching the Smart 
Squad, direct mail, public relations and recruiting the super users, a group who will 
agree to be the initial test homes and businesses for the technology. 
         In the share phase, the plan moves from announcement and recruitment 
activities to building awareness, education, and engagement.  Program participants 
will be introduced to the Smart Grid via a welcome kit containing a DVD that chronicles 
the Smart Grid experience.  National Grid’s website will have Smart Grid planning 
details and monthly bill inserts will also include information.  National Grid will provide 
updates by solar powered billboards in the Program areas as well as by electronic 
newsletters and direct mail.  Additional plans include a series of educational breakfast 
meetings throughout the Program area, neighborhood contests to drive Program 
participants to achieve greater savings, field demonstration units to engage Program 
participants, in‐home demonstrations, and education institution partnerships. 
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         In the final phase of the marketing plan, succeed; the Company will focus on 
those strategies from the share phase that have proven most successful.  Attachment 
7 hereto contains a timeline and information about the three phases.   
         National Grid will carefully measure the success of its marketing and education 
efforts.  We will include pre‐ and post‐Program awareness research to set baselines 
and measure program impact, marketing channel success tracking, identification and 
measurement of website metrics, call center tracking, and customer participation rates 
by a variety of demographic and load profiles, and associated savings.  Attachment 8 
(Confidential) hereto outlines the expected cost for the marketing plan.  The 
Company’s estimated budget for a five‐year marketing program is                    .  This 
represents approximately                 of the total expected Smart Program cost of 
              .  Although this percentage is slightly higher than traditional marketing 
programs, National Grid believes it is justified due to the degree of customer education 
and incentives likely to be needed to change long‐ingrained customer habits and 
expectations and to create awareness of and willingness to take advantage of the new 
energy options made possible by a Smart Grid. 
         C.      Community Outreach 
         In addition to outreach to our energy customers, National Grid has developed a 
comprehensive plan to inform key external stakeholders, such as city, state and federal 
officials, community associations, education institutions, and the media.  This will 
include some of the same educations activities noted earlier, but it will also include an 
effort to understand the concerns of each stakeholder group as it relates to Smart and 
Clean Energy, conservation, and energy efficiency.  
         D.      Customer Service 
         As noted earlier, Program participants electing to monitor their accounts via 
the Internet will have access to detailed usage information, pricing, trends and 
program alerts.  Customers phoning into the Contact Center will be able to use their 
existing Customer Service phone numbers, but will be offered a Smart Grid specific 
option via the Interactive Voice Response System, routing them to an agent specifically 
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trained and qualified to handle their inquiries.  To address the unique needs of Smart 
Grid Program customers, additional training will be provided for these agents, 
including not only the technology and applications, but also the broader capabilities 
and benefits of a Smart Grid and the Program objectives.  Customer Service 
representatives will also have information about the new rate structures created for 
the Program and will be able to educate customers on the benefits from the rate plans 
given their individual situation. 
          E.      Billing   
          Due to the cost and complexities associated with replacing the systems that 
support the existing meter reading to invoicing process, National Grid will modify 
existing systems where practical to support these processes.  Key among these will be 
the billing system.  We will make some modifications to accommodate the proposed 
new tariff structures outlined below in this section.  Customers in the Program will 
continue to receive a billing statement on a monthly basis.  They will also have the 
option to view their bill online through National Grid’s website.  To minimize the 
potential for confusion, the Company intends to have Program customers retain their 
current account numbers. 
          While the Program will enable the capture and presentation of significant new 
and useful data, National Grid will endeavor to make the experience for the customer 
as routine as possible with regard to bill presentation.  To that end, other than a logo 
at the top of the bill, which will identify the customer as a Smart Program customer, 
the billing statement customers receive will look similar in many ways to their current 
statement.  Name, address, account number, and billing period will continue to be 
displayed as they are today.  The Account Balance section will also remain the same.  
While these customary details will remain, the Detail of Current Charges section will be 
tailored to the appropriate Program tariff.  Program customers will continue to receive 
all bill inserts they currently receive, including standard safety information, but will 
also receive new Program information. 
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        A.     Smart Grid ‐ Guiding Principles 
       In developing the Program and its broader Smart Grid plans, National Grid 
sought to develop a solution that:   
   • is aligned to Customer needs – both current and anticipated; 
   • is aligned with the agencies and organization developing guidelines for Smart 
       Grid ;  
   • aligns with National Grid Information System (IS) Technology Standards; 
   • leverages existing National Grid IS assets to the largest extent practicable; 
   • features a communications infrastructure that meets the requirements of 
       advanced metering, customer choice/control and grid monitoring / control; 
   • uses standard communication protocols that support assigning unique 
       addresses to individual devices;  
   • complies with current cyber‐security requirements and is capable of adapting 
       to future requirements as they evolve;  
   • has an integration architecture that incorporates the IEC 61968 and IEC 61970 
       Common Information Model and reference interfaces;  
   • is interoperable with existing technologies and will interoperate with future 
       technology enhancements;  
   • is flexible enough to accommodate varied vendor products to ensure 
       competition and choice; and   
   • enables common end‐to‐end business processes that are as independent of 
       field technologies as possible, enabling consistent processes to be maintained 
       with changes in technology.  

            o Interoperability. 
                National Grid is employing industry standard technologies and practices 
        as guiding principles during design and implementation.  National Grid is 
        pursuing interoperability between the three major elements, grid, meter, and 
        home.  This translates to using a non‐proprietary and standards‐based 
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approach to deliver an open architecture that can quickly and very easily 
integrate various vendor solutions into a single cohesive solution.   This 
approach enables the widest possible technology and vendor choice for in‐
home devices and for our own enterprise systems.  It also is consistent with 
FERC Interoperability and Stranded Costs guidelines noted earlier.   
    o Multi‐tier Architecture. 
        The solution utilizes a multi‐layered component based architecture 
platform that addresses the demanding performance and scalability 
requirements for the project.  A multi‐layered architecture enables logical 
separation (de‐linking) of the various solution components making it easier to 
surgically replace or upgrade legacy components and add new components. It 
will consist of metering devices, network infrastructure (Home Area 
Network/LAN/WAN), client servers/machines, web server(s), application 
server(s), database server(s) and network storage.  
        This multi‐tier approach organizes major components into Service 
Layers.  These Service Layers act as both a common reference for all vendors of 
a particular function and offer a common view across all components of the 
overall solution.  This approach creates a common evaluation process and 
ensures Service Layer interoperability.  
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       The figure below represents the various Service Layers. 

           o Commercial‐off‐the‐shelf (“COTS”). 
          National Grid will leverage vendor strengths and competencies in choosing 
    COTS products as opposed to developing in‐house solutions.  There are numerous 
    advantages to this approach including:  
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     Selected products and applications have already been tested and proven in other 
                 • less  risk; 
                 • lower cost; 
                 • faster time‐to‐market; and  
                 • more robust enhancements as these technologies continue to 
                     mature in support of a wider market share.  
         i. Scalability and Flexibility 
         Each service layer and associated product, and the overall Smart Grid system, 
can scale as the number of customers increases from the Program to full deployment.  
The overall architecture design will enable rapid changes in business needs, such as 
meter reading software and processes, as National Grid expands the coverage area. 
         As business processes change and volumes increase, it is important for each 
product in each service layer to independently change without significant impact to 
business or other components of the solution.  The multi‐layered architecture satisfies 
these requirements without significant impact to other processes in the solution. 
         ii. Leveraging Existing Systems 
         Some of National Grid’s legacy systems will have to be upgraded or replaced as 
the project develops.  National Grid will be able to use the same open, interoperable, 
multi‐tier, scalable designs that we are using for all other Smart applications and 
products.  A more detailed assessment of the systems can be found in Attachment 9 
         iii. Future Outlook 
         The technology vision also recognizes that the market is continuing to develop.  
As National Grid overlays a robust communications backbone along the electric grid 
and extends it into the customers’ homes or businesses, new products and services 
will rapidly emerge.  The Company is selecting products for this backbone that will 
allow growth.  By designing an open, interoperable system, National Grid reduces the 
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risk of obsolescence while increasing the potential for rapid introduction of innovation 
with minimal disruption. 
         Through a recent RFI process, National Grid has sought to obtain the most 
current information on Smart Grid technologies, services, and pricing.  This process 
familiarized National Grid’s Program team with the capabilities and limitations of key 
technologies and helped identify those technologies and services that may be utilized 
during the Program.  Through this extensive procurement process we have identified 
multiple providers in each aspect of the proposed solution and we are ready to further 
negotiations and enter contracts once we receive regulatory approval.  Details of the 
RFI process and its outcome are provided in Attachment 10 hereto.    
         The Program’s proposed Smart Grid technology solution will provide customers 
with ready access to more detailed and timely consumption information, timely energy 
cost and pricing options, greater choice, and simple, automated consumption controls.  
The technology solution and the new business processes that it enables will provide 
distribution grid operators and managers a powerful new set of tools to improve the 
efficiency, reliability and security of the grid.  The Smart Grid technology will serve as 
the foundation for the Clean Energy Modules, including distributed generation, remote 
energy storage, plug‐in hybrid electric vehicles and the next generation of renewable 
         At the heart of the Smart Grid technology solution is a two‐way communication 
system with the security, capacity and speed to enable advanced metering, new 
service offerings for customers that improve choice, control and convenience; 
distribution grid monitoring and control, as well as, the addition of Clean Energy 
Modules.  Existing meters will be replaced with advanced digital smart meters.  These 
meters are critical to providing the interval consumption data required to enable 
customer choice, control and convenience.  They also provide a variety of data 
elements required to support distribution grid monitoring.   
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        In addition, in‐home energy management technologies will be made available 
to customers who choose to use them.  These technologies will be organized from 
simple home display units to more complex and interactive automation software, 
programmable communicating thermostats, and communicating appliance 
disconnect/control devices.  With these technologies, customers will be able to view 
their energy consumption and cost in near real‐time, learn about and evaluate 
alternatives for reducing their energy consumption and expenditures, automatically 
control electrical loads in their homes and, if they choose to, allow electrical system 
operators to control certain in‐home devices during critical system load reduction 
        The distribution feeders that provide electricity to customers in the Program 
areas will be updated to include sensors to monitor critical operating parameters and 
control equipment that can sense abnormal conditions on the grid and allow the grid 
to be reconfigured.  All of the technologies installed on the distribution grid will 
communicate with a new network management system in the grid operating centers.  
This network management system will enable grid operators to view the status of the 
grid in near real‐time, identify abnormal operating conditions, evaluate corrective 
actions and take remote action to reconfigure the distribution grid to avoid or 
minimize the scope and duration of outages, and improve voltage regulation and 
power quality.  In addition, the grid operating data gathered and recorded by Smart 
Grid‐enabled sensors will guide future grid investments by identifying specific grid 
enhancements that will reduce unplanned outages and generally improve power 
        The Smart Grid technologies proposed for the Program will support the 
addition of distributed resources, including renewable generation, energy storage and 
plug‐in hybrid electric vehicles, by allowing all of these resources to be interconnected 
with the grid in a carefully managed process that does not overwhelm and destabilize 
the grid as the number and types of these resources increases over time. 
        i. Communications Technology 
        Smart Grid systems will rely on a robust, two‐way communications platform to 
effectuate reliable and secure transfer of data.   The general architecture will be the 
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development of neighborhood collectors that will act as access points for meters, in‐
home devices and some grid devices.  Collectors will in turn communicate with a wide 
area infrastructure that will leverage existing National Grid assets, new wireless 
technologies, and public networks where appropriate to communicate between field 
collectors and grid devices and utility operators and computer systems.  To enhance 
our SGDP application, in conjunction with the Clean Energy Module deployment in 
Syracuse, National Grid will evaluate and may demonstrate more advanced 
communications capabilities in some or all of that area. 
        The goal is to have the same infrastructure support both customer and grid 
device communications.  The preferred solution is a private infrastructure committed 
solely to the Smart enablement, but the reality of National Grid’s service territory and 
the cost to construct a dedicated network from home to utility makes the use of some 
public network transport necessary.   
        The meter will serve as the communications portal into the customer home.  
This approach makes available a certain level of communications capability to all 
customers and will place the responsibility for operations of that infrastructure12 on 
National Grid.  For those customers who opt for the most robust in‐home energy 
management tools, interaction with home devices and in‐depth consumption data will 
be managed via a customer‐provided broadband internet connection.  In this scenario, 
the customer’s existing broadband router will be the interface point to new high 
bandwidth, low latency in‐home devices that enable this more robust and automated 
energy management.  As new vendor offerings become available, they will be 
evaluated and made available as appropriate. 
    That network is composed of the following major elements: 
    • Wide Area Network (“WAN”) – The WAN enables communication between 
        regional collection points and the utility operating center and back office.  
        Communications to and from multiple meters and intelligent electronic devices 
  Each meter will contain a communications module that will be capable of communicating outside the
home to a neighborhood collector; but also will communicate inside the home to support standard in-
home energy management devices. The collector and the Communications module are part of this new
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        (IEDs) are routed through regional collection points located throughout the 
        Program area.  
    •   Local Area Network (“LAN”) – The LAN enables direct communications between 
        individual smart meters and IEDs and between individual devices and regional 
        collection points. 
    •   Home Area Network (“HAN”) – The HAN enables communications between the 
        meter and IEDs installed within a customer’s home or business. 
   A graphic depiction of the proposed communications network is shown 

      The WAN will be designed and constructed, where required, using a 
combination of proven fiber optic, microwave and WiMax technologies.  Existing 
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National Grid assets will be incorporated into the Smart Grid WAN to the largest extent 
practical with some degree of reliance on public networks where practical.  
        The LAN will be a two‐way radio frequency network.  Installed meters and grid 
sensors will self‐discover and register on the network when electrical power is applied 
to them.  The HAN will be a wireless network that uses the ZigBee Smart Energy Profile 
embedded in the meter to manage the exchange of interval usage, price signals, and 
controls as appropriate and other meter or customer information from the utility to 
customers and from customers to the utility.   
        Within a customer’s home or business, a variety of communication protocols 
will be evaluated to determine their strengths, weaknesses and appliance‐level 
application for in‐home communications.  These protocols will include ZigBee from the 
meter direct to the in‐home devices and Insteon and Smart Plug with a bridge relay 
between the devices and the meter.  Attachment 11 hereto provides additional 
information on the smart communications. 
        ii. Smart Metering 
        National Grid proposes using advanced metering technologies in the Program 
that enable the meter to be a smart consumption measurement devices and an 
important Smart Grid sensing device.   The meter will measure and report total 
consumption, interval consumption, demand, energy supplied by the grid, energy 
provided to the grid, voltage and power factors.  It will also be able to log and trigger 
communications to alert the operator to specific occurrences such as tampering, 
outages, and meter/load problems.     
        iii. In‐Home Energy Management 
        The in‐home energy management technologies are designed to allow 
customers to participate at multiple levels.  At each level of participation customers 
are provided with energy consumption and pricing to inform their decision making and 
process.  As customers elect to become more engaged, the information and tools 
available to them to actively manage their energy consumption and usage become 
increasingly detailed, timely and interactive, with more options and greater flexibility 
for the customer.  
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       Customers who elect to participate in the energy management programs will 
be provided with three choices of in‐home energy management technology.   
   • Option 1:  In‐Home Technology consisting of a home display unit will be 
       provided for those customers who select a minimum level of involvement in 
       energy management programs.  The base model home display unit will provide 
       customers with basic consumption information from the meter and 
       informational messages from National Grid.   
   • Option 2:  In‐home technology will consist of a home display unit and two (2) 
       in‐home control devices, either programmable communicating thermostats 
       and / or direct load control devices.  In addition to basic in‐home display 
       functionality, in‐home technology in this level will allow customers to enroll in 
       a direct load control program that allows National Grid to control thermostat 
       settings and disconnect loads in a customer’s home or business during system 
       critical peak events.   
   • Option 3:  In‐home technology will consist of a web‐ and / or mobile device‐
       enabled set of tools that allow customers to:  1) receive targeted educational 
       content from National Grid via written, audio or video media to inform them 
       about techniques that they can employ to reduce their energy consumption; 2) 
       model and track the impact of various actions on their energy consumption and 
       expenditure; 3) interactively control individual loads in their homes or 
       businesses; 4) add additional load control devices to their home or business 
       accounts; and 5) establish time‐of‐day and of‐week load control profiles that 
       automatically control loads in their homes or businesses to reduce their energy 
       consumption every day of the year, not just on system critical peak days.   
No in‐home technology will be provided for customers who elect not to participate in 
energy management programs, although they will still be able to participate in the 
Smart Program via new pricing tariffs.   
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        iv. Grid Monitoring and Automation Technology 
         The monitoring and control technology deployed on the distribution grid as 
part of the Program will work in concert with the communications and advanced 
metering technologies described above to improve the operating efficiency and 
reliability of the distribution grid, while at the same time providing the Smart Grid 
foundation necessary to enable greater numbers of distributed resources, such as 
renewable generation, battery storage units and PHEVs, to be added to the 
distribution grid safely and efficiently. 
Six categories of technology are being deployed on the grid as part of the Program:   
    • First, new monitoring devices will be mounted directly on feeders.  Feeder 
         monitors will be installed at selected locations on each phase of three phase 
         feeders to measure voltage, current and power factor on each phase.  Faulted 
         circuit indicators will be installed at selected locations to allow circuit faults to 
         be recorded in order to identify the location and nature of circuit faults.  
         Distribution transformer monitors will be installed on approximately two thirds 
         of the distribution transformers in the Program area.  These devices measure 
         secondary voltage, current and power factor on each.  
    • Second, retrofit communication devices will be installed on existing grid control 
         and switching equipment to enable this equipment to be monitored and 
         controlled remotely.  Existing recloser and capacitor bank controllers capable of 
         supporting communications will be upgraded to add this capability to allow 
         remote monitoring and control of reclosers and capacitor banks.  Existing 
         recloser and capacitor bank controllers that cannot be upgraded will be 
         replaced with new controllers that include remote monitoring and control 
    • Third, new grid control and switching equipment will be added to feeders in the 
         Program areas. This new equipment includes reclosers, capacitor banks, 
         automated tie switches and automated load‐break switches.  This new 
         equipment will have remote monitoring and control capabilities.  New 
         automated tie and load‐break switches will have local protection and control 
         logic that can be programmed remotely and their autonomous operation 
         requires the inclusion of peer‐to‐peer communications capability.  
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    •   Fourth, software applications deployed for the Program now include both 
        digital Outage Management System (OMS) and Distribution Management 
        System (DMS).  ARRA funding guidelines now appear to explicitly support these 
        systems and their inclusion will significantly enhance the value of the data that 
        will flow from the new smart endpoints.  Benefits include: 
        o allow distribution grid operators improved visibility into the operating 
            conditions on the grid;   
        o enable operators to evaluate alternative switching scenarios in near real 
            time to enable improved decision making;   
        o enable operators to identify, locate and determine the scope of outages 
            and other problems more quickly;   
        o enable operators to control grid equipment remotely to reconfigure the 
            grid to avoid outages and minimize the scope and duration of outages;   
        o optimize the control of  voltage and power factor on the grid to reduce 
        o enable modeling of the  impact that interconnection of renewable 
            generation and other distributed resources in increasing quantities will 
            have on the operation of  the distribution grid;   
        o enable the development and implementation of new dispatch and control 
            programs for distributed energy  resources; and  
        o identify changes in the operation of grid equipment to flag developing 
            problems, so that they can be resolved before the equipment fails. 
    •   Fifth, addition of substation EMS/SCADA at select substations where this 
        technology does not exist today.  The upgraded substations will provide an 
        expanded, real‐time view of the area and enhance the value of the distribution‐ 
        level smart grid data, by including substation performance data, which is a 
        fundamental piece of information on the overall distribution function. 
    •   Sixth, addition of digital monitoring and control breakers in Subtransmission 
        stations in the area of the smart deployment to support full grid automation.  
        The circuit breakers identified for replacement are older breakers of 
        obsolescent technology.  They need to be replaced to ensure appropriate 
        protection for the area covered by the Smart Grid program. 
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       D. Smart Grid – Clean Energy Modules 
       The Program proposes to demonstrate the full vision of the New York energy 
blueprint includes a selected number of clean energy technology “modules”. Each 
technology is summarized and the logic and rationale for its inclusion is listed below, 
under the following categories: 
       • Photovoltaics (PV)  
       • Plug‐in Hybrid Vehicles/Electric Vehicles (PHEV/EVs)  
       • Energy Storage  
       • Wind Power  
       • Micro‐CHP  
       • Micro‐Grid  
       • Holistic Homes 
                The current plan for these clean technology modules reflects the 
       recently released final Funding Opportunity Announcements (FOA) from the US 
       Department of Energy. In particular, FOA number DE‐FOA‐0000036 (“Smart 
       Grid Demonstrations”) sets forth requirements that limit the total cost of 
       distributed energy resources and energy storage to 20% of the total program 
       costs. There is also a stronger emphasis on the integration of electric and plug‐
       in hybrid vehicles. Moreover, given the differences between DE‐FOA‐0000036 
       and DE‐FOA‐0000058 (“Smart Grid Investment Grant Program”), the emphasis 
       of the clean energy technology modules, and the Syracuse Program in general, 
       will be on integration of the modules with the Smart Grid Spine, both 
       technically and from a business model perspective. This will include the 
       development and deployment of additional functionality within the Spine to 
       enable this integration, and to test other advanced Smart Grid technologies 
       and business model concepts. To be fully responsive to the DOE FOAs, the 
       Smart Program now envisions locating all of the modules in Syracuse. 
       i.       Photovoltaics (PV) Smart Grid Module – Scoping Description 
                Understand what effect a large penetration of photovoltaic (PV) would 
       have on the grid and how the Smart Grid would (i) help manage the impact and 
       (ii) take advantage of the presence of “Smart PV” (i.e., PV equipped with smart 
       inverters, and potentially, energy storage) to provide distribution system 
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         Prepare National Grid for the likelihood that PV will achieve high levels 
of market penetration in the future, when the levelized cost of electricity from 
PV begins to approach that of retail grid electricity. 
         PV – when installed with smart inverters, and energy storage – coupled 
with Smart Grid sensing and controls can provide asset deferral, peak shaving, 
voltage support, and improved reliability for the distribution system and to end 
users (if the PV is on the customer side of the meter). Without the sensing and 
control of the Smart Grid, the value of PV is limited to the energy displaced, in 
the form of reduced retail electricity purchases (if located behind the meter) or 
reduced marginal cost of supply (if located on the utility side of the meter). 
Additionally, current interconnection standards require PV systems to 
disconnect in the event of a network outage, which deprives the end user of 
one of the key benefits of onsite generation. A key objective for this 
demonstration will be to learn how to integrate PV and Smart Grid 
technologies to overcome this obstacle.  Coupled with smart inverters PV could 
also provide voltage control to the local distribution system.  Energy storage 
controlled by the Smart Grid and integrated with PV could manage the ramping 
and intermittency of PV output and shift the PV peak to be coincident with 
demand peak, thereby providing firm renewable capacity, which will aid the 
utility in integrating the presence of PV with it operations and with capital 
         PV technology is reliable and well proven. The key barriers to PV have 
been high installed costs and the intermittent and variable nature of the 
output. However, the global PV industry has achieved sustained annual sales 
growth rates of 30‐50% (80% from 2007 to 2008), and it is on a pathway to cost 
reductions and performance improvements that increase the likelihood that PV 
will achieve cost parity with retail electricity in the next 10‐15 years.  When this 
occurs, PV market penetration is expected to expand rapidly. This module will 
focus on demonstrating how the Smart Grid can manage ever higher 
concentrations of PV on the grid and how the Smart Grid can help unlock 
additional value by having that PV on the grid. The Smart Grid can also perform 
critical tasks with respect to tracking the environmental attributes of PV, which 
will become increasingly important within the evolving state, regional, national 
and international renewable energy and climate change policy frameworks. 
Testing these capabilities will also be a focus of this module 
         National Grid affiliates have the ability to own and operate PV in 
Massachusetts.  Detailed planning is currently underway for a 5 MW 
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deployment, which will grow to 50 MW.   The deployment and operational 
knowledge gained from this deployment can be applied directly to New York.    
Approach to achieving the objective 
         The plan for this module involves deploying a sufficient amount of 
“Smart PV” capacity (i.e., PV with a smart inverter and energy storage) in a 
small enough geographic area in order to observe and understand the grid‐
level impacts, to measure the ability of the Smart Grid to mitigating these 
impacts and to use the Smart PV to the overall benefit of the grid.  
National Grid anticipates procuring and deploying approximately 1 MW of PV, 
all of which would be equipped with smart inverters and 25% of which would 
be equipped with energy storage. The PV would be installed on a small number 
of feeders, all on the same substation, to give the desired level of 
concentration. In addition, National Grid proposes to provide monitoring, via 
the Smart Grid, to customers with PV installations.   The Smart Grid would be 
used to sense and control the PV systems and to make decisions about 
charging and dispatching the energy storage based on local system conditions. 
         National Grid is in confidential discussions with several potential 
partners including equipment suppliers, installers, and small start‐ups.  By 
working with New York companies, entrepreneurs, and universities, National 
Grid believes that Smart Grid‐enabled PV could provide opportunities for New 
York State to create jobs in the green economy.  
Scale and configuration 
• 1 MW total PV capacity (with smart inverters) in Syracuse 
• 250 kW of PV equipped with energy storage in Syracuse 
• Individual installations would range from residential scale systems (1‐3 kW) 
     to commercial building scale systems (100‐200 kW).  Approximately 20‐30 
     PV systems would be installed, depending on the mix of sizes 
• Smart Grid monitoring and controls 
• Capex ‐                    for PV systems, fully installed (including smart 
     inverters and energy storage), including the investment required for full 
     integration with the Smart Grid Spine 
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•   Opex ‐             for project management, monitoring, reporting, 
    operations, and supporting research & development needed for full 
    deployment of this module 
ii.      PHEV/EV Smart Grid Module – Scoping Description 
         Understand what effect a large penetration of PHEVs/EVs would have 
on the grid and how the Smart Grid would (i) help manage the impact and (ii) 
take advantage of the presence of PHEVs/EVs on the grid (e.g., peak load 
management).  Examine the interface between the Smart Grid and PHEVs/EVs, 
including how this enables different delivery models, including green charging 
and smart charging.  Prepare National Grid for the likelihood that PHEVs/EVs 
will achieve high levels of market penetration in the near future. 
         PHEVs/EVs, especially when integrated with the Smart Grid, would 
provide benefits to utilities, ratepayers and society at large. Electric 
transportation would reduce New York’s dependence on foreign oil, decrease 
the fuel cost of transportation for end users, and reduce greenhouse gas and 
criteria pollutant emissions, especially as the carbon intensity of power 
generation decreases in the future. The United States Congress is moving closer 
to enacting landmark climate change legislation that would have profound 
implications for energy consumption. Electric vehicles are likely to play a major 
role in achieving greenhouse gas reductions, and National Grid must prepare 
for this eventuality. The US Department of Energy has long had petroleum 
reduction as one of its primary strategic objectives. Energy security, as 
measured by the amount of electricity consumed by “smart‐grid enabled” 
electric vehicles, is specifically listed as a benefit to be tracked in the DOE’s 
Smart Grid Demonstrations FOA (DE‐FOA‐000036). 
         With adequate sensing and control, PHEVs/EVs could also provide 
many, if not all, of the grid‐level benefits of fixed energy storage. By working 
with New York companies, entrepreneurs, and universities, electric 
transportation could provide opportunities for New York State to create jobs in 
the green economy. 
         National Grid has long been a leader in alternative fueled vehicles with 
extensive experience using compressed natural gas vehicles in our own fleet. 
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National Grid has had as many as 800 CNG fleet vehicles and owns 13 fueling 
stations (8 in New York, 3 in Massachusetts, and 2 in Rhode Island). National 
Grid is currently working with Ford, EPRI, and a consortium including NYSERDA, 
ConEd, and NYPA on a demonstration of Ford’s Escape PHEV. The objective of 
the project is to understand the interface between these vehicles and the 
Smart Grid.  
        Currently, electric transportation faces cost and performance issues 
related mainly to battery technology. This situation is expected to improve in 
the future, given the intense interest and resources being directed towards 
battery technology. From the grid side, large‐scale deployment of electric 
transportation without the Smart Grid could require significant investments in 
generation (especially on‐peak), transmission, and distribution infrastructure. 
Conversely, marrying electricity transportation with the Smart Grid will allow 
for optimization of the entire system and create new opportunities for utilities 
and end users to take advantage of what will amount to significant distributed 
energy storage on the grid. This would avoid the need for much of the 
traditional investments that would otherwise be required to meet unmanaged 
increases in demand.  Deploying PHEVs/EVs as part of the Smart Grid 
demonstration program allows National rid to evaluate various service delivery 
models to effectively deal with the challenges and opportunities resulting from 
the large‐scale deployment of PHEVs/EVs, such as smart charging stations that 
allow PHEV/EV owners to charge their vehicles away from their homes or 
businesses and have the electrical usage be charged to their home or business 
accounts; franchised charging stations, similar to gas stations, where customers 
pay for charging services with cash or credit cards and charging station 
operators are billed by the utility; and idle PHEVs/EVs plugged into charging 
stations used as utility controlled energy storage devices.   
Approach to achieving the objective 
        The plan for the initial phase involves deploying a sufficiently large 
number of vehicles in a small enough geographic area, in order to observe and 
understand the grid‐level impacts and to measure the ability of the Smart Grid 
to mitigating these impacts and leverage the presence of the vehicles. 
        National Grid anticipates procuring and deploying approximately 175 
vehicles and installing two primary charging points per vehicle (one at a home 
and one at work for each vehicle), as well as a smaller number of charging 
points in public locations. The preference is for a partnership with one or more 
large local employers that could provide a sufficient level of vehicle 
concentration during the day. National Grid would identify and work with 
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    employees that have a range of commuting patterns in order to learn about the 
    costs and benefits of different control schemes, depending on vehicle usage. 
    Vehicle charging at night is expected to be less of an issue, but the ability to 
    sense and control charging at home in the early evening, when there may still 
    be a system‐wide peak, will also be part of the program. Thus, National Grid 
    will also endeavor to achieve a certain level of concentration of vehicles at 
    night. The Smart Grid would be used to sense, control, charge, and potentially 
    dispatch the onboard storage based on local system conditions. Given the 
    mobile nature of the application, the Smart Grid would also be used to manage 
    billing. Clearly, achieving seamless integration will be a key aspect of this 
             National Grid is in confidential discussions with several partners 
    including small start‐ups with potential manufacturing facilities in New York, 
    national labs, vehicle OEMs, and universities. The small start‐ups would provide 
    the vehicles, which could be EVs, aftermarket conversions of existing HEVs, or 
    production PHEVs. They would have the capability to deliver the vehicles in the 
    quantity required in a short period of time. National labs and universities would 
    be engaged to provide some of the intelligent hardware and software, identify 
    innovative solutions and applications, and to monitor and report results. 

    National Grid has also formed a partnership with Ford Motor Company on 
    the DOE's Transportation Electrification FOA (DE‐FA‐0000028).  National Grid is 
    a sub‐applicant with 15 other utilities. The proposal is to build and test 740 
    electric vehicles, including the necessary charging and electric distribution 
    infrastructure.  National Grid's cost share commitment is in the form of 
    infrastructure that will support charging of these vehicles (i.e., investments as 
    granted regulatory approval in this Filing). 

    Scale and configuration 
    • 175 vehicles deployed in a relatively narrow geographic area in Syracuse 
    • 2 primary charging points per vehicle, with a smaller number of additional 
       charging points in public locations 
    • Most vehicles will be light duty vehicles (to control costs and maximize the 
       number of vehicles)  but the program may include a small number of heavy 
       duty vehicles (i.e., vans, buses) 
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• Capex ‐                   for PHEVs/EVs, charging points, and additional 
     upgrades to the Spine necessary to integrate the vehicles and charging 
• Opex ‐                 for project management, R&D activities, monitoring, 
     reporting and operations (includes vehicle operations and maintenance) 
iii.     Energy Storage Smart Grid Module – Scoping Description 
         Understand how the Smart Grid can be used to exploit energy storage 
technology.  Demonstrate the various applications of energy storage in the 
Smart Grid. 
         Energy storage coupled with Smart Grid sensing and controls can 
provide asset deferral, peak shaving, voltage support, and improved reliability 
for the distribution system.  Energy storage would also be an important tool for 
managing increased penetration of intermittent renewable generation and 
charging of PHEVs/EVs.  By working with New York companies, entrepreneurs, 
and universities, National Grid believes energy storage could provide 
opportunities for New York State to create jobs in the green economy.   
         The key barriers to energy storage have been installed costs and life of 
the technology.  Energy storage has many different applications and benefits, 
but the most promising applications require close integration with utility 
operations and assets.  With billions of dollars invested in the last decade, 
driven in large part by consumer electronics, and more recently, electric and 
hybrid vehicles, energy storage technology may be on a pathway to commercial 
viability for many other products, including fixed energy storage for utility 
applications. This module would focus on demonstrating the best applications 
for energy storage, with a focus on tight integration with National Grid’s 
distribution system via the Smart Grid.   
         National Grid and National Grid affiliates have been working on several 
demonstrations of energy storage including (1) a frequency regulation 
demonstration with Beacon Power in Massachusetts, and (2) a zinc bromide 
battery integrated with a PV system at Niagara Falls with the New York State 
Parks Department.  Working with the DOE, National Grid affiliates also recently 
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completed an assessment of energy storage in the Northeast, which identified 
the most promising technologies and applications.   
Approach to achieving the objective 
         National Grid would procure and install energy storage units (150kw to 
2MW) within its system on feeders near peak capacity, long feeders vulnerable 
to weather related outages, or other areas where voltage support is needed or 
reliability is an issue. As detailed deployment plans for the other modules are 
developed, this will also be factored into the choices made for siting energy 
storage. The Smart Grid would be used to sense, control, charge, and dispatch 
this energy storage based on local system conditions. National Grid is currently 
in detailed technical discussions with energy storage suppliers including 
developing the technical specifications, sizing of units (MWs and MWhrs), and 
potential locations.   
         National Grid is in confidential discussions with several partners 
including small start‐ups, national labs, and universities.  The small start‐ups 
would provide the energy storage technologies.  These potential partners have 
detailed plans for ramp‐up including hiring and facility expansion, which we 
believe are achievable.  National labs and universities would be engaged to 
study and select the best locations, identify innovative solutions and 
applications, and to monitor and report results. 
Scale and configuration 
• 4 MW total capacity (with 1‐6 hours of energy storage) in Syracuse 
• Individual installations would be 150 kW to 2 MW in size 
• Capex ‐                     for energy storage equipment and installation, 
    including the necessary additional investment in the Spine to fully integrate 
    the energy storage equipment 
• Opex ‐                   for project management, R&D activities, monitoring, 
    reporting and operations (including electricity for round trip efficiency of 
    energy storage) 
iv.      Wind Power Smart Grid Module – Scoping Description 
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         Conduct research into the role of the Smart Grid with respect to 
integration of both utility‐scale and distributed wind power resources. 
         In the last 3‐5 years, wind power has emerged as one of the most 
significant sources of new power generation capacity in the United States – in 
2008 alone, more than 8 GW were installed, and a total of 27GW were installed 
worldwide. Despite the financial crisis, in the United States 2.8 GW were 
installed in Q1 2009 and 3.4 GW are currently under construction. Almost all of 
this is capacity in the form of large‐scale wind farms, but some is also in the 
form of distributed wind, i.e., units ranging from less than 1 kW for residential 
applications to multi‐MW installations for so‐called “community wind” 
         As wind capacity continues to expand, integration of this highly variable 
resource is expected to become more of an issue.  Smart Grid has a role to play 
in this integration. Smart Grid sensing and controls can help optimize the 
integration of distributed wind power, and therefore provide asset deferral, 
load management, voltage support, and improved reliability. Other Smart Grid 
modules, such as energy storage, can facilitate the integration of bulk wind 
power capacity by serving as an alternative to traditional transmissions level 
         Wind power technology is reliable and well‐proven, and commercial 
systems exist that range in capacity from 400 Watts to larger than 3 MW. The 
key barriers to wind power have traditionally been high installed costs, the 
intermittent and variable nature of the output, and siting constraints due to 
transmission access, viewshed impacts and wildlife concerns. Nevertheless, the 
overall outlook for wind power is extremely favorable, and it is expected to 
continue to be the dominant source of new renewable power generation 
capacity for the next several years. New York State has seen a significant 
increase in wind power development upon the adoption of a Renewable 
Portfolio Standard (RPS).  
         National Grid has been actively engaged in discussions with 
stakeholders in New York State on wind integration.  National Grid affiliates 
also have experience in Rhode Island, where two customer‐owned wind 
turbines (one 660 kW unit and one 1.5 MW unit) have been interconnected. 
This experience will be brought to bear for this module. 
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Approach to achieving the objectives 
        The focus of this module is to conduct research into the role of the 
Smart Grid with respect to integration of both utility‐scale and distributed wind 
power resources. Integration of utility‐scale wind farms has traditionally been 
accomplished using conventional transmission solutions. Distributed wind 
power has been a niche market to date, and projects are typically addressed on 
a case‐by‐case basis. Nevertheless, the Smart Grid is expected to provide new 
and improved ways to address wind power integration, particularly as the 
amount of wind power capacity grows.  
For this module, National Grid intends to collaborate with a university (or 
possibly a consortium of research organizations) to study the role of the Smart 
Grid in wind power integration. 
        National Grid expects to partner with a New York State university to 
conduct the bulk of the research.  
Scale and configuration 
• Not applicable 
• Opex ‐              for research, project management, and reporting. 
v.      Micro Combined Heat and Power (Micro‐CHP) Module – Scoping 
        Understand how the Smart Grid can be used to exploit micro‐CHP 
technology, including utilizing micro‐CHP as a dispatchable resource and load 
management tool for demand side management (DSM).  Demonstrate the 
various applications of micro‐CHP in the Smart Grid for single family residences, 
multifamily residences, and light commercial & industrial customers. Various 
delivery mechanisms would also be tested in order to maximize customer value 
and penetration of micro‐CHP technology.  Utilize the smart grid capabilities to 
enhance and expand the development of the micro‐CHP technologies and 
expand the range of applications, including standby power, demand response 
and integration with renewable generation. 
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         Micro‐CHP coupled with Smart Grid sensing and controls can provide 
asset deferral, peak shaving, voltage support, standby power, reduced GHG 
emissions and improved reliability for the distribution system.  For customers, 
it can provide energy cost savings and improved power quality and reliability. 
The benefits to the distribution system include various capabilities under 
demand side management and load growth including increased spinning 
reserve generation and on site load management.  Micro‐CHP would also be an 
important tool for managing increased penetration of intermittent renewable 
generation on the grid.  By working with a large boiler manufacturer in New 
York, National Grid believes micro‐CHP could provide opportunities for New 
York State in the green economy.   
         The key barriers to micro‐CHP have been high capital costs, consumer 
knowledge and familiarity, and development of a qualified installer and service 
provider network. Utilizing micro‐CHP may result in more than a 30% reduction 
in fuel required for residential electricity generation, and produce enough 
electricity in a thermal load following configuration to reduce a homeowner’s 
annual electric consumption by about half.   Micro‐CHP may reduce CO2 
emissions as well as SOx, NOx and particulates associated with global warming 
by 60%.  Micro‐CHP may help electric utilities meet mandates requiring them 
to meet certain target reductions in emissions by certain dates.  Additionally, 
generating power close to the electric load reduces electricity losses associated 
with transmission over power lines. With adequate sensing and controls, the 
presence of micro‐CHP could provide the ability for utilities and power 
generators to defer investment in traditional generation, transmission and 
distribution assets. 
         The United States Environmental Protection Agency (EPA) has 
designated micro‐CHP as its first Climate Choice technology.  Climate Choice is 
an EPA partnership program that recognizes emerging technologies that have 
the potential to substantially reduce greenhouse gas emissions once they are 
more widely adopted.  EPA stresses the importance of micro‐CHP being 
adopted across the United States.  
         National Grid and National Grid affiliates have a long history of 
developing micro‐CHP technology. National Grid has been working on several 
demonstrations of recip‐engine based micro‐CHP technologies including              
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    worked with customers in Massachusetts to install 19 units at customer sites.  
    In addition, National Grid is demonstrating a fuel cell micro‐CHP unit in the 
    Albany region with Plug Power.  National Grid affiliates entered into an 
    agreement with a Sterling engine manufacturer (DISENCO) to assist in 
    demonstrating five of their units.   
    Approach to achieving the objective 
            National Grid would procure and install micro‐CHP units (1.2kw to 25 
    kw) at 60 customer sites.  The Smart Grid would be used to sense and control 
    the generator and customer loads and dispatch the electric generation based 
    on local system conditions.   National Grid is currently in detailed technical 
    discussions with micro‐CHP manufacturers including developing the technical 
    specifications, operational characteristic of units, and potential applications 
    and business models.   
            National Grid is in confidential discussions with several partners 
    including a NY based boiler manufacturer, small start ups and international 
    companies expanding their products and services to the US market.   
    Scale and configuration 
    • 60 micro‐CHP units  with a total capacity of approximately 400 kW in 
    • Individual installations would range in size from 1.2 kW  to 25 kW.  
    • Capex ‐                 for micro‐CHP equipment and installation, including the 
        necessary additional investments in the Spine to fully integrate the micro‐
        CHP equipment 
    • Opex ‐                 for project management, R&D activities, monitoring, 
        reporting and operations. 

    vi.    Micro‐Grid Smart Grid Module – Scoping Description 
           Demonstrate that a collection of distributed resources and loads can be 
    integrated and controlled together in a local energy network to optimize the 
    system to reduce costs, reduce carbon footprint, reduce peak demand, and 
    improve local reliability.  Demonstrate that this local energy network can 
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              disconnect and operate independently (i.e., islanded) from the rest of the 
              distribution system, and can resynchronize with the grid.  Understand how the 
              Smart Grid can be used to control the resources within the micro‐grid and 
              integrate this local energy network with the larger energy system, to the 
              benefit of both the loads within the micro‐grid and the larger distribution 
                       The future utility system may involve a diverse group of local generation 
              resources including energy storage, PV, and CHP working together with local 
              dynamic load resources including PHEVs/EVs and demand response in a local 
              energy network or micro‐grid.  A micro‐grid is an integrated energy system 
              consisting of interconnected loads and distributed energy resources which, as 
              an integrated system, can operate in parallel with the grid or in an intentional 
              island model13.  Micro‐grids could provide greater flexibility and optimization of 
              generation, loads, and the larger (macro‐grid) power system to create a system 
              that is: 
              • Flexible in how the power delivery system is configured and operated.   
              • Optimized for lowest carbon footprint, lowest peak demand and highest 
                  reliability at the lowest possible cost to customers. 
                       Local generation and local resources all have strengths and weaknesses, 
              but as a package, these resources complement one another, mitigating 
              weaknesses and exploiting strengths.  A micro‐grid approach would likely be 
              more economic than deploying the individual resources alone.  
                       There have been several demonstrations of micro‐grid technology in the 
              United States (e.g., CERTS micro‐grid at AEP’s Dolan Labs), Canada, Europe and 
              Japan.  These have been, for the most part, laboratory demonstrations.  The 
              barrier to wide‐scale penetration of micro‐grids is the cost and availability of 
              the underlying component technologies, the cost of integrating these 
              technologies, and getting a critical mass of the resources in one geographic 
              area to make the macro‐grid viable.  The costs for the underlying technologies 
              may be undergoing dramatic reductions over the next 5 years.  The National 
              Grid Smart Program could prove to be a low cost approach to operating a 
  Final Report Microgrids Research Assessment for the US Department of Energy’s Office of Electricity 
Delivery and Energy Reliability and the California Energy Commission’s Public Interest Energy Research 
Program, May 2006 
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micro‐grid and the proposed program would offer many opportunities to gain 
critical mass of local resources.     
Approach to achieving the objective 
         This module is different from the others in that it would “bring all of it 
together”, that is, all the resources discussed in the preceding modules into a 
single locally operated system.  National Grid would look for opportunities to 
demonstrate a utility‐scale micro‐grid or a customer‐scale micro‐grid.  For the 
utility‐scale micro‐grid, National Grid would look for areas where there are 
large penetrations of resources resulting from the deployment of the other 
modules.  Opportunities with customers would also be examined, where 
customers who were interested in reducing their carbon footprint, reducing 
energy costs, or increasing reliability would be deploying local resources or 
electric vehicles.  National Grid would either deploy a local control system or 
use its Smart Grid assets to control and operate the micro‐grid, including 
dispatching generation resources, controlling loads, making decisions about 
islanding and resynchronization, and smart charging vehicles.   
         National Grid is in confidential discussions with micro‐grid technology 
suppliers and customers who could host or participate in a micro‐grid 
Scale and configuration 
• A local distribution system with approximately 5‐10 MW of peak demand 
     with generation resources of about 2‐5 MW.  
• Capex ‐                  for micro‐grid technology procurement and installation 
     (generation, energy storage, load control) and additional Smart Grid Spine 
     functionality to interface between the micro‐grid and the distribution 
• Opex ‐                  for project management, R&D activities, monitoring, 
     reporting and micro‐grid operations  
vii.     Holistic Homes Module – Scoping Description 
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        Just as the micro‐grid combines multiple technologies to achieve a 
higher level of benefits, it is possible to combine an array of technologies 
within the home to achieve greater benefits to the utility, society and 
customers. In particular, this module seeks to integrate the individual 
technologies described in the preceding modules into existing homes, thereby 
making it possible for these homes to become net zero (or near net zero) 
energy homes. In order to fully realize the benefits of the Smart Grid concept, 
connected buildings and all utility grids clearly need to be operated 
synergistically.  In order to evaluate and scale the ultimate potential for the 
Smart Grid, it is necessary to understand the potential benefits of the 
coordinated operation of utility grids and all advanced technologies in homes 
and small businesses.  It is therefore proposed to retrofit or incorporate in 
twenty (20) single‐family homes the following technologies: 
    Home Automation and Energy Management with Remote Access, Alarm & 
    Hybrid Heating & Cooling and Domestic Water, Swimming Pool and Patio 
    Advanced Appliances & Lighting with IP control and Automatic Load Centers 
    Advanced Building Envelopes (glass, insulation , sealing , ventilation 
    w/Indoor air quality monitoring) 
    Photovoltaic Generation & Architectural Wind Generation 
    Advanced Evacuated‐tube Solar Hot Water 
    Micro‐Combined Heat & Power & Back‐up Power 
    Energy Storage (Electric & Thermal) 
    Vehicle Fueling (Electric/Plug‐in Hybrid or Slow‐fill CNG Compressor) 
Each of these technologies offers (1) Increased functionality and daily energy 
choices for customers, (2) Options for distribution utilities to manage their 
assets under varied conditions, (3) Potential for dramatic environmental 
improvement, and  (4) Opportunities to accomplish these goals at declining 
unit costs as technologies proliferate.  The heart of this concept is a home 
automation system closely integrated with the Smart‐Grid. The end result could 
be an integrated system that ultimately leverages the Smart Grid to enable a 
new customer‐focused energy industry born in New York. 
        A holistic building today will lead ultimately to a zero‐net carbon 
building as renewable energy technology continues to develop.  This evaluation 
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              of the holistic home concept will for the first time consider the potential for 
              these concepts as a whole, rather than in discrete parts.  This evaluation will 
              lead directly to economically framing the possibilities and costs for all New York 
              utility customers.   
                       All of these unique parts currently exist, but have never been integrated 
              in a planned manner.  Deployment of these technologies will probably be 
              driven by new construction or major rehabilitation projects.  According to the 
              ENERGY STAR program in 200714, there were approximately 16,000 new single 
              family homes built in NY State with 15%, or nearly 2,500, being ENERGY STAR. 
              New York’s percentage of new construction is lower than the national average, 
              yet the data shows that if the energy savings from a home can be tripled, New 
              York could lead the nation in residential energy savings in new homes. 
              Nevertheless, because the vast majority of homes are existing homes, this 
              module targets deploying the holistic home module within existing homes in 
              the Smart Grid Spine deployment area.  
                       The holistic home concept can do more than save energy. It can provide 
              a range of desirable features that customers want or need, and can thus 
              tolerate a lower benefit‐cost‐ratio by allowing new advanced systems to 
              leverage the Smart Grid investment.  For example, home monitoring, while 
              giving customers major opportunities to manage energy costs, also allow 
              customers to monitor their most valuable asset and be alerted to threats from 
              hazards and accidents, such as equipment failure, flood or fire.  
                       National Grid is the only New York utility that has substantial experience 
              with all of the proposed technologies in a holistic home. Of the most relevance 
              is National Grid’s extensive experience with home monitoring and home 
              automation.  National Grid has developed a spectrum of customer propositions 
              around these technologies from simple telephone monitoring and control 
              systems to sophisticated internet‐based home management systems. National 
              Grid also has substantial experience with small renewable applications as well 
              as deployment of small advanced heating and cooling systems and 
              cogeneration products.   National Grid also has extensive experience in all 
              alternative motor fuel vehicle concepts.  These technologies are also being 
              addressed though the deployment of the Spine and the other modules. In 
              essence, the holistic home module is an opportunity to bring these 
              technologies together to create a vision of the home of the future. In each 
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case, the barriers are first‐cost and a scarcity of competitive products and 
related services.   
Approach to achieving the objective 
        A coalition to define and develop the holistic home concept will be 
assembled. The coalition will include relevant industries, universities and 
federal and state government agencies. National Grid will manage all work and 
oversee the installation, marketing, customer recruitment and operation in all 
        New York is home to major manufacturers or service providers for 
nearly all components of a fully holistic home including the following:  
    New York Based Green Architectural Firms 
    New York Based Home Builders 
    New York Based home‐automation and Energy Management System 
    New York Colleges and Universities that have participated in the Solar 
    New York Based‐Information Technology and Telecommunication Service 
    New York Based Heating and Air Conditioning Manufacturers and Service 
    New York  Based Green Energy Markers (electric & gas) 
    Light‐duty vehicle dealers offering EV, PHEV or CNG Vehicles and Systems 
Scale and configuration 
        For this module National Grid proposes to retrofit and incorporate this 
technology in 20 existing homes in the Syracuse.   
• Capex:                  for retrofitting twenty homes with all component 
    technologies and installing additional smart grid functionality necessary to 
    fully integrate the module with the Spine 
• Opex:                 for design, R&D activities, analysis, monitoring, 
    prototypes and project management 
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       The delivery of an IS Solution for the Smart Program will impact the existing 
applications and also introduce new applications to the existing National Grid IS 
landscape. Application integration forms a critical part for an end‐to‐end technological 
solution because a majority of the applications that comprise the IS Solution will be 
involved either in sharing data or connecting processes.  As the following technical 
model below indicates, there are a number of systems that must work seamlessly with 
each other for the Smart Grid to function.  Additional details on the IS solution for the 
Smart Program are provided in Attachment 12 hereto entitled Information Systems 

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i. New Applications 
   New applications were identified during the vendor evaluation sessions for 
each specific service layer within the Technical Model:   
Service Layer             Activity/Function          Technology/Software 

                                              •   RF  
S1 – HAN / LAN 
                          Communications      •   Fiber‐optic, microware, Wi‐
/ WAN 

                                              •   Head end software 
S2 – Meter                AMI Meter Head 
                          end                 •   Back office integration 
Services                  Meter Data 
                                              •   Meter Data Management 

                          Customer Billing    •   Billing software 

                   •   GRID Head end          •   SCADA software and 
S3 – Grid Data 
Management         •   DMS & Grid Analytics       repository 
                   •   Grid Analytics         •   Analytics software 

S4 – Enterprise 
Integration and           Middleware          •   EAI and BPM tool 

S5 – Web           •   Home Automation 
solution               Head end               •   Customer‐facing energy 
S6 – Messaging  •      Web Presentation           conservation tool 

S7 – Mobile        •   Messaging & Mobile 
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Service Layer            Activity/Function           Technology/Software 

Devices              Services 

Warehouse &              Business KPIs and  •    Data Warehouse 
Business                 Metrics            •    Reporting and Metrics tools 

                         Process modeling  •     Process modeling software 

ii. Existing Applications 
     In addition to installation, integration and testing new applications, some 
work will be required to modify the existing legacy applications to support the 
new business processes and the new applications for the Program.  If a decision 
is made to conduct a full rollout of Smart Grid to all customers, the existing 
legacy systems may not be suitable for that larger deployment.  Analysis has 
been conducted to define the present state, the desired or target state and the 
gap between them for the Program, as presented in Attachment 9 hereto.   
iii. Data Impacts 
     New Smart Grid services will impact both the flow and the volume of data 
that must be exchanged and processed within IS.  Data impacts have been 
modeled based on the envisioned future state of the information system 
needed to meet the Smart Grid objectives and includes the data subject areas 
from the current systems and future subject areas that will form the end 
solution.  This information was gathered based on discussions with National 
Grid IS and business teams and through vendor discussions for the Smart Grid 
Project.  Industry standard methodologies and data modeling best practices 
were also used to create the data model.  See Attachment 13 hereto entitled 
High Level Data Model. 
iv. Integration 
     National Grid will use an Enterprise Service Bus (ESB)/ Business Process 
Management (BPM) integration strategy to support its Program roll out.  The 
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ESB unifies message oriented, event driven and service oriented approaches for 
integrating applications and services.  BPM helps redefine and improve existing 
business processes.  The ESB will be a core part of the system and will be the 
central transport and interface mechanism for all related systems.  The ESB 
component includes substantial work to implement a robust, fully fault tolerant 
bus‐based architecture and industry standard messaging design.  
    The BPM will be able to constantly capture and track sub‐second real‐time 
information on the processes that it is managing, and it will also be able to 
monitor and track a broad variety of events.  The BPM will be scalable, multi‐
platform, multilingual and middleware‐agnostic.  
    Existing interfaces used as part of the technical solution will remain as 
point‐to‐point interfaces.  Attachment 14 hereto, Integration Outline, provides 
additional information. 
v. Hardware and Software Specifications 
    National Grid’s vendor evaluation workshop sessions evaluated vendor 
responses for each service layer by Subject‐Matter experts (“SME”) to 
determine the best option for the IS and Communications Smart Solution.  The 
hardware and software specifications will require further analysis as the final 
technology solutions are matched against the Program objectives.  Attachment 
15 hereto, Hardware and Software Specification, provides additional details 
vi. Security 
    As noted earlier, a key element in the evolution of the Smart Grid is the 
convergence of the electrical power infrastructure, communications 
infrastructure, and the supporting information system infrastructure.  The 
security framework that addresses these must take into consideration the 
needs of all parties.  National Grid will integrate various existing networks, 
systems, and touch‐points that are capable of exchanging information 
seamlessly.  The older proprietary and often manual methods of securing utility 
services will disappear as each is replaced by more open, automated and 
networked solutions.  
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           Some of the unique security challenges of the Smart Grid include: 
       •   Smart Metering and Home Automation touch every customer 
       •   Smart Metering and Smart Grid solutions are “command and control” 
       • Millions of controllable end‐points will be added along the infrastructure 
       • Almost every enterprise system will be impacted 
           As noted earlier, National Grid has a robust plan to address security.  The 
       following high level security objectives provide further insight into the key 
       objective of that program: 
       • Availability: avoid denial of service 
       • Integrity: avoid unauthorized modification 
       • Confidentiality: avoid disclosure 
       • Authenticity: avoid spoofing/forgery 
       • Access control: avoid unauthorized usage 
       • Audit ability: avoid undetected access 
       • Accountability: avoid denial of responsibility 
       • Third party protection: avoid attacks on others  
       A detailed Security Framework can be found in Attachment 16 hereto 

       The preliminary analysis for the Program (Spine) projects a $190 million 
operating and capital expenditure requirement.  The breakout of this total expenditure 
by category is as follows: 
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A.     Cost‐Benefit Analysis Strategy 
         Given the limitations inherent in a relatively small deployment of capital‐
intensive technology, the analysis must focus on a full deployment.  There are several 
reasons for this approach.  First, there is an inherent inability to achieve economies of 
scale in a relatively small Program.  In the absence of a larger purchasing guarantee, 
vendors set their equipment prices to accommodate a higher cost per unit.  For 
example, 82,000 meters are much more expensive per unit than 1.6 million meters.  
Additionally, the fixed costs associated with project management and information 
technology will inflate the relative economics of the Program versus the economics of 
a full deployment.  Second, many of the benefits that flow from a Smart Grid cannot 
be actualized in Program deployment, including labor savings and wholesale business 
improvements that reduce the need for certain assets.  Lastly, many of the operational 
benefits of a Smart Grid are achieved over a much longer period as Smart Grid enabled 
information is gathered and analyzed, and the resulting improvements are applied.  
For these reasons, National Grid has prepared an initial full deployment cost‐benefit 
analysis to inform its decision on the cost of the Program against the larger cost‐
benefit of a full deployment. Preliminary findings suggest that benefits will exceed 
costs for a full deployment and the Program will enable the Company to test some of 
its key assumptions.    
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B.     Financial Modeling Approach 
        The financial analysis was performed using a cost/benefit model that captures 
the overall economics of the project through incremental project financial analysis.  
The tool is Excel‐based and models monthly capital expenditures, operation and 
maintenance (O&M) expenses, and associated benefits for 2009‐2039, as well as 30‐
year net present values (NPVs).  The analysis does not attempt to model revenue 
recovery values or rate impacts; those elements will be developed by National Grid 
using outputs from the model.  The model has been used as part of a holistic 
integrated evaluation of various vendor proposals, proposal combinations, and overall 
cost/benefit analysis.  
C.      Full Deployment Cost‐Benefits 
        National Grid’s preliminary analysis projects a total capital requirement for a 
full deployment of                         on a current cost per meter basis).  The capital 
and operating expenditures result in an          per meter discounted value.  Using the 
January 2009 EPRI Report on achievable potential in Energy Efficiency and Demand 
Response, a five percent reduction in energy savings is considered a reasonable 
assumption.  National Grid incorporated these peak load and total consumption 
savings and a conservative approach to potential operational benefits into benefit 
analysis for a Smart Grid deployment across the entire National Grid service territory.  
A pretax net present value analysis was conducted to quantify these benefits using a 
discount rate of       percent.  The results of this analysis indicate a         per meter 
present value for a Smart Grid deployment across National Grid’s New York service 
territory.  Thus the net benefits of the preliminary Smart Grid analysis exceed its costs 
with a net present value of        per meter equating to          million net present value 
of benefits.  The benefits and their associated per meter net present values are listed 
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         National Grid believes the successful evaluation of Smart Grid and thus the 
Program proposal must demonstrate at a minimum a prudent framework with a strong 
possibility of positive benefits for all stakeholders.  While these finding are preliminary, 
National Grid believes the potential for significant load reduction will be enhanced by 
the Program’s tools.  In combination, the benefits listed in the chart above suggest a 
strong potential for value that exceeds cost for a full deployment.  A more detailed 
version of the model and the major assumptions can be found in Attachment 17 
hereto (Confidential). 
         This section describes the timeline and deployment plan National Grid 
proposes for the Smart Grid Program.  In addition to implementing the Program itself, 
the project team’s mission expressly includes working with customers and other 
stakeholder groups outside of National Grid as well as any affected department or 
business unit within the company to define new business processes or changes to 
existing processes required to support the Program, as well as training the appropriate 
National Grid personnel in the new solution.   
A.       Project Planning  
         The Program team evaluated several alternative approaches for implementing 
a Smart Grid Program, adopting best practices from similar projects at other utilities.  
The overall approach selected by the team is an “Integrated Functional Release” 
strategy in which National Grid implements key technology and enables associated 
functions in phases, each called a Release, building complexity and allowing National 
Grid to progressively enable, test and adapt to new Smart Grid technologies and 
business processes.  For example, Release One will test smart meter communications 
in the field on a limited number of residences while continuing to use existing meter 
reading and billing processes.  This will permit field testing of smart metering 
capabilities without potentially disrupting customers’ monthly bills.  Plans for each 
functional release are described below. 

The deployment timeline for the Clean Energy Modules will be individually assessed, 
but in general terms it is possible to prioritize some modules ahead of others an even 
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ahead of the Smart Grid spine, e.g., rapid introduction of PHEV’s can enable both quick 
wins for customers and programs that are “shovel ready”.    


Smart Grid will fundamentally change many aspects of National Grid’s business, 
making necessary and possible a greater degree of integration and increasing the 
exchange of information between customers, business units and supporting computer 
systems.  The Program project team will take an integrated and comprehensive 
approach, and will include key participants from all affected areas of the business.  A 
core group of the project team will focus throughout the Program deployment and 
beyond on refinements and adjustments, particularly as Smart Grid technologies 
change and evolve. 


B.       Deployment Timeline 
         The following table provides an overview of key milestones for the proposed 
Program.  For illustrative purposes, the chart below shows Month 0 as the Project start 
date.  It is assumed that National Grid has regulatory approval, the vendor equipment 
has met all internal safety and standards testing, vendor contracts have been signed 
and DOE contributions have been secured. 
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Phase                    Customer         National Grid           Phase Activities / 
/Release                 Capabilities     Capabilities            Release Functionality 
Proof Of      Pre –                       • Smart                 • Technical Proof of 
Concept       Month 0                        technologies lab       Concept 
                                                                  • Integrated requirements 
                                                                    and logical design 
                                                                    workshops in key 
                                                                    business areas 
Regulatory    Month 0                                             Regulatory Approval   
Advance      Month 1                          • Early order of    • Meters & 
Procurement  ‐ Month 4                          equipment            communications 
                                                                  • PHEVs 
                                                                  • Energy Storage 
                                                                  • PV 
Release 1     Month 7    • Selected         • Field testing of  • 250 Meters are installed 
                           customers          Smart Meters and    (dual socket) at selected 
                           participate in     communications      customer’s premises 
                           field trials of  • Interval meter    • Retain current AMR 
                           smart services  reading and            meter reading process 
                           and                testing           • Meter Head End 
                           technologies  • Analysis and           Communication 
                                              Design for        • Basic Functionality Meter 
                                              Modules             Data Management 
                                                                • Initial Communications 
Release 2     Month 12  • Electric        • Updated               • More MDM Functionality 
                          consumption       processes and           including Integration with 
                          information       systems to              Current Billing 
                          available on      support Smart         • Field Deployment 
                          Home Display      Services                Processes and Tools 
                        • Education on      deployment and        • Basic Home Automation 
                          smart             installation            (Limited Info on Home 
                          programs and    • Interval meter          Display) 
                          consumption       reading used for      • Device Life‐Cycle 
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                                              • Automatic outage     Management for 
                                                notification         Communications, Meter, 
                                              • Ability to verify    and Grid 
                                                customer outage    • Basic Grid Operations 
                                                and restoration      (OMS, EMS) 
                                                                   • Expansion of 
                                                                     Communication Network 
                                                                   • Begin Initial Benefits 
Grid           Month 1  •                    • Grid devices          •      Grid Automation and 
Modifications  – Month                         installed                 Monitoring Construction 
Syracuse       23                            • Monitor                   Complete for Program 
                                               distribution grid  
Meter and    Month 14  •                     • Smart meters          Beginning in approximately 
In‐Home      – Month                           installed               Month 14, meter 
Device       23                              • In Home devices         replacements would 
Deployments                                    installed               begin to ramp up in 
Syracuse                                                               Syracuse until ~40,000 
                                                                       Smart Meters are 
                                                                     •      Month 1 ‐ 500 
                                                                     •      Month 2 ‐ 1000 
                                                                     •      Month 3 – and 
                                                                       beyond 5000per Mo. 
Module           Month 17  • PHEV            • Energy Storage        • The installation of Smart 
Installations    – Month  • Large            • PV                      Modules will be installed 
Syracuse         27          customer                                  in parallel with the 
                             micro‐grid                                installation of the 
                                                                       common communications 
                                                                       infrastructure required to 
                                                                       support Smart Customer 
                                                                       and Grid facing services 
Grid           Month 12  •                   • Grid devices          • Grid Automation and 
Modifications  – Month                         installed               Monitoring Construction 
Capital        25                            • Monitor                 Complete for Program 
District                                       distribution grid  
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Meter and    Month 16  •                  • Smart meters          • Beginning in 
In‐Home      – Month                        installed               approximately 16, meter 
Device       25                           • In Home devices         replacements would begin 
Deployments                                 installed               and ramp up in the Capital 
Capital                                                             District until ~ 35,000 
District                                                            Smart Meters are 
                                                                    installed.  Installations will 
                                                                    ramp up to approximately 
                                                                    5,000 per month within 3 
                                                                    months of starting this 
                                          •                       • 
Release 3    Month 18  • New rate /       • Updated               • Customer Portal / Mobile 
                         customer           processes to            Device Capability 
                         programs           support smart         • Complex Billing and 
                       • Smart service      service programs        Complex Rates to support 
                         information        (enrollment             new Smart Service 
                         available          through billing)        Products 
                         through          • Two‐way               • Full Home Automation 
                         various            communication         • Initial Data Warehouse, 
                         means              with smart meters       including Reporting and 
                       • Education on     • Detailed analytics      Analytics 
                         smart              and reported          • Initial Demand Response 
                         programs and     • Fully deployed        • Load Monitoring 
                         consumption        monitoring and        • Expansion of 
                                            remote control of       Communication Network 
                                            grid equipment          Operations 
                                          • Automated outage      • Full Grid Operations 
                                            detection and           (DMS, OMS) 
                                          • Automated 
                                            voltage control 
Operate      Month 13                                             • For analytical purposes, 
Program      – Month                                                the Program location grid 
             51                                                     and customers are 
                                                                    measured and monitored 
                                                                    for 24 months after 
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                                                                        commissioning of all 
                                                                        assets.  This can be 
       A graphical depiction of this preliminary timeline is shown below.  

C.     Description of Release Phases  
        i.      Proof of Concept 
        During this pre‐release Proof of Concept phase, key Smart Grid technologies 
will be deployed in a laboratory environment in a coordinated process with the 
vendors.  This lab environment will enable National Grid to test components of the 
proposed Program solution from a technical and functional perspective to confirm 
expectations and to assess component compatibility.  Functional test cases, derived 
from the Company’s business requirements, will be developed and tested during this 
phase.  For example, demand response event messages to the customer will allow the 
team to observe and confirm or alter key processes and functions.  During the proof of 
concept phase, the technologies will only be tested with standard capabilities and 
some simulation of automated integration.  
        ii.     Release One 
        The objective of the first release is to test communications and smart meters in 
the field while continuing the parallel billing process with legacy systems. This parallel 
process enables us to learn from field deployments without exposing the customer to 
the potential problems associated with any learning process.   Approximately 250 
customers, located on the same distribution circuit, will have a Smart Meter installed 
next to their existing AMR meter.  Testing in this phase will cover the communications 
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network for the selected substation, the meter head end and the basic functionality of 
the meter data management system (MDMS) at the utility.  These systems will support 
communications testing with smart meters and the collection of interval meter reads.  
These tests will confirm reliability of communications and accuracy of remote meter 
readings, prior to using the Smart technology for customer billing.  Implementing a 
best practice learned from prior Smart Grid programs by other utilities, the 250 
customers selected for Release One testing will continue to be the core field testing 
group before future functionality is rolled out to the broader population served by the 
Program system. 
        iii.     Release Two 
        Release Two includes functionality that will enable National Grid to deploy the 
remaining 70,000 + meters, fully replacing the existing AMR meters at those 
residences and businesses.  Interval data will be recorded by the new smart meters 
and collected using the new head end and communications network.  Billing will be 
performed using the current systems using total consumption data aggregated in the 
new MDMS.  The field deployment team will also test new processes and systems to 
support smart meter replacements in the field, such as new processes to install and 
provide quality assurance, as well as, updates to the information systems to support 
the Smart Solutions such as work order, dispatch, asset management billing, etc.  The 
pace of replacing existing meters with smart meters will progressively increase over a 
several month period as National Grid identifies and resolves any issues in the logistics, 
installation, and activation process.  This approach will enable future large‐scale 
deployment of smart meters to be managed efficiently.  During the evaluation of other 
Smart Grid programs, National Grid found that each field crew could install between 
forty and eighty meters a day, depending on a variety of variables.  National Grid 
estimates that smart meter and in‐home device deployment in each Program area will 
be completed over a nine month period.  Immediately following the go live of Release 
2 functionality, meter installation will begin in Syracuse.  Approximately 3 months after 
the start of field deployment in Syracuse, deployment will begin in the Albany Capital 
District.  In each area, the Company will install the common communications network 
technology in parallel with smart meter installations.  The installation of Smart 
modifications to the distribution grid and the installation of Smart Modules will be 
coordinated with the installation of the communications network.  Additional 
functionality in Release Two will enable field testing of home display units, support for 
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grid monitoring and testing.  National Grid’s plan is to deploy Clean Energy Modules as 
soon as practically possible following the installation of the communications 
infrastructure and grid monitoring systems. 
        iv.    Release Three 
        Release Three will deliver the full range of capabilities planned for the Program.  
Customers will have the ability to monitor consumption on a home display unit or the 
Program web portal; establish energy saving modes to automatically control loads in 
their homes; and control and monitor load in their homes and businesses via mobile 
wireless devices.  From the distribution grid perspective, Release Three will enable 
remote monitoring, voltage optimization, sectionalizing and automated outage 
detection and restoration planning and confirmation.  This release will also enable 
smart grid embedded demand response.  As of this phase, full smart grid analytic, 
measurement and control functionality will be placed in service.  The full deployment 
of any remaining Clean Energy Modules will be staged to follow Release 3.   

D.     Summary 

       Smart Grid deployments are extremely complex.  National Grid will have to 
confirm the capabilities of new technology; make sure that new and legacy 
technologies work together; adapt the businesses processes; educate employees and 
customers; measure and test systems and security; and report progress throughout.  In 
order to accomplish these deployments in a condensed timeframe, the Program 
overlaps the functional releases and coordinates between multiple parallel activities.  
The Company has assembled a strong, experienced team.  National Grid is studying 
smart deployments in Europe, Canada, California, Texas, North Carolina and Florida to 
incorporate those lessons in the Company’s Smart Grid Deployment Program.       

       Smart Grid projects are composed of a large number of components provided 
by multiple suppliers.  These components must work together seamlessly in order to 
provide the desired value to consumers, utilities, regulators, and society at large.  In 
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addition, hardware, software and interoperability standards are still evolving.  These 
kinds of projects by their nature are inherently risky.  National Grid intends to actively 
manage the risks on the Smart Grid Program.  Active risk management of the Program 
will include an ongoing assessment to identify risk events that may occur in the future, 
developing contingency plans to reduce the likelihood of these risk events occurring, 
minimizing the impact of risk events on the program should they occur and dealing 
with them if they do occur.  Several key risk areas have been identified.  These, along 
with the contingency plan that addresses each, are summarized below:   
Risk Event                    Contingency Plan 
Customers do not elect to   In order to reduce the likelihood of this event occurring 
become engaged in the       National Grid will undertake secondary market research 
Smart Services offered by   as part of finalizing the design of its Smart Services 
National Grid.              offerings and marketing plan to assure that the services 
                            being offered are attractive to customers.  Once the 
                            marketing and enrollment process begins, opt‐out rates 
                            will be monitored weekly to identify unfavorable trends 
                            quickly so that contingency plans can be implemented 
                            quickly.   Contingency plans will be developed in advance 
                            of the launch, marketing and enrollment.  These 
                            contingency plans will include additional service elements 
                            and / or modifications to tariffs that can be introduced if 
                            necessary in order to improve customer sign‐up rates. 
Vendors are not able to     This event is likely to occur to some degree.  The 
deliver products to         contingency plan in place to deal with this situation 
support the project         includes: 
schedule or the delivered  • Conducting a proof of concept to validate functionality 
products do not perform  and compatibility of the technologies that will be 
as specified.               deployed. 
                            • Using technologies that utilize existing and evolving 
                            open standards to allow products from more than one 
                            vendor to be incorporated into the solution. 
                            • Phased approach for introducing new functionality to 
                            customers in a controlled manner that measures impact 
                            and manages exposure. 
The Smart Grid Program is  In order to reduce the likelihood of failure in each 
complex, involving a large  element of the Smart Grid Program, National Grid will: 
number of customers,        • Implement a proven Program and Project Management 
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Risk Event                    Contingency Plan 
utility business functions    approach across all aspects of the program. 
and technology                • Contract with vendors and service providers 
components.  Failures in      experienced in the design, manufacturing and installation 
any one of these areas        of Smart Solutions. 
can adversely impact          • Make effectively managing the customer experience 
project results.              aspects of the Program a high priority. 
Smart Grid Program is         National Grid will include cancellation provisions in 
cancelled prior to its        contracts with vendors and service providers engaged in 
completion or a decision      delivering the Smart Program.  If cancellation occurs after 
is made not to deploy the     the installation of smart meters and home automation 
Smart Solution beyond         devices, provisions have been made to remove and 
the initial Program.          replace this equipment with existing meter technology.  
                              Business process and information systems modified to 
                              accommodate the Program will be rolled back to pre‐
                              Program conditions. 
    A. Introduction 
    National Grid is proposing to make available to customers participating in the New 
York Smart Program (“Smart Program”) an alternative pricing structure (“Smart Grid 
Pricing”) for PSC No. 220 Electricity Tariff Rule No. 46 Electricity Supply Service (“Rule 
46”).  This portion of the Company’s proposal discusses how National Grid proposes to 
implement Smart Grid Pricing and the rate design underlying Smart Grid Pricing. 
    The Company proposes that Smart Grid Pricing consist of: (i) a Critical Peak Pricing 
Program (“CPPP”) for customers in non‐demand metered service classifications and (ii) 
and an Hourly Pricing Program (“HPP”) for customers in demand‐metered service 
classifications.  Customers on CPPP or HPP may opt out of the pricing programs before 
the programs start as discussed below.  The information and communication 
capabilities of Smart Grid technology will enable customers to enhance their potential 
savings through changes in behavior that move electricity consumption away from 
expensive time periods towards inexpensive periods. 
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    B. Eligibility for Smart Grid Pricing 
    The customers who will be enrolled into the Smart Program consist of a cross‐
section of customers receiving retail delivery service pursuant to National Grid’s tariffs 
for the following PSC No. 220 Electricity Tariff service classifications: 
        Residential and Farm Service, Service Classification No. 1 (“SC‐1”) 
        Residential and Farm Service ‐ Optional Large Time of Use Rate, Service 
        Classification No. 1‐C (“SC‐1C”) 
        Small General Service, Service Classification No. 2 (“SC‐2ND" for non‐demand 
        metered customers and “SC‐2D” for demand metered customers) 
        Large General Service, Service Classification No. 3 (“SC‐3”) 
        Large General Service ‐ Time of Use Rate, Service Classification No. 3A (“SC 3A”) 
        Untransformed Service to Certain Customers Taking Power from Projects of the 
        New York Power Authority, Service Classification No. 4 (“SC‐4”) 
        Sale of Standby Service to Customers with On‐Site Generation Facilities, Service 
        Classification No. 7 (“SC‐7”) 
    These customers must be receiving commodity service from the Company 
pursuant to its Rule 46 tariff to be eligible for Smart Grid Pricing.  Service classes SC‐1, 
SC‐1C, SC‐2ND and certain SC‐7 customers must be receiving, or elect to receive, 
Market Rate Service (“MRS”) under PSC No. 220 Electricity Tariff Rule No. 48 
Administration of Standard Rate Service and Market Rate Service (“Rule 48”) to qualify 
for CPPP.  Customers who are receiving commodity service from the New York Power 
Authority (“NYPA”) under PSC No. 220 Electricity Tariff Rule No. 34 Economic 
Development Programs (“Rule 34”), or under SC‐4 for a portion of their commodity 
service will not be eligible to receive CPPP or HPP for that portion of their service, but 
will be eligible to receive CPPP or HPP for that portion of their commodity service 
supplied by the Company under Rule 46.  Customers who are receiving delivery service 
under retail electric delivery service contracts under PSC No. 220 Electricity Tariff 
Service Classification Nos. 7, 11 (“SC‐11”)and 12 (“SC‐12”) are eligible for CPPP or HPP 
provided that such commodity service is permitted by the terms and conditions of 
their respective individual contracts. 
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     National Grid proposes that Rule 46 customers in the Smart Program service areas 
be placed on Smart Grid Pricing and have the opportunity to opt‐out if they do not 
want to take service under CPPP or HPP.  Customers on Smart Grid Pricing will be 
protected from bill increases on an annual basis.  The Company will determine the 
total cost of commodity service for each customer for each year under Smart Grid 
Pricing and the total cost of commodity service for each customer for each year under 
traditional Rule 46 rates and provide customers with a credit if the Smart Grid Pricing 
is more expensive for that year.  Customers will retain any savings if their annual bills 
on Smart Grid Pricing are less than their bills would be calculated under ordinary Rule 
46 rates.  Rule 46 customers who opt‐out from Smart Grid Pricing will receive 
commodity service under ordinary Rule 46 rates, but will be eligible for Peak Time 
Rebate (“PTR”) for any load reductions during critical peak periods.  
     C. Tariff Provisions 
     The Company will propose to amend its currently effective Rule 46 by adding 
provisions for Smart Grid Pricing.  A listing of the terms and conditions for Smart Grid 
Pricing that would be incorporated into proposed tariff changes are included in this 
filing in Attachment 18   
     National Grid proposes that New York Smart Program customers remain on Smart 
Grid Pricing for twelve consecutive months.  Although the Company would prefer to 
allow more flexibility in order to promote the operation of the competitive electricity 
market, the design of the wholesale capacity market and the term of service provisions 
for Market Rate Service (“MRS”) in the Company’s currently effective Rule 48 inform 
National Grid’s decision to have New York Smart Program customers remain on Smart 
Grid Pricing for at least one year in order to fulfill the customers’ obligation under the 
tariff.15   Specifically, the NYISO determines the Unforced Capacity Requirement 
(“UCAP”) for Load Serving Entities (“LSE’s”) based on each LSE’s contribution to the 
statewide annual system peak for each Capability Year ending April 30.  Thus, each 
customer of an LSE has associated with it a capacity tag representing that customer’s 
contribution toward the annual system peak load.  The monthly UCAP cost for these 
capacity tags moves with customers as they change LSE’s.  If customers choose an a 
different LSE for the summer months, their capacity tags will follow them.  This could 
result in a significant under‐recovery of Rule 46 UCAP costs associated with such 
customers during those months as their capacity obligations were determined the 
previous year. Thus, the Company proposes that customers remain on Smart Grid 
Pricing for twelve months to facilitate adequate recovery of Rule 46 costs. 
  Rule 48 requires that “a customer who voluntarily subscribes to Market Rate Service must remain on 
Market Rate service for a minimum of twelve consecutive months.” 
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    D. Rate Provisions and Design 
     As stated above, National Grid is proposing two alternative pricing structures as 
part of Smart Grid Pricing.  The first, CPPP, would be available to non‐demand metered 
residential and general service New York Smart Program customers receiving retail 
delivery service on service classes SC 1, SC‐1C, SC‐2ND and SC‐7.  The second, HPP, 
would only be available to general service New York Smart Program customers 
receiving retail delivery service under all other PSC No. 220 Electricity Tariff service 
classifications.  All New York Smart Program customers must be receiving Rule 46 
service to be eligible for Smart Grid Pricing.  In addition, special eligibility rules apply to 
certain customers receiving service under Rule 34, SC‐7, SC‐11, and SC‐12 as noted in § 
D.ii above. 
             i. Critical Peak Pricing Program 
     CPPP offers customers an opportunity to reduce their electrical load during a few 
important hours in a year and receive a significant reduction in their bills for doing so. 
Critical peak pricing is designed to recover most of the costs for generation capacity in 
the hours that have the greatest need for peak capacity.  Generation plant is built to 
meet load during the hours of highest demands with a reserve for emergencies during 
those times.  Typically, fewer than 1,000 hours a year produce the need for a 
significant amount of central station generation plants to be available to serve peak 
loads.  Attachment 19 contains load duration curves for New York State using hourly 
loads from data recorded at the NYISO for the years 2006‐2008.  Fewer than 250 hours 
in the year cause a need for 5,000 to 7,000 MW of capacity in the State This represents 
at least 20% of the system load at the time of the NYISO system peak in the last three 
years.  CPPP charges higher prices for those hours.  This provides two benefits.  First, 
the savings customers realize from shifting load away from the critical peak period is 
much more than traditional time‐of‐use (“TOU”) pricing structures would produce.  
Conventional TOU rates are characterized by very long on‐ and shoulder‐peak periods 
that result in lower capacity‐related prices over these time periods as capacity costs 
are spread over a longer period of time.  Second, customers are afforded a greater 
degree of flexibility in responding to price signals with critical peak pricing given the 
relatively few hours that high prices will be charged during a year. 
     In its Smart Grid Pricing for CPPP, National Grid proposes three seasons and four 
time‐of‐use periods with different prices for the CPPP for eligible New York Smart 
Program customers.  Both the seasons and the time periods are based on the 
definitions of those seasons and time periods currently in effect for SC‐1C and SC‐3A, 
the Company’s currently effective TOU rates.   
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    The seasons are defined as follows:  (1) Summer Season for the calendar months 
June through August; (2) Winter Season for the calendar months December through 
February; and (3) Off‐Season for the fall calendar months September through 
November and for the spring calendar months March through May. 
    The first time period is the off‐peak and off‐season period which has the lowest 
prices.  The off‐peak and off‐season period includes all hours during the Off‐Season; all 
weekends, holidays and weekday hours from 8:00 p.m. to 8:00 a.m. during the 
Summer Season; and all weekends, holidays and weekday hours from 8:00 p.m. to 
9:00 a.m. during the Winter Season.  The second period is the shoulder‐peak period.  
The shoulder peak period is defined as non holiday weekdays from 8:00 a.m. to 11:00 
a.m. and from 5:00 p.m. to 8:00 p.m. during the Summer Season, and non holiday 
weekdays from 9:00 a.m. to 5:00 p.m. during the Winter Season.  The third period is 
the on‐peak period.  The on‐peak period is defined as non holiday weekdays from 
11:00 a.m. to 5:00 p.m. during the Summer Season, and non holiday weekdays from 
5:00 p.m. to 8:00 p.m. during the Winter Season   These daily periods recognize that 
average electric energy prices are significantly higher during certain weekday hours 
during certain seasons of the year.  The fourth and final period is the critical peak 
period.  This is the feature that distinguishes critical peak pricing from time‐of‐use 
pricing.  Although the critical peak hours will occur on weekdays during the Summer 
and Winter Seasons, the exact times these hours occur cannot be predicted accurately 
and are, in fact, event driven.  Thus, no set definition of critical peak hours can be 
provided; rather such hours are “called” based on load and weather conditions 
expected in the next 24 hours.  For example, if the NYISO forecasts very high loads or 
peak conditions for the next day, National Grid will notify customers using Smart Grid 
technologies that electricity prices for the next day will be at much higher levels during 
a certain time of day.  
    The selection of days with critical peaks requires careful analysis of system loads 
from the NYISO.  National Grid employed a statistical technique called cluster analysis 
to place days into groups with similar peak loads.  Cluster analysis puts load levels into 
groups in a way that decreases the differences between loads within a group while 
increasing the difference between groups.  The cluster analysis used the peak load in 
each day for 2008.  The analysis resulted in 23 days falling into the cluster for the 
highest peaks, as shown in Attachment 20.  
    National Grid further reviewed the days identified by this analysis to define the 
number of hours for critical peak pricing.  The Company counted the number of hours 
in these critical peak days that were above 27,000 MW of load.  This approach is based 
upon a review of the daily load curve in each of these days.  Summer load patterns 
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have smoothed to a very flat pattern for peak days.  Thus, National Grid selected the 
hours above a load level that does not occur on any other day of the year except for 
the days in this grouping.  This results in a total of 163 hours for 2008.  Attachment 21 
provides the daily load shapes in New York in 2008 for those days that had the highest 
loads in the year. 
                    a. Design of CPPP Rates 
     National Grid proposes to offer CPPP as an alternative Rule 46 pricing option for 
commodity service provided to New York Smart Program customers.  The goal of the 
CPPP is to motivate customers to shift their electric usage away from peak‐priced 
hours or to simply using less electricity during those hours. 
     The Company proposes to design alternative Rule 46 pricing for CPPP using NYISO 
energy prices by load zone, then adding ancillary services costs and capacity costs to 
each hourly price, and finally adjusting the sum thereof for thermal and unaccounted 
for energy losses in a manner similar to the procedure National Grid follows to 
produce Rule 46 prices today.  These hourly prices are cross‐multiplied by each service 
class’s load shape to compute a load‐weighted moving average energy price for each 
CPPP period for each service class for each load zone for each 30‐day billing period.  
Syracuse Area customers are located in Load Zone C, and Capital District Area 
customers are in Load Zone F.  The principal difference between ordinary Rule 46 
pricing and critical peak Rule 46 pricing is the treatment of UCAP capacity costs.  In 
critical peak pricing, the UCAP costs are recovered over the critical peak hours, while 
ordinary Rule 46 pricing recovers such costs over the entire year albeit over a 
differently defined set of “on‐peak” hours. 
     National Grid used 2008 hourly loads and day‐ahead locational energy prices 
including ancillaries to simulate the average energy price in each period of the CPPP 
for illustrative purposes.  This simulation is shown in Attachment 23.  In the first step 
of the calculation, the average energy price is calculated by weighting each hourly 
energy price by the corresponding hourly load for the zone.  The next two steps sum 
the hourly cost and the hourly loads in each period in order to divide cost by load to 
determine the average energy price for the period. 
     For New York Smart Program customers, National Grid proposes to collect all costs 
for capacity in the critical peak period.  The addition of these costs to the otherwise 
applicable average energy prices for that period promotes price response and savings 
for customers who volunteer for CPPP and keep rates lower in the other periods.  
These are the hours in which the system peak load will occur and any load reduction 
by customers during these hours will save on the costs for incremental generation 
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capacity in the long term and reductions in the Company’s UCAP responsibility in the 
short term. 
     At the NYISO, an LSE’s annual capacity obligation for the next Capability Year 
ending April 30 is determined by its customers’ load at the time of the NYISO annual 
peak, which typically occurs during the summer months.  Each customer’s load at that 
time sets the capacity obligation for that customer.  This load is adjusted for reserve 
margin needs.  Finally, a projected monthly cost per kilowatt is estimated for the 
average of the results expected from the two forthcoming NYISO Capability Period 
capacity auctions, also known as the NYISO six‐month capacity strip auctions.  For 
illustrative purposes, this value is shown as $4.00 per kW.  An example of the monthly 
capacity charge calculation is shown in Attachment 22.  The annual cost for one kW is 
calculated and divided by the number of hours in the critical peak period for 2008 
(hours above 27,000 MW) or 163.  Attachment 22 provides the calculation of the 
illustrative per kWh capacity charge adder of $0.34686 to $0.36884 depending upon 
retail delivery voltage level.  Under National Grid’s proposal, the Company may call this 
price for not more than 8 hours duration per call and for up to 30 days per year 
provided that the total duration of called hours in the aggregate is 200 or less.  
     As discussed above, National Grid proposes to recover 100% of the capacity costs 
in the critical peak period, which will require the Company to forecast capacity costs 
for these periods.  The risk in this approach is that if the NYISO annual peak occurs 
outside the critical peak period, CPPP customers will not be instructed to reduce load 
and the anticipated next year capacity benefit for which they are being compensated 
in CPPP rates this year will be lost.  However, this is, in part, the purpose of the New 
York Smart Program, which is to provide the opportunity to study under real 
conditions: (i) whether critical peak pricing is effective; (ii) whether customers react 
significantly to the highest price in the critical peak period; and (iii) the various risk 
factors inherent in designing the CPPP. 
                      b. Peak Time Rebate 
     New York Smart Program customers who do not wish to participate in CPPP or HPP 
will be able to use Smart Grid technology to participate in a simpler option to reduce 
their electric bill through demand response.  Those customers may elect to participate 
in Smart Grid Pricing through the Peak Time Rebate program which permits such 
customers the opportunity to earn a rebate by reducing load during critical peak 
periods.  National Grid hopes to determine whether customers will be attracted by the 
simplicity of this offer and, if so, are there any distinguishing characteristics of this 
group of customers which led them to elect this option over CPPP or HPP. 
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     New York Smart Program customers who elect PTR will be charged for commodity 
service under ordinary Rule 46 rates applicable to their respective service class but will 
have the opportunity to earn a credit when notified of a critical peak period. The 
Company is proposing that the PTR credit be equal to the calculated per kWh capacity 
cost adder for the CPPP as shown in Attachment 22.  The same critical peak event 
calling restrictions that apply to CPPP would also apply to PTR. 
                      c. Hourly Pricing Program 
     Traditionally, large commercial and industrial customers have been served under 
more complex rate structures that provide greater opportunities for such customers to 
control their electricity charges.  In recent years, industry participants have debated 
whether, in a restructured electricity market, the rate structure underlying the 
provision of commodity service by a utility should be real time (or hourly) pricing.  
Certain jurisdictions require that larger customers be billed pursuant to a tariff or rate 
structure that charges for electric use based on hourly market prices.  New York is one 
such jurisdiction.  The Company serves its customers 500 kW and larger on a 
mandatory hourly pricing program through Rule 46.  
     With Smart Grid Pricing, National Grid proposes to expand mandatory hourly 
pricing to all demand‐metered customers in the Smart Program areas through HPP.  
Those customers selected for HPP may elect to opt‐out of this program and elect PTR 
consistent with the Company’s proposal for CPPP customers.  In addition, HPP 
customers will enjoy the same bill increase protections being provided to CPPP 
     Like CPPP customers, all HPP customers receive modified Rule 46 pricing with the 
otherwise applicable UCAP costs in ordinary Rule 46 rates stripped out and the new 
critical peak capacity adder substituted in its place.  When a critical peak event is 
called, the same critical peak capacity adder that is used for CPPP is added to the Rule 
46 day ahead locational based hourly market price plus ancillaries and the sum thereof 
is then adjusted for thermal and unaccounted for energy losses.  These higher prices 
remain in effect for the duration of the critical peak event.  At the conclusion of the 
event, the Rule 46 prices for HPP are reduced by the loss‐adjusted critical peak 
capacity adder.  The same critical peak event calling restrictions that apply to CPPP 
also apply to HPP. 
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         ii. Illustrative Rates 
    The rate and pricing calculations in this filing are illustrative only.  If the 
methodology is approved, a compliance filing will be made by National Grid to reflect 
any changes ordered by the Commission and the appropriate tariff leaves submitted. 
    E. Reconciliation of Smart Grid Pricing 
    The design of the rates in Smart Grid Pricing may result in differences between 
revenue billed and costs incurred for Rule 46.  The calculations used to design Smart 
Grid Pricing are more complex and rely more on projections than do the calculations 
for ordinary Rule 46.  Thus, it is possible that an over‐ or under‐collection of Rule 46 
costs may occur with this small group of Smart Program customers. 
    National Grid proposes to include the Rule 46 revenue generated from Smart 
Program customers with all other Rule 46 revenue for surcharge factor computation 
purposes.  Ordinarily, most differences between actual Rule 46 commodity costs 
incurred and Rule 46 commodity cost revenues received are reflected in the 
Commodity Adjustment Charge (“CAC”) applicable to Standard Rate Service (“SRS”) 
customers under PSC No. 220 Electricity Tariff Rule No. 29 Delivery Charge Adjustment 
(“Rule 29”).  In this instance, the Company believes that reconciling what will be 
principally capacity cost differences for MRS customers in the Smart Program through 
an adjustment mechanism for SRS customers is not appropriate.  Therefore, National 
Grid proposes to flow through any differences between actual Rule 46 capacity costs 
incurred by Smart Program customers and Rule 46 capacity cost revenues received 
from Smart Program customers in an adjustment to Rule 46 applicable to all Rule 46 
    F. Compliance of Proposed Smart Grid Pricing with Department of Energy Smart 
        Grid Investment Grant Program Funding Opportunity Announcement 
    Included in the U.S. Department of Energy (“DOE”) Smart Grid Investment Grant 
(“SGIG”) Program Funding Opportunity Announcement (“FOA”) of June 25, 2009 are 
Special Instructions for Applications Involving Advanced Metering with Dynamic Pricing 
and Randomization (“Special Instructions”).  Utility applications for funding under the 
SGIG that comply with these detailed instructions will be viewed more favorably by the 
DOE than applications which do not comply.  The instructions state:   
        “DOE is interested in advanced metering projects that involve dynamic pricing 
    and use a randomized control trial design. Randomization is important for 
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conducting cost‐benefit analysis of dynamic pricing because it allows for unbiased 
comparisons across customers.   
     There are two types of dynamic pricing – real‐time pricing and critical peak 
pricing – that come closest to aligning customer incentives with the true costs of 
providing power.  For these reasons, DOE is most interested in projects that involve 
some form of real time pricing or critical peak pricing.  
     In the ideal randomized control trial involving smart meters and dynamic 
pricing, smart meters would first be installed for all customers within a particular 
geographic area. . . .Next, customers within this geographic area would be 
randomly assigned start dates for dynamic pricing. . . .The DOE is most interested 
in applications in which some customers would remain on default tariffs for at least 
two years.  The randomization would need to take place at the customer level so 
all customers within the geographic area are equally likely to be in each group. 
     It is critical that smart meters be installed in the entire geographic area prior to 
the beginning of dynamic pricing because program evaluation depends on 
comparing hourly consumption between customers with and without dynamic 
pricing.  Applicants would need to make clear to customers that by the end of the 
project, all customers within the selected geographic area will face dynamic 
     DOE understands that there may be concerns from some customers about 
dynamic pricing. However, in order to avoid introducing selection bias that would 
hamper analysis of project costs and benefits, it is critical that dynamic pricing be 
applied on a mandatory basis.  Applicants would need to inform customers that 
dynamic pricing can offer substantial benefits in the form of reduced costs and 
improved reliability.  Under dynamic pricing, customers would face higher prices 
during a small number of hours during the year but lower prices during other 
times. Applicants should consider offering “price protection” products that allow 
customers to pre‐purchase set quantities of electricity at fixed prices. These 
products substantially reduce bill volatility without distorting the price signal from 
dynamic pricing. . . . 
     Applications should include a plan that addresses the requirements of the ideal 
randomized control design to the best extent possible. After project selection and 
before project award DOE expects to meet with the applicant to finalize data 
collection and analysis requirements.  
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       Applicants that do not yet have regulatory approval are eligible for receiving an 
    award.  Examples might include applications that require approvals for cost 
    recovery or dynamic pricing tariffs.  However, DOE may withhold some or all of the 
    grant funds until regulatory approval is obtained.”  [SGIG FOA at 22 24] 
    National Grid believes that its Smart Grid Pricing programs (Critical Peak Pricing 
Program, Hourly Pricing Program and Peak Time Rebate) comply with most of the 
DOE’s Special Instructions.  For example, National Grid will install smart meters on all 
customers in two well‐defined geographical areas.  Also, National Grid’s Critical Peak 
Pricing Program and Hourly Pricing Program meet the dynamic pricing program 
specifications set forth in the Special Instructions.   
    First, National Grid’s Smart Grid Pricing program design requires all customers in 
the Smart Program areas to be put on the CPPP or HPP dynamic pricing programs.  
Since this is the entire population, there is no need to design a statistically based 
random sample plan.  Second, all CPPP and HPP customers are given price protection 
on an annual basis.  This increases the likelihood that customers will simply accept the 
dynamic pricing program they are placed on.  Finally, should some customers decide 
that full dynamic pricing under CPPP or HPP is undesirable, all such customers are 
enrolled automatically in the PTR program.  Peak Time Rebate is another form of 
dynamic pricing that is much simpler in form than CPPP or HPP, and one that may be 
more effective or practical in a full scale rollout of smart grid technologies than CPPP 
or HPP for the majority of National Grid’s customers.  Peak Time Rebate inherently 
contains price protection—i.e., rebates are earned only if demand response is 
obtained, but no penalty is imposed if demand response is absent.  It is National Grid’s 
opinion that these design features comply with restrictions imposed by state law on 
mandatory dynamic pricing. 
    National Grid acknowledges that the foregoing program design does not meet the 
requirements of a randomized design within the Smart Program areas.  Clearly, the 
number of customers enrolled in CPPP, HPP and PTR will be partly the result of self‐ 
selection by customers.  But, the fact that all customers in the Smart Program areas 
will be on some form of dynamic pricing is clearly a benefit—no one receives a smart 
meter and is compelled to stand by idly while others reap rewards.  Moreover, there is 
a control group.   
    The control group for the customers in the Smart Program areas are the 
Company’s load research sample customers that lie outside of the Smart Program 
areas.  The sample design for National Grid’s load research customers is a statistically 
valid stratified random sample design.  Such customers have interval data recorders 
already installed at their premises and have had such recorders for many years.  Thus, 
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a statistically valid baseline from which one may compare ordinary customer behavior 
without dynamic pricing and without smart grid technologies with the observed 
customer behavior in the Smart Program areas already exists. 
    However, National Grid’s design for Smart Grid Pricing programs and the Smart 
Program need to depart from the DOE’s Special Instructions to address an important 
statutory requirement imposed by the State of New York.  In 1997, the State of New 
York enacted a change to Public Service Law Section 66(27)(a) (“PSL § 66(27)(a)”) that 
prohibits the Commission from imposing mandatory time‐of‐use rates on residential 
customers.  Consequently, the Special Instructions requirement that dynamic pricing 
be applied on a mandatory basis in the Smart Program areas cannot be met without 
violating state law.  Moreover, the DOE acknowledges in its Special Instructions that a 
mandatory imposition of dynamic pricing will raise concerns with the customers 
affected and that “[a]pplicants should consider offering ‘price protection’ products.”16   
    National Grid believes that its overall Smart Grid Pricing program design and, in 
particular, its Peak Time Rebate program is an effective means  to address the 
restrictions imposed by state law on mandatory dynamic pricing yet still comply with 
the spirit of the DOE’s Special Instructions.   
    Finally, it is important to note that National Grid’s Smart Grid Pricing program is 
not one more experiment in a long line of experiments in dynamic pricing for which 
randomized control trials are an appropriate experimental method.  The DOE’s FOA 
and its Special Instructions were written with the entire nation in mind.  The fifty 
states have pursued dynamic pricing of one form or another for the past quarter 
century and to very different degrees.  Most dynamic pricing programs, and in 
particular those offered by National Grid, do not represent new pricing concepts.  
These concepts were reflected in earlier experiments or mandatory programs for time‐
of‐use rates, hourly day‐ahead locational based marginal pricing, interruptible and 
curtailable rates, and various load control and demand response programs.  New York 
has been in the forefront of experiments with such rates over the past few decades.  
Additional experiments are not needed.  We already know that customers will respond 
to price signals if the signals are strong enough and they have the ability to respond.   
    Previous dynamic pricing programs often failed because the technology required to 
implement the pricing program was too expensive for the benefits obtained or was too 
unreliable for daily use.  National Grid’s Smart Program provides a limited scale rollout 
of the new technologies in a real world setting coupled with the best dynamic pricing 
      See SGIG FOA at 23. 
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concepts evaluated in the last 25 years.  The combination of pricing and technology 
should ease customers’ concerns about their ability to respond and save on these 
pricing offers. 
Attachment 1
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                              SMART GRID SECURITY APPROACH 

    A. Overview 

        The advent of the Smart Grid, smart homes and smart metering all require 
communications and the ability to control devices that provide electricity to customers and 
manage the grid. Communications security for the distribution grid has not been an issue in the 
past, since there were almost no automated controls or remote sensors in the distribution grid. 
Over the last few years, the issue has been explored by a number of industry working groups 
resulting in an extensive list of security standards, borrowed from the telecommunications 
community and other industries, to address Smart Grid security.  With the rapid pace of Smart 
Grid development, the Senate has proposed in pending legislation the National Institute of 
Standards and Technology take control of the process and develop standards for the Smart 
For example, one key new area is communications associated with grid devices, meters and in‐
home energy management systems.  At the most basic level, securing these communications 
involves the ability to sign command messages, encrypt and decrypt messages sent to and 
received from field devices, audit both the security activities and the transaction data from field 
devices, manage keys, and manage the larger set of security components deployed throughout 
the system. With this in mind a security architecture will be developed that includes:  

           •   A security event manager to collect, correlate, and analyze audit events to allow 
               detection of intrusions and attacks;  

           •    A signing and encryption management system  for securing command messages 
               being sent  to field devices; and  

           •    A decryption and key update / management system to provide message 
               decryption and key management. 

These fundamental issues are not extremely complex, until you add scale and the asset 

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    B. Security Guiding Principles  

         As noted in the filing, many of the security guidelines related to the Smart Grid are being 
developed.  This does not mean we do not have guidelines for securing the Smart Grid today.  
In fact, many of the guidelines being considered for application to the Smart Grid are merely 
modifications of existing standards for telecommunications, critical infrastructure assets and 
general cyber security.  Additionally, many of the standards all utilities use today to protect the 
existing infrastructure apply to the Smart Grid, especially with regard to physical security.  It is 
the addition of smart command and control assets throughout the grid that has generated a 
focused effort to assemble (and adapt where appropriate) all applicable security and 
interoperability standards into one cohesive set of guidelines which has led Congress to direct 
FERC to oversee the efforts managed by the National Institute of Standards and Technology 
(NIST) as they work to develop or incorporate many of these standards.   

        While additional legislation may alter some of the roles for key agencies, we recognize 
NIST and FERC as the focal point for many Smart Grid Standards and are working with them and 
within the guidelines noted above and bulleted below, to expand our existing Security Program 
to address Smart. We will, therefore, include the following activities in our Program: 

       •   National Grid will endeavor to comply with the eight Critical Infrastructure 
           Protection (CIP) Reliability Standards of the North American Electric Reliability 
           Corporation (NERC). 
       •   National Grid will identify security risks, prior to finalizing the design, via the 
           application of AMI‐SEC and NERC CIP threat assessment methodologies (at a 
           minimum), and will incorporate appropriate mitigation techniques and controls into 
           said design.   
       •   National Grid will treat the detailed solution design itself as a security sensitive item, 
           requiring appropriate access rights and controls to ensure its secrecy from the 
           general population and employees on a need to know basis.   

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        •   National Grid will design and deploy the solution utilizing many of the security 
            standards and protocols (and their intrinsic security attributes) put forth by NIST in 
            their May 18, 2009 Smart Grid Interoperability Standards Framework Release 1.0 
            (and subsequent revisions), including, but not necessarily limited to: 
            Standard                         Application 
            AMI‐SEC System Security          Advanced metering infrastructure (AMI) and Smart 
            Requirements                     Grid end‐to‐end security 
            ANSI C12.19/MC1219               Revenue metering information model 
            BACnet ANSI ASHRAE 135‐          Building automation 
            2008/ISO 16484‐5 
            DNP3                             Substation and feeder device automation 
            IEC 60870‐6 / TASE.2             Inter‐control center communications 
            IEC 61850                        Substation automation and protection 
            IEC 61968/61970                  Application level energy management system 
            IEC 62351 Parts 1‐8              Information security for power system control 
            IEEE C37.118                     Phasor measurement unit (PMU)communications 
            IEEE 1547                        Physical and electrical interconnections between 
                                             utility and distributed generation (DG) 
            IEEE 1686‐2007                   Security for intelligent electronic devices (IEDs) 
            NERC CIP 002‐009                 Cyber security standards for the bulk power system 
            ..NIST Special Publication (SP)  Cyber security standards and guidelines for federal 
            800‐53, NIST SP 800‐82           information systems, including those for the bulk 
                                             power system 
            Open Automated Demand            Price responsive and direct load control 
            Response (Open ADR) 
            OpenHAN                          Home Area Network device communication, 
                                             measurement, and control 
            ZigBee/HomePlug Smart            Home Area Network (HAN) Device Communications 
            Energy Profile                   and Information Model 

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    •   National Grid will require adherence with the applicable standards by system / 
        device vendors as part of the fundamental vendor system / device requirements 
        going forward. 
    •   National Grid will utilize a layered security architecture, protecting the solution at 
        the physical, data, access, and transport layers at a minimum.  
    •   National Grid will utilize security methods that include, but will not necessarily be 
        limited to: rotating encryption, firewalls, multi‐factor identification, message 
        inspection and validation, the use of specialized hardware appliances, and restricted 
        user / administrator access. 
    •   National Grid will require all communications devices, including meters, deployed 
        outside of a secured area to employ hardware‐based destruction‐on‐tamper 
        technology that renders the communications portion of the device inoperable in the 
        event it is opened by unauthorized persons.  This will be in addition to the 
        appropriate system level exclusion of the device upon loss of presence. 
    •   National Grid will ensure our selected vendor partners are participants on the 
        appropriate standards development groups and compliant with the NERC CIP 
        Reliability Standards and applicable NIST Smart Grid Interoperability Standards 
        Framework standards.  
    •   National Grid will not simply assume compliance with standards is adequate, we will 
        test our systems using outside security experts to identify vulnerabilities and adjust 
        our approach to fill any gaps.  
    •   National Grid will also implement the processes and procedures required to provide 
        a long‐term secure environment. 
    •    National Grid will provide feedback to the various industry working groups lessons 
        learned to help accelerate the completion of good standards.  

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    C. Measuring Our Security 

        National Grid understands we must test our plans and our application of those plans to 
demonstrate our compliance.  We also realize we cannot simply operate in accordance with the 
prevailing standards and assume we are secure.  Security is a moving target, as holes are 
discovered in existing products and patches have to be created. As new products are 
introduced to the overall market, people who seek to break security are offered new 
opportunities to exploit any system weaknesses. Much of the smart grid infrastructure will be 
physically accessible by home owners and others.  This lack of physical control of a command 
and control asset means many security mechanisms traditionally used will now have to account 
for devices that can be readily accessed. Traditional data center and desktop security will not be 
sufficient in this dynamic environment.  Accordingly, we will continue to test and include 
outside experts to help identify gaps so we can continually adapt.   

        National Grid is committed to ensuring the security of the Smart Grid solution is integral 
throughout the process from design, to deployment, to operation. Through the work of NIST, 
the utility industry has security standards for most of the key components of the smart grid. 
However, much work is still underway to expand these standards for specific Smart applications 
and for new assets and operations. National Grid will operate within the guidelines of these 
existing standards and those recommended by FERC and NIST, while participating in the 
development of expanded and new standards.  We will also develop and test Smart Grid 
operational processes during the Program to ensure we adapt, test and measure our 
compliance and our overall security.  National Grid has always taken security seriously and we 
recognize the increased need for a focused and tested approach to Smart Grid Security.     


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State      Fuel    Period                                         Filed                      Approved                                             Programs
NY - NYC   Gas     "EXPEDITED" calendar 2009, 2010, 2011    08/22/2008    04/07/2009                     Residential High Efficiency Heating, Water Heating and Controls
NY - NYC   Gas     "90 DAY" calendar 2009, 2010, 2011       09/22/2008    expected third quarter 2009    Residential Low Income Program
                                                                                                         Enhanced Home Sealing Incentives
                                                                                                         Energy Audit/Home Performance
                                                                                                         Energy Star Products
                                                                                                         Energy Analysis: Internet Audit
                                                                                                         Residential Building Practices and Demonstration Program
                                                                                                         Commercial, Industrial and Multi Family Energy Efficiency Program
                                                                                                         Commercial High Efficiency Heating and Water Heating
                                                                                                         Comm Building Practices & Demonstrations
NY - LI    Gas     "EXPEDITED" calendar 2009, 2010, 2011    08/22/2008    04/07/2009                     Residential High Efficiency Heating, Water Heating and Controls
NY - LI    Gas     "90 DAY" calendar 2009, 2010, 2011       09/22/2008    expected third quarter 2009    Residential Low Income Program
                                                                                                         Enhanced Home Sealing Incentives
                                                                                                         Energy Audit/Home Performance
                                                                                                         Energy Star Products
                                                                                                         Energy Analysis: Internet Audit
                                                                                                         ENERGY STAR® Homes Program
                                                                                                         Residential Building Practices and Demonstration Program
                                                                                                         Commercial, Industrial and Multi Family Energy Efficiency Program
                                                                                                         Commercial High Efficiency Heating and Water Heating
                                                                                                         Comm Building Practices & Demonstrations
NIMO       Gas     "INTERIM" calendar 2009, 2010, 2011      08/01/2008    09/18/2008                     Residential Energy Star Products
                                                                                                         Residential High Efficiency Heating, Water Heating and Controls
                                                                                                         Commercial High Efficiency Heating and Water Heating
NIMO       Gas     "EXPEDITED" calendar 2009, 2010, 2011    08/22/2008    04/07/2009                     Residential High Efficiency Heating, Water Heating and Controls
NIMO       Gas     "90 DAY" calendar 2009, 2010, 2011       09/22/2008    expected third quarter 2009    Residential Energy Star Products
                                                                                                         Commercial High Efficiency Heating and Water Heating
                                                                                                         Enhanced Home Sealing Incentives
                                                                                                         Residential Building Practices and Demonstration Program
                                                                                                         EnergyWise Program
                                                                                                         Commercial, Industrial and Multi Family Energy Efficiency Program
                                                                                                         Comm Building Practices & Demonstrations
NIMO       Electric "EXPEDITED" calendar 2009, 2010, 2011   08/22/2008    01/16/2009                     Residential High Efficiency Central Air Conditioning
                                                                                                         Small Business Services
NIMO       Electric "90 DAY" calendar 2009, 2010, 2011      09/22/2008    expected second quarter 2009   Energy Initiative
                                                                                                         Enhanced Home Sealing Incentives
                                                                                                         Residential ENERGY STAR® Products and Recycling Program
                                                                                                         Residential Internet Audit Program and E-Commerce Sales
                                                                                                         Residential Building Practices and Demonstration Program
                                                                                                         EnergyWise Program
                                                                                                         Residential Pricing Pilot with Load Control
Attachment 3
Attachment 4
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                                  Albany (Capital District) Area

 Rate Code                                  Description                             Customers
SC-1         Residential                                                                37,680
SC-2         Small General Service Non-Demand                                            3,073
SC-2D        Small General Service Demand                                                1,412
SC-3         Large General Service (100 kW - 2,000 kW)                                       93
SC-3A        Large General Service (over 2,000 kW)                                            2
SC-4         Large General Supplementary Service                                             37
SC-7         Standby Service                                                               -

                                              Total                                      42,297

                                         Syracuse Area

 Rate Code                                  Description                             Customers
SC-1         Residential                                                                35,935
SC-2         Small General Service Non-Demand                                            2,192
SC-2D        Small General Service Demand                                                1,168
SC-3         Large General Service (100 kW - 2,000 kW)                                     148
SC-3A        Large General Service (over 2,000 kW)                                          10
SC-4         Large General Supplementary Service                                            33
SC-7         Standby Service                                                                 1

                                              Total                                      39,487

                                       All Program Areas

 Rate Code                                  Description                             Customers
SC-1         Residential                                                                73,615
SC-2         Small General Service Non-Demand                                            5,265
SC-2D        Small General Service Demand                                                2,580
SC-3         Large General Service (100 kW - 2,000 kW)                                     241
SC-3A        Large General Service (over 2,000 kW)                                          12
SC-4         Large General Supplementary Service                                            70
SC-7         Standby Service                                                                 1

                                              Total                                      81,784
Attachment 5
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Capital District Area             Xfmr     Xfmr     Caps Sectionalizers
FEEDER_NO                          O/H       U/G
01251                              327       170       11                 0
01252                               92        76         1                1
01253                              498       225         9                5
01254                              209        17         6                0
14202                               43         5         0                0
14203                               53        13         3                0
14206                               75         7         3                0
14251                              120        15         6                2
28185                              213        53         9                0
28186                              189        42         7                0
29751                              165        79         5                0
29752                               75         1         0                0
29753                              279       135         4                0
34552                              324       245         5                2
34553                              122       217         6                3
34554                              131       295         5                0
34555                              147       241         9                1
34556                              301       209         7                1
34557                              469        78         7                2
34558                              140       107         8                0
36954                              253       138         9                0
36956                              211        60         3                1
36958                              267       243       10                 0
41554                              128        46         3                0
44256                              413       228         3                4
44257                              181       257         3                1
44258                              152       352         3                1
46451                              136        26         0                0
34551                              100       154         0                0
46357                              164        68         0                1
28187                              132        29         0                0
41551                              219       207         0                0
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Syracuse Area        Xfmr    Xfmr           Caps Sectionalizers
FEEDER_NO             O/H     U/G
25555                  234    180                5                0
24452                  422    252                8                0
28651                  309     49              13                 1
28652                   92      7                3                0
16854                  352     31                8                0
25556                   86     20                3                0
24453                  342    153              11                 1
26552                  623    350              20                 1
29056                  215    143                5                0
28653                  345     47                8                1
16853                  420     73                4                2
26551                  582    240                6                2
26151                  176     35                4                0
29055                   69     11                3                0
29057                  302     46                6                1
26153                  208     13                7                0
29058                  225    110                9                1
24454                  162    146                6                1
28654                   84      4                4                0
16852                  277     57                1                0
25554                  149     34                0                0
24451                  168     23                1                0
26554                  462    193              11                 0
26154                  216     90                8                1
26553                  894    178              24                 0
26152                  110     18                7                0
26555                  234    200                0                1
Attachment 6
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Marketing Plan Business Capabilities

# Service                                Business Capability

1 Level One                              Real time measurement of


                                         Communication of energy


                                         Dynamic pricing

2 Level Two                              Real time measurement of


                                         Communication of energy


                                         Automated load management

                                         Dynamic pricing
                    Niagara Mohawk Power Corporation d/b/a National Grid
                                                        Case 09-E-0310
                                     New York Smart Program Proposal
                                                           Attachment 6
                                                            Page 2 of 2 

# Service                        Business Capability

3 Level Three                    Real time measurement of

   1st Generation                consumption

   2nd Generation                Communication of energy

   3rd Generation                consumption

                                 Distributed energy management

                                 Automated load management

                                 Prepaid usage (optional)
Attachment 7
                                                         Niagara Mohawk Power Corporation d/b/a National Grid
                                                                          New York Smart Program Proposal
                                                                                             Case 09-E-0310
                                                                                                Attachment 7
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Marketing Plan Tactics

The Three Phases of the Marketing Approach can be found below:

                                                        Niagara Mohawk Power Corporation d/b/a National Grid
                                                                         New York Smart Program Proposal
                                                                                            Case 09-E-0310
                                                                                               Attachment 7
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              I. Seed (Approval to Launch)                                         reach targets:
                                                                                   1. Residents
                                                                                   2. Small Businesses
                                                                                   3. Community Leaders

•   Meet with elected officials and community leaders                                     3
•   Send “teaser” message to all pilot participants                                      1,2
•   Engage “high profile” participants                                                   1,2
•   Initiate “SGV” contest                                                              1,2,3
•   Launch SmartSquad                                                                   1,2,3
•   Develop press kit

                                                               Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                New York Smart Program Proposal
                                                                                                   Case 09-E-0310
                                                                                                      Attachment 7
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       II. Share                                                                          reach targets:
                                                                                          1. Residents
                                                                                          2. Small Businesses
                                                                                          3. Community Leaders

•   Distribute “Welcome Kit” to participants and community leaders                           1,2,3
•   Introduce participants to web overlay – profile, options, social networking              1,2
•   Bill stuffers (monthly)                                                                  1,2

•   Erect solar powered billboards highlighting consumption savings                          1,2,3
•   Launch e-newsletter                                                                      1,2
•   Send direct mail to participants and community leaders                                   1,2,3
•   Announce “Badges of Honor”                                                               1,2

•   Initiate contest                                                                         1,2,3
•   Launch “Get Smart” breakfast series                                                      1,2,3

•   Launch In field demonstration unit                                                       1,2
•   Sponsor neighborhood block parties                                                       1,2
•   Launch “house” parties program                                                           1
•   Build school partnerships                                                                1,3

                                                           Niagara Mohawk Power Corporation d/b/a National Grid
                                                                            New York Smart Program Proposal
                                                                                               Case 09-E-0310
                                                                                                  Attachment 7
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         III. Succeed                                                                 reach targets:
                                                                                      1. Residents
                                                                                      2. Small Businesses
                                                                                      3. Community Leaders

• Continually update web overlay                                                       1,2
• Bill stuffers (monthly)                                                              1,2

• Update solar powered billboards                                                      1,2,3
• Garner PR coverage of “high profile” participant                                     1,2,3

• Send direct mail to participants and community leaders                               1,2,3
• Update e-newsletter monthly                                                          1,2
• Continue contests                                                                    1,2

• Continue school programs                                                             1,3
• Continue utilizing in field demonstration unit                                       1,2,3
• Continue “house” parties program                                                     1

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                      Niagara Mohawk Power Corporation d/b/a National Grid
                                                          Case 09-E-0310
                                       New York Smart Program Proposal
                                                             Attachment 9
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Global SMART Services Development Program

Filing Exhibit – Impacted Systems

IS Gap Analysis
                                                 Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                     Case 09-E-0310
                                                                  New York Smart Program Proposal
                                                                                        Attachment 9
                                                                                         Page 2 of 20

1. Purpose

  The Gap Analysis consists of defining the present state, the desired or `target' state and
  determining the gap between them.
  The purpose of the document is to capture and understand the gap that exists between the
  current state of applications within the National Grid IS Landscape and the ‘To-Be’ state these
  applications need to reach to support the New York Smart Program (Smart Program). The
  document will capture the changes required to existing applications to support the new business
  processes introduced as part of the Smart Solution.

  The results of this analysis were used as in input to developing the Smart Program proposal.

2. Scope
  The scope of this document is to identify the effort required to modify the existing legacy
  applications only. This covers the changes required to support the Smart Program and includes
  all Residential and small Commercial & Industrial customers.

  NOT included within the scope of this document are:
         Efforts for customization to 3rd party applications
         Impacts of a full roll out on legacy systems/applications (this will need to be investigated
         further prior to any future roll out taking place)

3. Impacted Applications

  3.1 Application Areas
  The applications in question have been organized in line with the structure provided by the Global
  Transformation Program, using the ‘Global Landscape 2008’ Model as a Baseline. This
  represents a logical alignment with the Business Processes detailed within the Business
  Architecture document:

          System & Market Operations – All Distribution Grid Control applications such as OMS,
          DMS, etc
          Customer Management – Customer facing systems, such as Billing, Customer Calls and
          presentation of Customer Data. Meter Data collection is also included within this area
          Work & Asset Management - Work and Asset Management applications, including both
          Meter and Grid (via the GIS) Devices and Substation Equipment, in addition to all work in
          relation to the National Grid Mobile Workforce.
          Shared Services - Financial systems such as Procurement, Finance, Admin, etc.

  IS Gap Analysis
                                              Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                  Case 09-E-0310
                                                               New York Smart Program Proposal
                                                                                     Attachment 9
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3.2 Identifying the As-Is Systems
Due to the variety of systems/applications within National Grid, a structured approach was
followed to identify only applications impacted by the Smart Program. From the initial 1,500+,
these were narrowed down using the following approach:
        Analysis of the IS Service Catalogue to remove:
        - Applications with a current status of ‘Decommissioned’
        - Applications within the Business Area of ‘Transmission’ (The Smart Program will only
        focus on Distribution and Metering)
        - Applications relating to ‘Gas Processes’ as the Smart Program will only focus on
        Electricity Processes
        Review of the National Grid Transformation Route Map. This provided a high level view
        of the key applications expected to be in use within the National Grid IS Landscape, both
        within 2008 and beyond to 2011 and 2013.
        Collaboration with key contacts from National Grid Business and IS (referenced in
        Appendix), to validate the current information available for each application.
        Referencing of the Business Requirements identified for the Program
        The list was further narrowed with the selection of Syracuse and Albany (Capital District)
        as the Smart Program sites for New York.

3.3 Identifying the Gap
The Business Architecture document details the key Business Processes to be implemented in
the Smart Program. The impact on the current Legacy Applications was identified by aligning
applications with the Smart Business Processes. (The alignment with the specific Smart Business
Processes is detailed in Section 5)

Collaboration with NG Contacts verified the gap and quantified the Level of Effort (LOE) required
to modify the applications to support the Smart Business Processes.
(Note – the full list of NG Contacts leveraged for input is included within the Appendix of the

The presentation below displays the current Legacy Systems within the National Grid IS
landscape considered to be impacted by the Smart Services Program roll out. The specific
impacts to these applications are detailed in subsequent sections of the document.

IS Gap Analysis
                  Niagara Mohawk Power Corporation d/b/a National Grid
                                                      Case 09-E-0310
                                   New York Smart Program Proposal
                                                         Attachment 9
                                                          Page 4 of 20

IS Gap Analysis
                                                  Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                      Case 09-E-0310
                                                                   New York Smart Program Proposal
                                                                                         Attachment 9
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4. Gap Details
  The following section details the specific gaps that exist in enabling existing legacy applications to
  support the Smart Program.

  The diagrams within this section depict at a high level the systems impacted by the Gap Analysis.
  Within the diagrams, changes to be introduced at a system level are highlighted. These are
  identified as being:
      - Changes required to current systems
      - New Smart functionality

  4.1 Customer Management

          4.1.1 Meter Reading and Repository

  The proposed solution will utilize the existing ERS (Energy Resource System) as the central
  repository for all meter reads for downstream applications such as PULSE/WSA etc. The Meter
  Data Services organization within National Grid has an ongoing project to consolidate meter
  reads into the Energy Resource System.

  Meter Data Management and Analytics will be completely redesigned for Smart Metering, hence
  a newly acquired MDMS (Meter Data Management System) would feed the interval consumption
  data from SMART customers to the ERS in the necessary format. This would make the ERS the
  single source of meter reads for all downstream applications.
  (Note - A performance test is scheduled for this system which will test its scalability in terms of
  additional number of meters the system can support. Utilizing the ERS for the SMART landscape
  would align with this initiative and minimize the impact to downstream systems and interfaces.)
  In addition to a new MDMS, the move from the AMR to AMI domain will require a new Meter Data
  Collection engine to be built. As with the MDMS, this will be newly acquired for the Smart

  Note - The MV90 system is currently used within National Grid for Meter Data Collection and
  Management purposes. This application is not being considered ongoing for the Smart solution,
  due to scalability issues, and the difficulty involved in making large scale changes to the system.
  This has been confirmed by the key users of the system within National Grid IS.

  IS Gap Analysis
                                              Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                  Case 09-E-0310
                                                               New York Smart Program Proposal
                                                                                     Attachment 9
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The MV90 system has been depicted in a number of the process maps below, to show the As-Is
scenarios, and how some ‘Non-Smart’ meter data will be handled in the future, however this is
not included as part of the impacted systems.

The following diagram shows the high level As-Is and To-Be scenarios for the Meter Reading

The specific gap details in the Meter Reading and Repository area are as follows:

Application    To Be State      As Is State             Gap                         Impact   Effort

ERS            ERS should       The System provides     The System would            Medium   6 Weeks
               be able to       electric and gas        need some
               provide          consumption data        modification to identify
               consumption      related to Non-         and store the
               data for         SMART customers         information coming
               SMART            to various              from the MDMS as
               Electric         downstream              being related to the
               meters to        applications            SMART customers

IS Gap Analysis
                                               Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                   Case 09-E-0310
                                                                New York Smart Program Proposal
                                                                                      Attachment 9
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        4.1.2 CSS Billing and Tariff Management
For smart services, there will be several programs required to cater to the various options
available to customers such as Dynamic Pricing, Time of Use (TOU) tariffs, etc. The National Grid
Billing System will be required to support this. In addition, the CSS system will require changes to
flag a customer as ‘Smart’, and associate the different billing programs with the Smart Program

To support the CSS system in the Smart Program, some additional tariff management and
complex billing functionality may be required outside of CSS. This will be completed within either
the MDMS or a new complex engine.

The process diagram demonstrates the proposed solution:

The current CSS system will be used to perform the Tariff Management for Smart data received
from the MDM. This would mean customization to CSS to include the Tariff’s related to Smart

IS Gap Analysis
                                               Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                   Case 09-E-0310
                                                                New York Smart Program Proposal
                                                                                      Attachment 9
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The specific gap details for CSS Billing and Tariff Management are as follows:

The total estimated Level of Effort to make the changes to the Billing and Customer Handling
systems is 74 person months.

Application     To Be State      As Is State               Gap                        Impact   Effort

Core CSS        Support          As of today CSS has       A new set of tariff        Low      1&½
                different        multiple tariff           structures has to be                Person
                programs         structures based on       setup to support the                Months
                (tariff          the                       SMART program
                structure)       Geography/Custome                                             Duration
                                 r type / Time of Use
                                 etc and can add new                                           4 Weeks
                                 ones as needed.
                Support          As of today the CSS       New functionality is to    High     5 Person
                dynamic tariff   can create and            be added in CSS to                  Months
                structures       maintain multiple         process the peak
                based on         tariff structures but     consumption data and                Duration
                peak             does not support          update the associated
                consumption      dynamic                   tariff structures                   10 Weeks
                period           creation/modification
                                 of tariff structure.
                Support of       There is no such          Major changes are          High     16 person
                tariff           tariff structure          required to support                 month
                structures       related to this           possible innovative
                relating to                                tariff components                   Duration
                demand                                     around demand                       6-8 months
                response                                   response programs
                events                                     like direct load                    A base
                                                           control,emergency                   effort    (
                                                           based demand                        1200 man
                                                           response,                           hours) will
                                                           interruptible/ curtailed            be required
                                                           rates/demand bidding                to support
                                                           etc.                                this. In
                                                                                               addition to
                                                                                               each tariff
                                                                                               man hours)
                Support of       There is no such          Major changes are          High     17 person
                prepayment       functionality             required to complete                month
                products and     available at this point   design of new
                gift card        in CSS                    functionality including             Duration
                                                           interfacing with                    6-8 months
                Identify a       As of today CSS can       No Gap. Effort would       Low      1&½

IS Gap Analysis
                                               Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                   Case 09-E-0310
                                                                New York Smart Program Proposal
                                                                                      Attachment 9
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              customer as        classify Customers       be required for only                 Person
              a SMART            into different           configuration &                      Months
              customer           categories               testing.

                                                                                               4 Weeks
              Associate          As of today              No Gap. Effort would        Low      1&½
              SMART              Customers can be         be required for only                 Person
              customers to       associated to            configuration &                      Months
              different tariff   different tariff         testing.
              programs           structures                                                    Duration

                                                                                               4 Weeks
              Additive           As of today CSS can      No Gap. Effort would        Low      1&½
              /Deduct            identify Master-         be required for only                 Person
              relationship       Subordinate meters       configuration &                      Months

                                                                                               4 Weeks
              Data               As of today CSS          Data aggregation for        Low      1 Person
              Aggregation        aggregates the data      SMART customers will                 Month
                                 to calculate the bill    have to be turned off
                                                          as it will be done in the            Duration
                                                          MDMS                                 4 Weeks
              Work Orders        Work Orders are not      Additional Work Order       Medium   3 Person
              for all Smart      currently available      Types / Sub Types to                 Months
              Meter related      for Smart Meters         be added to MWork
              jobs should                                 for all Smart Related                Duration
              be added to                                 work                                 6 to 7
              CSS                                                                              Weeks
              Cancel / Re-       As of today CSS can      CSS would have to be        Medium   4 Person
              bill               re-bill multiple         modified to re-bill                  Months
                                 periods without          multiple periods with
                                 interval data. Re-bill   interval data (but a                 Duration
                                 of multiple periods      manual work around
                                 with interval data is    could be implemented                 7 Weeks
                                 done manually.           to eliminate this effort)
              Data               As of today CSS          CSS will have to be         Low      2 Person
              Estimation         estimates missing        modified to turn-off the             Months
                                 data before              estimation of missing
                                 computing the bill       data for SMART                       Duration
                                                          customers                            1&½
              Sending a          As of today CSS can      CSS will have to be         Low      1&½
              flag to VRU        send different           configured to send                   Person
              signifying         customer categories      smart customer flag to               Months
              smart              to VRU                   VRU
              customers                                                                        Duration

                                                                                               4 Weeks
              Accounting         Currently hourly         Some revenue related                 3 Person
                                 billing accounting is    general ledger static                Weeks

IS Gap Analysis
                                               Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                   Case 09-E-0310
                                                                New York Smart Program Proposal
                                                                                      Attachment 9
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                                  supported                tables need to be
                                                           changed only                          Duration

                 Ability to       Currently invoices       On demand invoice         High        6 person
                 generate on      are generated based      generation will require               month
                 demand           on billing cycle         real time
                 invoices         configured in the        communication with                    Duration:
                                  system                   MDMS and out of                       6-8 months
                                                           cycle bill generation.
                 For              These interfaces are     Changes will be                       18 person
                 interfacing      new interfaces           required on CSS to                    months
                 with other       arising out of smart     consume these
                 systems          project hence they       interfaces or produce                 (refer
                                  don’t exist              data for the                          following
                                                           interfaces.(the                       table for
                                                           interfacing effort to                 details)
                                                           ESB and
                                                           transformations are
                                                           not considered here)

Xtreme           Bill presented   As of today Xtreme       Xtreme would have to      Medium      4 Person
                 to SMART         is able to process       be customized to                      Months
                 customers        the information          display relevant
                 should be        related to bill          SMART information on                  Duration
                 able to          presentment for          the bills to the
                 display          regular customers        Customer                              8 Weeks
                 additional       from CSS

The following details the effort required to change CSS to support the interfaces required to
support the Smart Program:

    High Level         Source         Target             Interface       Interface     Type of      Level of
   Requirement         System         System               Type         Frequency      Impact        Effort
  Customer                          Meter Data                                                        280m
                                                                          non-real      New
 Master                  CSS       Management       Asynchronous                                      hours
 Information                         System
  Installs and                                                                                        200m
 removes of                                                               non-real     Modify         hours
                         CSS           MITS         Asynchronous
 SMART                                                                      time
 Creation of
                                      Work                                                          (We have
 SMART Work                                                               non-real     Modify
                         CSS       Management       Asynchronous                                   considered
 Orders and their                                                           time
                                     System                                                           6 such
                                                                                                   work order

IS Gap Analysis
                                               Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                   Case 09-E-0310
                                                                New York Smart Program Proposal
                                                                                      Attachment 9
                                                                                      Page 11 of 20

                                       Home                                                           280m
 Customer Master                                                          non-real       New
                        CSS          Automation        Asynchronous                                   hours
 Information                                                                time
 SMART Meter                                                                                          280m
                                                                          non-real       New
 Identification         CSS         AMI Head End       Asynchronous                                   hours
 Customer Master                                                          non-real       New          280m
                        CSS             CRM            Asynchronous                                   hours
 Information                                                                time
                        Meter                                                                         280m
                        Data                                                                          hours
 Electric Interval                                                        non-real       New
                       Manage           CSS            Asynchronous
 Read Data                                                                  time
 Electric Interval                                                                                    280m
                                                                          non-real      Modify
 Data for Smart         ERS             CSS            Asynchronous                                   hours
 Send available                                                           non-real      Modify        200m
                        MITS            CSS            Asynchronous                                   hours
 SMART inventory                                                            time

In addition to the CSS system some minor changes will be required to the PeopleSoft accounting
systems to reflect the new tariffs created within CSS:

Application       To Be State        As Is State        Gap               Impact     Effort
PeopleSoft        The system         NA – Smart         New               No         No effort from an IS
                  must recognize     Meter Tariffs      accounting        impact     perspective required
                  the newly          not yet created    streams for                  to make this change
                  created Smart                         Smart Tariffs                – tariff streams are
                  Tariffs to post                       will need to be              continuously added in
                  to the General                        created within               PeopleSoft so only a
                  Ledger                                PeopleSoft                   minor change will be
                                                                                     required to
                                                                                     accomplish this for

        4.1.3 Customer Handling
There will be several new requirements for customer support e.g. upon receipt of a complaint, the
CSR may need to ping the meter. The existing CSS system will be enhanced to support the new
customer functions related to the Smart Solution by integrating with the underlying systems, such
as the MDM.

The Program will be done in a ring fenced manner limited to 15,000 to 30,000 customers and will
have a work force specially trained to handle the customers. These CSR’s will access the
customer data via the existing CSS system

IS Gap Analysis
                                                Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                    Case 09-E-0310
                                                                 New York Smart Program Proposal
                                                                                       Attachment 9
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The diagram shows how a customer query will be directed within CSS, to ensure the customer is
dealt with by the correct agent. Upon contacting National Grid, a customer will input their
customer reference number. The system will then determine whether this is a Smart customer,
and will direct the customer call to the correct place. If a Smart customer, the call will be handled
by an agent with the necessary training to handle the customer query.

The diagram also indicates how the agent will interact with the meter, via the MDMS.

The specific gap details for Customer Handling are as follows:

Application     To Be State      As Is State              Gap                     Impact        Effort
VRU             This should      This system              Significant             Medium        3 Person
                be able to       currently supports       customization is                      Months
                support calls    calls from the regular   expected to this
                from             customers                application to                        Duration
                customers in                              enable supporting
                the SMART                                 SMART customers                       1 Month

IS Gap Analysis
                                         Niagara Mohawk Power Corporation d/b/a National Grid
                                                                             Case 09-E-0310
                                                          New York Smart Program Proposal
                                                                                Attachment 9
                                                                                Page 13 of 20

                                                                                       would be
                                                                                       the same
                                                                                       would be
CTI           Should be       The system passes    No Gap. Effort            Low       1&½
              able to pass    on the phone         would be required                   Person
              on unique       number or customer   for only                            Months
              identifier to   account number to    configuration &
              the CSR to      the CSR GUI          testing.                            Duration
              identify the
              SMART                                                                    4 Weeks

IS Gap Analysis
                                             Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                 Case 09-E-0310
                                                              New York Smart Program Proposal
                                                                                    Attachment 9
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4.2 Asset and Work Management
The systems used within the Work & Asset Management areas are as follows:
                  • MITS (Meter Asset Register)
                  • AIMMS (Substation Asset Register)
                  • GIS (Grid Asset Register)
                  • MWORK (Meter Mobile Work System)
                  • STORMS (Construction Mobile Work System)
                  • iScheduler (Workforce Scheduling System)

Based on the analysis completed, STORMS, iScheduler & AIMMS will remain the same. MITS
and Powerplant will require changes with respect to the new Smart Meters being procured.

New Meter Installation

The current MITS (Meter Inventory Tracking System) system will be used for Asset Management
of Smart Meters. This would require changes to MITS (see below) to facilitate this change. In
addition, the MITS system will update the AMI Head End with details of new meters procured.

The meter installation process will require the support of MWork and the Meter Vendors. The
process diagrams show the system impacts in of the two scenarios in terms of installing the
Smart Meters.

Solution 1 assumes MWork will perform Smart Meter installations and Smart Meter related work,
and would therefore (along with CSS) be required to change accordingly.

IS Gap Analysis
                                                                                 Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                     Case 09-E-0310
                                                                                                  New York Smart Program Proposal
                                                                                                                        Attachment 9
                                                                                                                        Page 15 of 20

Asset Management – New Meter (Smart Solution 1)

                                       Meter Inventory
                  Meter Procured       Received from

                                       Meter Updated to                                                          Meter validated      Meter status
                                            MITS                                                                   with CSS         updated in MITS
 Smart Solution

                                       Meter updated in                    Meter updated in                                        Meter Activated in
                                        AMI Head End                            MDM                                                Head End / MDM

                                                                                                  Work Order

                  Meter Installation     Work Order        Meter details                                         Meter validated     Meter status
                     Request            Raised in CSS     updated to CSS                                           with MITS        updated in CSS
                                                                                                updated in CSS

                                                                                                 Work Order
                                         Work Order                        Meter Installed at
                                                                                                 Completed in
                                       Raised in MWork                         property

                                                                                                                                      Asset financial
                                                                                                                                   information updated

IS Gap Analysis
                                               Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                   Case 09-E-0310
                                                                New York Smart Program Proposal
                                                                                      Attachment 9
                                                                                      Page 16 of 20

Solution 2 is based on the assumption the Smart Meter Vendor will install the meter, and will be
responsible throughout the Program for maintenance work related to the meter. In this case, the
vendor will need to provide MITS with an equivalent file (for a new meter), to enable this to be
updated in the system and for the details to be issued to CSS. In addition, CSS will require an
interface with the vendor Work Order solution, both to raise the Work Order and to update the
details of the completed Work Order in the system.
 Meter Vendor
 Smart Solution

The gaps identified therefore fall under the applications listed below:

The total estimated Level of Effort to make the changes to the Asset & Work Management
systems is 14 person weeks.

Application       To Be State       As Is State       Gap                 Impact   Effort
MITS              Requires a flag   MITS contains     Flag to be          Low      1 person
                  to identify       a flag to         added to                     week
                  Smart Meters      identify AMR      MITS to
                                    Meter             recognize                    Duration
                                    MITS already      Smart Meter                  1 week
                                    has the ability
                                    to add a new
                                    meter flag
                  Requires          MITS contains     Additional          Medium   2 person
                  additional data   data fields for   data fields to               weeks
                  fields to         attributes of     be added to
                  recognize         dumb and          MITS to                      Duration
                  attributes of a   AMR meters        recognize                    1 week

IS Gap Analysis
                                                Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                    Case 09-E-0310
                                                                 New York Smart Program Proposal
                                                                                       Attachment 9
                                                                                       Page 17 of 20

                  Smart Meter                          Smart Meter
                  (Comms                               attributes

                  An additional       No file is       Additional         Medium   3 person
                  daily file should   currently sent   daily file to be            weeks
                  be sent to the      to Head End      created from
                  AMI Head End,       system –         MITS to                     Duration
                  containing the      MV90             populate the                3 Weeks
                  details of new      (files issued    AMI Head End
                  meters              from MITS to     with the Smart
                  procured            CSS on a daily   Meter details
                  Smart Meters        Meter is         Weekly file to     Low      1 Person
                  to be flagged in    flagged based    Powerplant to               Week
                  weekly file to      on whether       be amended
                  Powerplant          Residential or   to recognize                Duration
                                      C&I              Smart Meters                1 week
                                                       as a separate

IS Gap Analysis
                                                    Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                        Case 09-E-0310
                                                                     New York Smart Program Proposal
                                                                                           Attachment 9
                                                                                           Page 18 of 20

Grid Devices

The diagram shows the process for the creation of a new premise. Due to the way Grid devices
are recognized within the Asset Management system, only minor customization will be required to
the GIS system, as detailed below. Assets to be procured through Smart are considered to sit
‘outside the fence’, hence no impacts to the AIMMS substation assets register exists.

Asset Management – New Premise

                      Procure Assets

         Process     Premise Number    Work Order                                              Daily validation of
          Start         Created         Raised                                                 Premise with GIS
                                                                            updated in CSS

                                       Work Order       Work Order Status    Work Order
                                        Raised              updated          Completed

                                       Work Order        GIS Updated in     GIS Production    Daily validation of
                                       Designed           Design View        view updated     Premise with CSS

                                                                                                 Asset financial
                                                                                              information updated

Application        To Be State         As Is State           Gap                     Impact       Effort
GIS                Devices within      Provision for         To be                   Low          2 Person
                   GIS need to be      flagging a            confirmed,                           Weeks
                   flagged as          device as             potentially no
                   ‘Smart’ by a        Smart has             gap exists if                        Duration
                   symbol              been                  process from                         1 Week
                                       incorporated          DA Program is
                                       within GIS            followed – to
                                       through the           be confirmed
                                       Distribution          by National
                                       Automation            Grid
                                       Program (in
                   Equipment No.       Provision for         There is no             No           1 Person
                   should reflect      Smart specific        customization           impact       Week
                   the device is       Equipment No.         need. While
                   Smart               has been              entering the                         Duration
                                       incorporated          data, the                            1 Week
                                       within GIS            planner has to

IS Gap Analysis
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                                    through the       enter a new
                                    Distribution      letter (training
                                    Automation        issue &
                                    Program (in       manual
                                    Syracuse-NY)      process)

In addition to the Asset Management systems, as a result of the changes to the process, some
minor changes are required within the Powerplant and PeopleSoft accounting systems:

Powerplant        The system        Currently there   The meter has      Medium   1 Person
                  has to accept     no is smart       to be identified            Month
                  smart meter       meter related     in MITS as
                  data from MITS    data in either    smart meter.                Duration
                                    MITS or           Then
                                    Powerplant        Powerplant                  1 Month
                                                      would need to
                                                      be configured
                                                      to consume &
                                                      process this
Peoplesoft        The system        Currently,        New meter          No       No effort
                  has to accept     Peoplesoft will   type and           impact   from an IS
                  the Purchase      not contain the   vendor to be                perspective
                  Order for the     specific meter    created in the              required to
                  Smart Meter       or vendor         system for                  make this
                  from the          being procured    Inventory and               change –
                  relevant vendor   in the Smart      General                     minor
                                    Program           Ledger                      change only
                                                      purposes                    to create
                                                                                  meter and
                                                                                  vendor in

IS Gap Analysis
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4.3 System and Market Operation
It has been proposed that within the Grid area the existing applications will not be utilized to
support the Smart Program. The current intention is to leverage the new OMS/DMS solution,
which is being rolled out within National Grid Electricity Distribution, and use this to provide
Smart functionality within the Grid area.

The current Legacy Applications will be required to interface with the new solution offering. This
will replicate interfaces with the current OMS and EMS systems. The details of this interface have
been referenced in the document ‘Interface Specification’, and will be explored further as part of
the Solution Design phase.

4.4 Shared Services
As part of the Smart solution, operational/tactical reporting and strategic analytics requirements
will need to be addressed. It is proposed the existing SAP Business Objects suite used at
National Grid be leveraged. This gap will be addressed in detail during the Business
Requirements phase, once the specific business metrics and KPIs for the Program have been

Changes to other systems within the Shared Services area, such as accounting systems
Powerplant and PeopleSoft, have been detailed in the above sections within the specific business
area in which the impact occurs.

IS Gap Analysis
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         Through a recent RFI process, National Grid has sought to obtain the most current 
information on Smart Grid technologies, services, and pricing.  This process was not designed to 
identify specific vendors, but was intended to familiarize National Grid’s Smart Program team 
with the capabilities and limitations of key technologies and to identify those technologies and 
services that will be utilized during the Program.  Details of the RFI process and its outcome are 
provided below.     
         A.      RFI Process 
         Due to the size and scope of the RFI, technical specifications were divided into three 
distinct areas:  
       • Information Systems and Telecommunications (“IS” and “Comms”) 
       • Smart Meters, Home Display Unit (“HDU”) and related equipment 
       • Smart Grid Technology  
       Within each of the above areas, the RFI defined distinct “service layers,” based on logical 
groupings of functionality. These service layers formed the Smart Services conceptual technical 
model, on which the RFI content was based. 
       Eighty‐five vendors were invited to submit relevant information for the solution as a 
whole, or for specific service layers.  National Grid’s assumption is no single technology solution 
would address all of the diverse customers and circumstances of the Program, and therefore 
invited proposals that encompassed a multitude of technology options.  
       The RFI requested detailed information about products, software and services; 
functionality, availability, Smart Program and mass deployment pricing; customer references 
and vendor financial information (to assess viability as well as readiness to undertake the 
Program and inform volume production rollout).  
  ACTIVITY                                               DATE 
  RFI Issued                                             December 12th 2008 
  Vendors Pre‐Bid Meeting                                December 16th 2008 
  Last date for posting queries on Q&A                   January 5th 2009 

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    RFI Closing Date & Time                                 January 13th 2009  
          The RFI imposed the following minimum requirements as a guide for responses: 
          •     Integrated grid / network communications. 
          •     Advanced smart meters that support real time interval measurement, 
                communication of consumption details, upgrade ability and control from a remote 
          •     Load management capabilities to support demand side management programs. 
          •     Remote status detection and operation of electric distribution grid equipment. 
          •     Time of use (TOU) hourly pricing. 
          •     Potential reductions of peak and average load consumption by Smart Program 
          •     Vendors were required to include full technical details and compliance with 
                specified functionality within each service layer with their responses.  In addition to 
                requests for individual component solutions, we also invited more comprehensive 
                proposals that included multiple components or full solutions.   
          B.       Evaluation Process  
         The RFI evaluation process was designed to consider National Grid’s business, technical, 
financial, and regulatory needs and objectives for the Smart Program.  The Evaluation Team was 
led by a dedicated Smart Project Team and via a series of workshops, engaged National Grid 
subject matter experts in customer service, communications, metering, grid operations, and 
rates.  In addition, outside experts with experience in Smart Grid technology, utility information 
systems, program and mass deployments, business, and finance participated.   
         Because the RFI was released to a wide list of vendors, the evaluation process was 
designed to funnel from a large list down to the best potential options in three stages:   
         • First level evaluation: Vendor Self Assessment scoring. 
         • Second level evaluation: National Grid Project team scoring verification and 
             assessment workshops. 
         • Third level evaluation: Detailed Vendor clarification workshops. 
         Evaluation was carried out in a structured way with dedicated teams focusing on key 
aspects, as presented below: 

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The table below describes the high level activities and responsibilities of the evaluation teams.  
This matrix indicates whether a team was Responsible, Accountable, Consulted or Informed 
(“RACI”) regarding each specified activity. 
  Activity                                         Role                             R  A  C  I 

                                                      Procurement Team              √  √          
    Commercial Evaluation 
                                                      Others ‐ Evaluation Team      √        √  √ 
                                                      Business Project Manager          √         
    Evaluation of Grid End Point Devices              Business Team                 √             
    Responses                                         Grid SME                      √        √   
                                                      Others ‐ Evaluation Team                 √ 
                                                      Business Team Lead              √         
    Evaluation of Customer Facing End Point           National Grid SME             √        √   
    Devices Responses  
                                                      Business Team                 √             
                                                      Others ‐ Evaluation Team                   √ 
    Evaluation of IS and Comms Responses              IS Project Manager              √           
                                                      IS Team Lead                    √           
                                                      National Grid COMMS SME       √  √          

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    Activity                                        Role                         R    A    C    I 
                                                    IS Team                      √               
                                                    Others ‐ Evaluation Team               √    √ 
                                                    Steering Group                    √          
                                                    Procurement Team             √               
    Recommended Solution Options                    Business Team                √               
                                                    IS Team                      √               
                                                    Others ‐ Evaluation Team               √    √ 
          C.    Responses  
         As noted, 85 vendors received the RFI, and National Grid received 43 responses. The 
responses were grouped as follows, based on National Grid’s internal designation of Service 
Layer Groups: 
                 i.      Responses by Category 
                                                             Total Responses 
  Home (H1 – H9)                                                     5 
  Grid (G1‐ G6)                                                      4 
  IS and Communications 
  (S1, S2, S3, S4, S5, S6, S7, S8) 
  Home and Grid (H, G)                                               1 
  Home and IS & Comms (H and S layers)                               7 
  Grid and IS & Comms (G and S layers)                               3 
  All (H, G and S layers)                                           10 
  No Responses Received                                             42 
  Total                                                             85 

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              ii.     First Level Evaluation – Vendor Self Assessment 
        The vendor RFI responses were rated using predefined, simple evaluation criteria that 
relied on a consistent scoring mechanism.  Vendors were provided with specific requirements 

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and expected to respond using a Microsoft Excel format template predefined in the RFI. 
Vendors were asked to score their products and services based on Compliance with the 
specified functions in each of the service layers and current availability.   
        Functional maturity was scored: 
        2 …if Vendor considered the specific function was fully met 
        1 … if Vendor considered the specific function was partially met  
        0 … if Vendor considered the specific function was not met  
        Availability was scored: 
        5…if vendor considered the function to be production available 
        4…if vendor considered the function to be in beta testing  
        3…if vendor considered the function to be in proof of concept testing  
        2…if vendor considered the function to be in development  
        1…if vendor considered the function to be planned for a future release  
        0…if vendor considered the function to be not available  
        A combined factor score (functional maturity times availability) was applied to each 
function and then averaged across all functions in a particular service layer. 
        Vendor offerings were then allocated to one of three categories based on their overall 
combined factor score: 
        7 and above……..HIGH 
        3 to 7…………….MED 
        0 to 3 ……………LOW 
HIGH                 Available Solution 
                     Responses that fall into this category indicate a vendor product / solution: 
                          • Has proven technology. 
                          • Has hardware and software production available. 
Criteria                  • Is ready for deployment (and may already be deployed at other 
                          • Supports requirements from RFI. 
                          • Has strong organizational support e.g., warranty, service support.  
                     Responses from vendors with solutions falling under this category will be 
                     considered for detailed analysis and further vendor workshops 

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MEDIUM            Emergent   
                  Responses that fall under this category indicate a vendor product / solution:
Criteria             • Has established customer demo units. 
                     • Is not yet deployed into production. 
                  Such responses will be considered to fill‐in any service layer gaps left by the 
                  above (HIGH category solutions) in the Program framework. 
                  Vendors for who the responses fall under this category may be engaged by 
                  National Grid at a later stage for further evaluation. 
LOW*              Conceptual   
                  Responses that fall under this category indicate the vendor product / 
Criteria          solution is in a conceptual stage and not yet built or deployed into 
                  Vendors for whom the responses fall under this category will not be 
                  considered for the Program. However, such vendors will be referred to 
Considerations    National Grid R&D and will be monitored.  If they become available and are 
                  deemed satisfactory during the course of the Program, they could be 
                  considered for inclusion for volume roll‐outs 
*Those products and services ranked in the LOW category were not included in the second 
phase of the evaluation process, team evaluation.  
               iii.   Second Level Evaluation – Project Team Assessment 
       The team evaluations were designed for National Grid to validate the vendors’ self‐ 
assessment score by reviewing responses against the supporting information provided by the 
vendors and based on information obtained from their references.  The team evaluations were 
organized into functional and technical workshops, as follows:  
Functional/ Technical Workshops (Service Layer Reference) 
   • Workshop 1: Grid Facing End Point Devices  (G1 – G6) 
   • Workshop 2: Metering Devices (H1‐H4) 
   • Workshop 3: Customer Facing End Point Devices (H5‐H9)   
   • Workshop 4: Communications (S1) 
   • Workshop 5: Meter Data Management (S2) 
   • Workshop 6: Grid Data Management (S3) 
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    •   Workshop 7: Integration ‐ Application and System (S4, S8) 
    •   Workshop 8: Web Presentation, Messaging and Mobile Devices (S5‐S7) 
        More than thirty National Grid subject matter experts attended the functional and 
technical workshops.  All of the “medium” and “high” scored solutions from the First Level 
Evaluation stage were re‐evaluated by these teams, using the supporting documentation 
provided by each vendor. The workshop teams reviewed the vendor self‐assessment scores and 
adjusted them based on consensus agreement of:  
    1. Product/ Solution maturity 
    2. Product/ Solution scalability  
    3. Product/ Solution architecture flexibility 
    4. Product/ Solution interoperability 
    5. Proven track record 
               iv.     Third Level Evaluation – Vendor Clarification Workshops 
        Those vendors scoring highest in the first two phases by service layer were advanced to 
a third phase for further consideration.  These vendors were engaged in direct, detailed 
discussion with the National Grid Smart Project team and relevant subject matter experts in a 
workshop environment. The objective of these workshops was to expand National Grid’s 
understanding of the technology, services, and vendors beyond the level of information that 
can be captured in documentation or RFI responses.  This interactive phase enabled the team 
members to articulate National Grid’s Smart Grid vision, ask specific questions and generally 
refine their understanding; and gave vendors the opportunity to explain their responses, ask 
their own questions and present additional information regarding their offerings.  These 
discussions focused on three major areas, technical solution, Smart Program implementation, 
and commercial issues (pricing and financials), but also included areas such as security 
considerations, product and company scalability, and clarifying functional capabilities. 
        D.     Evaluation Results 
        As show in the graph below, the process started with 43 vendors.  Working through 
each step in the evaluation process resulted in fewer eligible vendors until the last step which 
provided the Company with a group of 4‐6 vendors.   

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       E.      Summary 
        National Grid has conducted a robust and inclusive procurement process to identify and 
cost viable technology solutions.  National Grid has identified multiple providers in each Service 
Layer and is ready to begin negotiations, once we receive regulatory approval. 

Attachment 11
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Smart Communications Technologies

      In the development of the New York Smart Program, we separated the

required communications into three layers. The technology chosen for each

layer along with key selection drivers are detailed in the following


Home Area Network (HAN)

      As part of the Smart Program, National Grid will deploy a Home Area

Network in customer homes. This network will provide connectivity from

the electric meter to a number of devices. These devices will include, but are

not limited to:

          • Load Control

          • Thermostats

          • Other utility meters

          • In-home display for displaying pricing and usage information
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         • Appliances

         • Hot Water Heater

         • Home Automation Devices

      The Smart system will use the electric meter as a communications

gateway into the customer home. In this configuration, the meter is expected

to have the functionality and proven capability to routinely and successfully

communicate externally with some devices in the home. The

communications module embedded in the meter will be robust enough to

support the level of communications and controls necessary for Smart

Program tariffs.

      For the Smart Program, National Grid proposes to use Zibgee

communications into the home. The vendors selected for the Smart Program

all adhere to this communications standard. In fact, nearly all bidders that

responded to the RFI use Zigbee or are in the process of adding that

capability, suggesting a significant level of industry acceptance. Zigbee will

provide communications between the meter and at least two home area
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devices. This approach will allow remote control for demand-response and

will provide sufficient bandwidth for an in-home display unit. As part of the

Smart Program, we will also evaluate a more feature-rich in home solution

approach that will provide automated customer control of a much broader

group of in-home devices, near real-time display of consumption data and

billing data, and remote access and control. This solution will require a

much higher bandwidth and speed than needed for the core services. We

propose deploying this capability to customers with existing broadband

connections who select the most sophisticated home automation alternatives.

Local Area Network (LAN)

      National Grid will deploy a series of data collectors and a LAN

throughout the Smart Program area to relay data and communications to and

from in-home devices, meters, and some grid devices. The LAN topology

will be point to multipoint, mesh, or a combination of both.
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      Local area networks will concentrate into a larger Wide Area Network

(WAN). This network will provide connectivity from the meter data

collectors to higher level concentrators and/or directly back to National

Grid’s facilities. National Grid’s use of its existing fiber and a common

infrastructure for grid and metering devices has been a key consideration in

our technology selection. Use of the same infrastructure to communicate

with grid operational devices, meters, and in-home display units will achieve

cost efficiencies. The technologies under consideration for the devices on

the WAN included:

             • Fiber Optic Communications

             • Private or Public Data Radio Systems

             • Broadband Over Power-line Carrier (BPL)

             • Public Cellular Networks

             • Other Public Data Networks
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       In areas were existing National Grid network assets are available, they

will be used. For example, in locations were we have a fiber multiplexor

connected to one of our fiber rings, we would provision capacity from that

multiplexor to the head-end location. In some instances, the LAN collector

infrastructure will extend out to the locations where our multiplexors are

installed. In other areas, we may need to extend the reach of the last

collector. In those instances, the technology we propose to use is a private

wireless WiMAX solution. A WiMAX infrastructure can be implemented to

provide backhaul connectivity for multiple collectors back to one of our

network points. The desire is to place WiMAX base stations at National Grid

locations such as substations or service centers. In some instances we may

use existing radio/microwave sites that have tower structures and space. As

a last resort, we may need to lease space on an existing public

communications tower or other third party structure.

Certain low-latency grid devices will communicate with the WiMAX base

stations directly.
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      At least one of the WiMAX base stations will be collocated with

National Grid network equipment. At this location, data will pass to the

National Grid network with a final destination of Westborough,

Massachusetts. We believe we have sufficent network capacity in the

Syracuse and Capital District areas to support the Smart Program. This will

be verified during detailed design. The interface point into the National Grid

data network will be existing service center facilities or substations. We

have sufficient capacity on our microwave links and/or fiber infrastructure to

these facilties to support our data estimate for all Smart Program devices.
Attachment 12
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1         Purpose.......................................................................................................2

2         Information Systems Summary ................................................................2
    2.1     New Vendor Solutions .................................................................................................... 2
    2.2     Existing Applications...................................................................................................... 3

3         Conceptual Technical Model Service Layers ..........................................3
    3.1     Communications (HAN/LAN/WAN) (S1)........................................................................ 3
    3.2     Meter Data Management Services (S2) ......................................................................... 3
    3.3     Grid Data Management Services (S3) ........................................................................... 4
    3.4     Enterprise application integration and Business Process Management (S4) .......... 5
    3.5     Web Solution, Messaging and Mobile Devices (S5, S6, S7) ....................................... 6
    3.6     Data Warehouse & Business Intelligence .................................................................... 7
    3.7     Process Modeling ........................................................................................................... 7
    3.8     Existing Applications...................................................................................................... 8
     3.8.1        CRM / Customer Services ....................................................................................... 8
     3.8.2        Geo-Spatial Data (GIS)............................................................................................. 8
     3.8.3        Work Management ................................................................................................... 8
     3.8.4        Work Scheduling & Dispatch.................................................................................. 8
     3.8.5        ERP (Acc Payables / Acc Receivable) and Asset Accounting ............................ 9
     3.8.6        Asset Management .................................................................................................. 9

4         End-to-end Solution map of Smart Services Solution ............................9

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1 Purpose
The purpose of this document is to summarize the end-to-end technological solution
landscape for the Smart Services pilot program. Vendors were identified from the vendor
evaluation sessions that were conducted based on the RFI responses from each vendor
supporting specific service layers within the Conceptual Technical Model (CTM).

2 Information Systems Summary
Based on the vendor evaluation sessions held with participation from National Grid
subject-matter experts, a number of vendors were short-listed for the Smart Solution for
each service layer.

2.1 New Vendor Solutions
    Service Layer           Solution Offering           Technology
    S1 – HAN / LAN / WAN    Communications              •   RF
                                                        •   Head end software
    S2 – Meter Data         AMI Meter Head end
                                                        •   Back office integration software
    Management Services
                            Meter Data Management       •   Meter Data Management

    Customer Billing        Customer Billing            •   Billing software

                            •   GRID Head end
                                                        •   SCADA software and repository
    S3 – Grid Data          •   DMS & Grid Analytics
    Management Services
                            •   Grid Analytics          •   Analytics software

    S4 – Enterprise
                            Middleware                  •   EAI and BPM tool
    Integration and BPM
                            •  Home Automation
    S5 – Web solution          Head end
                                                        •   Customer-facing energy
    S6 – Messaging          • Web Presentation
                                                            conservation tool
    S7 – Mobile Devices     • Messaging & Mobile
    Data Warehouse &        Business KPIs and           •   Data Warehouse
    Business Intelligence      Metrics                  •   Reporting and Metrics tools

    Process Modeling        Process modeling            •   Process modeling software

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2.2 Existing Applications
    Service Layer    Solution Offering                   Vendor
    CRM / Customer
                     CSS Suite                           •   Customer support suite
                     •   Geo-spatial data (GIS)          •   Geo-spatial software and
                     •   Work Management                     repository
                     •   Work scheduling and dispatch    •   Work scheduling and customer-
    Back office      •   Asset Management                    system interfacing
    applications                                         •   Workforce management and
                                                             field job scheduling
                                                         •   Asset Management and
                     •   ERP (Accounts Payable /
                                                         •   ERP finance software solution
    Financials           Accounts receivable)
                                                         •   Asset accounting software
                     •   Asset accounting

3 Conceptual Technical Model Service Layers

3.1 Communications (HAN/LAN/WAN) (S1)
The RF LAN is a “Hang and Run” communication network that is self-configuring
(automatic addition or removal of devices), self-optimizing, and self-healing, providing
diagnostics capable of detecting abnormal device operating parameters including, but
not limited to, memory failure, power supply degradation, microprocessors(s) failures
(ex. watch dog events), firmware/software problems, excessive device temperature, non-
responsiveness, etc.

3.2 Meter Data Management Services (S2)
The Meter Data Management System (MDMS) will serve as the system of record for all
metered data and will play a central and crucial role in creating and capturing the key
benefits from the AMI. Data gathered, processed and made available in the MDMS will
provide near real-time intelligence in National Grid’s utility operations.

The MDMS Layer will facilitate better customer care and energy utilization by
disseminating interval-based meter data to multiple applications like Customer
Information Systems (CIS), Billing, Customer Care and other Distribution Network

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Management systems. It will bridge the Smart Services with other internal systems
hence insulating internal processes from the highly evolving AMI technologies. The
MDMS is broken down in service layers as below:

AMI Head End - The AMI Head End will receive Smart Meter data from the head end
collectors and perform two-way communication (using different protocols) between the
MDM and the installed meters.
Customer Demand - The Customer Demand service layer within the MDMS supports
management of customer meters directed from MDMS. Various peak pricing and
demand functions are managed through functionality defined in this layer
Meter Data Management - The meter data management layer supports all functions
related to the managing data collected and fed from the AMI head end software like
aggregation of raw meter data, performing VEE (validating, editing, and estimating)
functions and other functionalities related to storing of data and visualization of meter
information for metrics purposes.

3.3 Grid Data Management Services (S3)

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This service layer covers the functionality required for grid data transmission, processing
and reporting. The layer will serve as the system of record for all grid device data
received from field devices. Data is captured from the Head End software, processed
and made available to National Grid’s utility operations in near real-time.
National Grid’s solution will facilitate better grid control and monitoring capabilities as
more near real-time information is made available. To meet this requirement, the
solution will be highly scalable and flexible so changes to business processes can easily
and quickly be incorporated into the technical solution.

3.4 Enterprise application integration and Business Process
    Management (S4)

The EAI layer provides a standards-based, open, extensible platform for developing
software infrastructures using a service-oriented architecture approach. This unified and
comprehensive suite can help your enterprise create composite applications from
existing investments as well as deliver new business services in a flexible SOA
environment with no vendor lock-in.

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3.5 Web Solution, Messaging and Mobile Devices (S5, S6, S7)

This includes the Customer care self service portal for all the customer requirements
from bill presentment and payment to home/business management and control.

Customer Focused: Features of the customer conservation software solution include:
• Allows home owners to access and control their home energy consumption
   anywhere, anytime – over the Internet, from PCs, or even handheld devices such as
   Blackberry and iPhone. It provides full analysis of their energy consumption, billing
   information and time of use patterns. This analysis seamlessly ties into utility
   distributed generation programs as well as user defined programs and device control
   to allow the home owner to have effective real-time control over how and when they
   use energy.
• Allows Utility Companies to execute demand control programs and receive real time
   feedback and reports from participating homes and communities for energy planning
   and grid control.
• The software is an enterprise architected, fully flexible solution. Customers can
   deploy the full solution, or choose to deploy those pieces that best fit their existing

Grid Focused: The energy management software is an advanced smart grid and
energy management solution. It provides full support for end to end grid management
including support for meter, and transformer monitoring, distributed generation control

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and demand response execution. Through a combination of user defined programs, the
software responds to grid signals, schedules, pricing or environmental signals, or on
demand execution. These executions will interact with all distributed energy resources
(DER), either distributed generation (DG) or demand response (DR) to enable smart
power management across the grid.

3.6 Data Warehouse & Business Intelligence
The Data Warehouse will support National Grid’s information needs by integrating data
requirements of the enterprise and hence support the analysis and reporting
requirements of the entire organization.
• The Data Warehouse serves a broad user community providing an integrated view of
   the organization.
• Data is cleansed and at granular level and is stored in a consistent form (not
• The Data Warehouse contains time-based historical data.
• Significant or often-used data is summarized by structuring it to align with business
   areas. These summaries are driven by analytic requirements from the business

Business Intelligence activities involve providing historical, current and predictive views
of the various business operations. This is accomplished through various tools that
provide multi-dimensional analysis capabilities, which will slice-and-dice through data
providing insight into various business and/or customer trends to support better business
decision-making. The source of data for these BI activities will be the Data Warehouse.

3.7 Process Modeling
Process modeling helps conceptualize business processes to achieve process
governance and aligning enterprise IT architecture to business architecture to meet
business needs. The benefits of using a process modeling tool helps in documenting
and publishing process knowledge of the organization increasing process performance.

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3.8 Existing Applications

3.8.1 CRM / Customer Services
Customer Services systems allows customer representatives to support Smart
customers. The customer systems provide information regarding every aspect of utility
customer information-service connection, meter reads, rating, billing, and more-while
also undertaking associated functions like payment processing, collections, field service,
and meter management.

3.8.2 Geo-Spatial Data (GIS)
The GIS system provides the X and Y co-ordinates for the location of each of the
devices to assist in providing the exact location for field crew. The GIS system provides
a pictorial representation of the existing topology of all the devices currently on the field.

The current system supporting the geographical positioning of the existing devices will
continue to support the topological requirements of the Smart devices.

3.8.3 Work Management
Customer and Grid devices installation, repair, and maintenance activities are managed
through the work management system providing the work crew with timely information.

Customer requests for maintenance activities are entered in the customer support
systems generating service orders. Work status on service orders is updated by the field
crew which provides the customer representatives details on status within the customer
support applications.

3.8.4 Work Scheduling & Dispatch
Work Scheduling and Dispatch ensures service availability and automates field
operations via dispatch, scheduling, and routing.

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3.8.5 ERP (Acc Payables / Acc Receivable) and Asset
All financial functions for accounts payables and accounts receivables will be continued
using the existing ERP application suite.

Asset accounting will be managed using the existing software suite with changes to
handle Smart project specific devices.

3.8.6 Asset Management
National Grid’s current asset repository will be used to support the asset management
functions of the Smart project. The asset repository provides details on all the metering
assets currently available. It is the source for the CSS system to assign an asset to a

4 End-to-end Solution map of Smart Services Solution
The Smart Services IS & Comms solution for the pilot will consist of new applications as
well as existing applications that will be integrated to provide an end-to-end solution.

The gaps and high-level effort to enhance and integrate existing applications to meet the
requirements of the Smart solution have been provided in Attachment 9 Gap analysis

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                                           Data Model

Table of Contents 

1.   Purpose of Document ............................................................................................2
2.   Overview of approach............................................................................................2
3.   High‐level Conceptual Data Model ........................................................................2
4.   High‐level Conceptual Data Model for Meter Data Management ........................4

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1. Purpose of Document

  The purpose of this document is to identify the high-level technology agnostic conceptual data
  model from a data perspective that has enterprise applicability. The conceptual data model
  consists of various business entities and forms the basis for further understanding of the
  business semantics of the various operational areas within the organization. It is in the form of
  an entity relationship model (ERD) which helps understand and capture the business
  knowledge from a data perspective. The ERD further helps breakdown the various business
  entities into atomic levels for the logical and physical data models. The document denotes the
  envisaged state of the enterprise data and is meant to provide an understanding of the
  various data areas that span multiple systems across the enterprise.

2. Overview of approach
  The below conceptual data model is created based on envisioned future state of the Smart
  Services program and includes the data subject areas from the current systems and future
  business entities that will form the end solution. Industry standard methodologies and data
  modeling best practices were used to create the data model.

3. High-level Conceptual Data Model

  The following notations are industry-standard representations in Information Engineering for
  denoting relationships between entities as identified below in the conceptual data model.

        - Zero or more occurrences

        - One of more occurrences

        - One and only one occurrence

  For example in the diagram below

  -   “CUSTOMER” may have one-or-more “CUSTOMER BILLING ACCOUNT”

  The principle behind design of the conceptual data model is NOT to identify any business
  processes, but rather only the data needs of the organization. Its function is to show the
  relationships between the various business entities. For example a data feed from one
  system to another is not documented in this model. Such representations would be part of the
  process-flow diagrams.

  Also as these business entities are at a much higher level, a conceptual data model does not
  indicate any data attributes. Data attributes are captured in the logical and physical data
  models which are achieved by further drilling down from the conceptual data model.

  While the logical data model can be created at an enterprise level to represent every single
  data attribute required across the enterprise, the physical data model breaks down to

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application / system specific level. A general real-world scenario involves data attribute
specific logical and physical data models.

The various business entities are detailed below:

1. Customer – This is the residential, commercial or industrial customers who are National
2. Customer Billing Account – This represents the billing information for customers and all
   related activities tied to CRM
3. Meter Interval Data – This represents the customer power consumption (interval data) as
   recorded by the meters
4. Metering Network Infrastructure – This represents the Advanced Metering Infrastructure
   (AMI) of installed asset base
5. Asset
       a. Meter – These are the meter assets at National Grid
       b. Grid – These are the grid device assets at National Grid
6. Geo-Spatial – Represents the geographical co-ordinates of the location of each asset in
   the field

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  7. Grid Network Infrastructure – This represents the near real-time (SCADA) grid device
      level information acquired from the field
  8. Grid Device Data – This represents the interval data received from the field devices rolled
      up to measureable information
  9. Installed Assets – This represents the customer-to-meter cross reference as well as the
      grid devices installed in the distribution and transmission grid.
  10. Work Order – this represents all installation and maintenance work orders created for all
      residential and C&I.
  11. Field Worker – This is the representation of the internal or contracted field worker working
      in the field
  12. Finance – This represents the Accounts Receivables and Accounts Payables for the
      company and all other information pertaining the installed assets
  13. Independent System Operator (ISO) – This is the supplier of power that National Grid
      contracts with
  14. Contract & Tariff – This represents contracts and tariffs agreed with the ISO for
      purchasing of power for distribution
  15. Supplier Billing Account – This is the billing account information for the ISO
  16. Transmission Supply – This represents the power supplied details as purchased from the
  17. Energy Control and Monitor – This represents all data that monitors and controls energy
      demand by customers and supply by power suppliers

4. High-level Conceptual Data Model for Meter Data Management

  A conceptual data model for only the Meter Data Management shown below illustrates some
  of the relationships between the various physical elements of the solution.

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                              INTEGRATION OUTLINE

1   Purpose

The delivery of an IS Solution for National Grid’s Smart Program will impact existing
applications and introduce new applications to the IS landscape. The majority of these
applications are expected to involve the sharing of data or the connecting of processes.
As a result, application integration is critical for an end-to-end solution.
The Application Integration solution will build interfaces to cater to new and existing
(legacy) applications around an Enterprise Service Bus (ESB). A Common Messaging
Model based on CIM (Common Information Model – IEC 61968/61970) will be utilized
for the messages passed to and from the various applications on the ESB.
Business Process Management will be utilized to capture and track sub-second, near real-
time information on the processes being managed, and will also monitor and track events
as they occur on the ESB.
The solution architecture identifies the existing interfaces requiring modification. It also
identifies at a high-level the estimated number of interfaces to be built and recommends
the next steps to be completed prior to moving into the detailed technical design phase.

2 Integration Scope of the Program
Application Integration is defined as “sharing or connecting processes and/or data
between applications.” The key areas in scope of Application Integration for National
Grid’s SMART Program are:
1. Area-1: Integration among the New Applications introduced as part of the Smart
   Program. It broadly includes two sub-areas – Smart Metering and Smart Grid
2. Area-2: Integration of the New Applications (introduced as part of the Smart
   Program) with Existing Applications within National Grid. The list of key existing
   applications includes Enterprise Asset Management, Work Management, Mobile
   Workforce Management, Billing and Payments, Customer Services, Portal,
   Distribution Management System, Outage Management System, Management
   Information and Business Intelligence
3. Area-3: Modifications to Existing Integration between the Existing Applications
   within National Grid. It includes changes to existing interfaces such as adding new
   data entities to share across existing applications
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4. Area-4: Business-to-Business (B2B) Integration. It includes Integration (or service)
   end-points at the boundaries of National Grid to provide an Integration platform for
   data and information sharing between National Grid and the External Parties
The area highlighted in red in the diagram below depicts the scope of Application
Integration for the Smart Program.

                                              B2B Integration             Portal or similar
                                               (end-points for           presentation layer
                                              External parties)

                                                  Smart Metering            Smart Grid
                                                   Applications             Applications
                 Smart Meter Head-end

                                                                                              Smart Grid Head-end

  Smart Meters
                                                                                                                    Smart Grid

                                                            Existing Enterprise

                                           Identity Management        Enterprise Operations

                                        Figure 1: Scope of Application Integration

The list below highlights the areas considered outside of the Application Integration
scope based on the Conceptual Technical Model for the Smart Program.
    Communication between the various field (or home) devices within the Home Area
    Network (HAN), Local Area Network (LAN) and Wide Area Networks (WAN)
    Communication between the HAN, LAN and WAN
    Communication between the various field (or home) devices and the Smart Meter
    Head-end applications
    Communication between the various field (or home) devices and the Smart Grid
    Head-end applications
    Communication between the various field (or home) devices and the Data center
    applications such as mobile messaging, emails and others
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    Provision of a Portal or any similar visual presentation layer. However, the scope
    includes the integration of relevant applications to a Portal or to any similar visual
    presentation layer (covered in Area-1 and Area-2)
    Integration at the end-points that reside outside the boundaries of National Grid i.e.
    end-points on B2B applications or systems hosted and maintained by External Parties

3 Integration Scope of the Smart Program
The scope of Application Integration for the Smart Program includes:
•   Area-1: Integration among the New Applications introduced as part of the Smart
    Program. It broadly includes the following:
           o Smart Meter AMI Head-end system(s)
           o Meter Data Management System(s) (MDM)
           o MDM Billing engine
           o Smart Grid Head-end System(s)
           o Home Automation System
           o Home Automation Head End
           o Distribution Management System
           o Outage Management System
           o SMART Portal
           o Grid Repository
•   Area-2: Integration of the New Applications (as listed above) with Existing
    Applications within National Grid. The list of key existing applications includes:
           o Customer Services suite (CSS)
           o Energy Resource System (ERS) – Meter Data Repository
           o Geographical Information System (GIS) – SmallWorld
           o STORMS – Work Management System
           o MITS – Meter Asset repository
           o PEOPLESOFT
•   Area-3: Modifications to Existing Integration between the Existing Applications
    within National Grid. It is likely to include changes to existing interfaces around:
           o Customer Services Suite (CSS) including Customer Billing, Tariff,
             Presentment and support
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             o ERS
             o MITS
             o STORMS
             o GIS
The list below highlights the areas considered out of scope for the Smart Program:
     •   It is understood the following business functions will be serviced through existing
         capabilities/systems or will be carried offline. Hence, there are no requirements
         identified for any new, or modifications to existing, application integration around
         these business functions. These include:
                 o Procurement and Logistics - to be offline
                 o Mobile Workforce Management –to use existing interfaces with Work
                   Management or through the External Meter Installation Vendor
                 o Sales and Marketing - to be offline
                 o Shared Services such as Finance, HR and others - to be offline
     •   Area-4: Business-to-Business (B2B) Integration i.e. Integration (or service) end-
         points at the boundaries of National Grid to provide an Integration platform for
         data and information sharing between National Grid and External Parties

4 Principles for Application Integration
The table below lists key application integration principles and associated rationale.
Ref. Principle                                       Rationale
P1       Plan for Integration and Plan for           Application Integration is typically
         Growth in Integration                       considered too late, during the build
         Application Integration must be started     stages of the Solution Delivery Process.
                                                     This results in missing interfaces or
         early in the Project and included in
                                                     poor quality interfaces such as Point-to-
         Project Plan. All the key deliverables of
         the Solution Delivery Process must be       point (P2P) that are built and deployed
         associated with Application Integration.
         IS must plan, design and build the          Adherence to this principle results in
         Application Integration to cater to         robust, complete and more cost-
         known future growth and expansion of        effective Application Integration. It
         Integration.                                would also enable a quicker response
                                                     for future growth and expansions.
P2       Proven Standards and Technologies           Assists in easier integration among
                                                     heterogeneous platforms and systems
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     Application Integration must be               common in the present technical
     delivered on proven standards-based           landscape. Avoids dependence on small
     technologies. The customization of the        or underperforming vendors and
     chosen products should be kept to a           reduces associated risks. Provides for
     minimum.                                      ease of maintenance and offers
                                                   flexibility and adaptability in product
                                                   upgrade or replacement scenarios.
P3   Use of Service Oriented Architecture   A Service Oriented Architecture
                                            Approach to Application Integration
     Application Integration must be based
     on Service Oriented Architecture (SOA) enables integrating diverse,
     to the maximum extent possible         heterogeneous applications developed
                                            in different architectures and
                                            programming languages and on
                                            different platforms. The interfaces
                                            delivered (on SOA) should be loosely-
                                            coupled, interoperable, self-describing
                                            and offer enhanced flexibility to
                                            accommodate the modifications
                                            resulting from changes to Host
P4   Minimal Impact on existing                    Changes to existing applications
     Applications                                  typically result in additional effort and
                                                   cost, leading to project delays, increased
     Application Integration should avoid
                                                   maintenance, and can lead to instability.
     changes to existing Applications
     requiring integration. When this is not
     possible, changes to existing
     applications should be kept to a
P5   Data Security and Protection of               Assists in safeguarding critical and
     Information                                   sensitive data associated with internal
                                                   business departments, business partners
     Application Integration must be
                                                   and end-consumers (public). Enables
     implemented in adherence with policies
     and laws on Data Security and                 compliance with regulatory and other
                                                   government requirements. Ensures data
     Protection of Information. Data and
                                                   integrity and increases the confidence of
     Information must always be protected
                                                   stakeholders and other interested
     against unauthorised access,
     modifications and Denial of Service           parties.

P6   Total Cost of Ownership (TCO)                 Enables a model where investments in
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      The Total Cost of Ownership (resulting    Application Integration are justified
      from Delivery, Infrastructure,            with direct benefits to businesses and
      Deployment, Operational Support,          cost-minimization against future
      Upgrade, Replacement and Migration)       enhancements and growth in
      for Application Integration must          integration. Enables improved planning
      balance the benefits and costs            and decision-making via greater
      associated with Growth in Integration,    visibility of investments associated with
      Flexibility to Change or Enhance,         Application Integration while delivering
      Scalability and Ease of Use               quality solutions.
P7    Change Management                       Software (or Code) Configuration and
                                              Change Management is followed for
      Application Integration must follow
                                              managing Host Applications. However,
      procedures and conform to policies as
      set by Software (or Code) Configuration it is not followed for Application
      and Change Management (SCCM)            Integration. SCCM is important for
                                              Application Integration as the number
                                              of interfaces and the applications reliant
                                              on those interfaces are increasing.

                     Table 1: Application Integration Principles

5 Architecture Building Blocks
The Building Blocks of an Application Integration Architecture specify (or define)
individual services and the relationship among those services required to enable
Application Integration.
The diagram below depicts the organization of various building blocks of an Application
Integration Architecture for the Smart Program.
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                                                                                                                                              Authentication;; Authorisation;; Identity Management;;
                                                                                   Presentation                  Business-to-Business
                           Integrated Development Environment;; Testing;;

                                                                               Integration Services               Integration Services

                                                                                                                                                                                                                           System Monitoring;; Event Handling;; Business
                                                                                                                                                                                                                           Activity Monitoring;; Configuration and Change
                                                                                                                                                   Security Context Management;; Information
                                                                                   Portal Integration                   B2B Gateway
                                 Process Modelling and Simulation;;

                                                                                                                                                                                                                                  Management;; Directory Services
    Development Services

                                                                                                                                                           Protection;; Non repudiation

                                                                                                                                                                                                                                                                            Operational Services
                                                                                     Business Process Integration Services

                                                                                                                                                                                                       Security Services
                                                                                Orchestration;; Rules and Policy Management;; Transaction
                                                                                 Management;; State Management;; Event Management;;
                                                                                                   Schedule;; Workflow

                                                                                              Data Integration Services
                                                                                  Data Access;; Schema Definition;; Data Mapping;; Data
                                                                                  Validation;; Data Transformation;; Canonical Data Model

                                                                                      Communication Integration Services
                                                                              System Access;; Adapters;; Remote Program Calls;; Messaging;;
                                                                                                      File Transfer

                                                                                          Figure 2: Architecture Building Blocks

6                          Proposed Application Integration Solution

The Integration for the Smart Program will utilize an Enterprise Service Bus built on the
principles of Service Oriented Architecture (SOA). This will aid in integrating distributed
components/applications seamlessly.

In the architecture using an ESB infrastructure the applications are connected through a
communication back bone which facilitates message transfer between the source and
target systems involved. The advantages of this approach are:
                      •                                 Security - the communication is only via the backbone,
                      •                                 Combining – the ESB combines the power of all previous integration approaches:
                                                                            o Is standards-based, scalable, and reusable
                                                                            o Supports heterogeneous communication mechanisms like synchronous,
                                                                              asynchronous, event based etc.
                                                                            o Can support the integration needs of legacy and new systems

It is also the intent to use a Common Message Model for the messages flowing on the
ESB. This will ensure messages on the bus can be utilized by applications connected to
                                 Niagara Mohawk Power Corporation d/b/a National Grid
                                                                     Case 09-E-0310
                                                  New York Smart Program Proposal
                                                                       Attachment 14
                                                                          Page 8 of 8

the ESB in the future, reducing the time and effort required to integrate new applications.
The Industry standard (IEC 61968 & 61970 CIM) will be used for implementation, based
on the level of support for the standard provided by the selected vendor products.

The following diagram depicts the SMART Program application landscape utilizing an
ESB/BPM to achieve the Integration requirements as required by the project.
Attachment 15
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Attachment 18
                                    Niagara Mohawk Power Corporation d/b/a National Grid
                                                                        Case 09-E-0310
                                                     New York Smart Program Proposal
                                                                          Attachment 18
                                                                             Page 1 of 7

                      Terms and Conditions for Smart Grid Pricing

1. Definitions

“New York Smart Program Area” shall mean any area designated by the Company which has
customers having the appropriate equipment to actively participate in Smart Grid Pricing.

“Smart Grid Pricing” shall mean P.S.C. No. 220 Electricity Tariff Rule No. 46 (“Rule 46”)
Electricity Supply Service with Unforced Capacity Charges computed under Rule 46.2.2
provided by the Company to Customers who are located in an area designated as a New York
Smart Program Area.

“Standard Rule 46 Electricity Supply Service” shall mean P.S.C. No. 220 Electricity Tariff
Rule No. 46 Electricity Supply Service with Unforced Capacity Charges computed under
Rule 46.2.1 provided by the Company to Customers who are not located in an area
designated as a New York Smart Program Area or who have opted out of participating in the
Critical Peak Pricing Program or Hourly Pricing Program of the New York Smart Program.

2. Smart Grid Pricing

       a. Applicability

       Except as set forth below, alternative Rule 46 Electricity Supply Service will be
       provided under the Smart Grid Pricing provision for Customers who are located
       within the New York Smart Program Areas. Pursuant to the specific requirements set
       forth below, Customers can opt-out from receiving Smart Grid Pricing under this
       provision and receive Standard Rule 46 Electricity Supply Service.

       Customers receiving retail delivery service pursuant to P.S.C. No. 214 Outdoor
       Lighting Tariff are not eligible for Smart Grid Pricing.

       The receipt of service and rendering of bills under Smart Grid Pricing is contingent
       upon the Company having systems and processes in place to provide the New York
       Smart Program’s communication and notification requirements and the Customer
       having metering, communications, and notification technologies designated by the
       Company and installed and operational at the Customer’s location.

       b. Initiation of Service

       Effective [Effective Date], Customers within the New York Smart Program Areas
       will transition to Smart Grid Pricing on the first day following the regularly scheduled
       meter reading date that falls on or after the [Effective Date].
                              Niagara Mohawk Power Corporation d/b/a National Grid
                                                                  Case 09-E-0310
                                               New York Smart Program Proposal
                                                                    Attachment 18
                                                                       Page 2 of 7

               Terms and Conditions for Smart Grid Pricing

c. Term of Service

Customers that do not opt-out of Smart Grid Pricing shall remain on Smart Grid
Pricing for a period of at least twelve months, commencing with the first billing
month on which the rates for Smart Grid Pricing are billed, and shall terminate no
earlier than the regularly scheduled meter reading date at the end of the twelfth billing
month. Service under this provision shall continue thereafter unless terminated
through the Opt-Out Procedure.

d. Opt-Out Procedure

The Company will send a notification to Smart Grid Pricing Customers prior to the
commencement of the New York Smart Program advising them of their right to opt-
out of Smart Grid Pricing and continue to receive Standard Rule 46 Electricity Supply
Service prior to the commencement of the New York Smart Program. The Company
must be in receipt of a completed “Customer Election to Opt-Out” form no later than
thirty (30) days prior to the Effective Date. Customers that do not opt-out shall
continue to receive alternative Rule 46 Electricity Supply Service under the Smart
Grid Pricing provision for the Term of Service subsequent to the Effective Date.

New Smart Grid Pricing Customers who move into a New York Smart Program Area
during the initial Term of Service will be required to opt out at the time retail delivery
service is requested from the Company.

Existing Customers residing in a New York Smart Program Area who are returning to
Rule 46 Electricity Supply Service from Competitive Suppliers will be placed on the
appropriate Smart Grid Pricing program but will have sixty (60) days to opt out. The
Company will notify the Customer of this right to opt out through a bill message on
the first bill issued by the Company after returning to Rule 46 Electricity Supply

At the end of the initial Term of Service, Smart Grid Pricing Customers will have the
opportunity to opt-out of Smart Grid Pricing. Customers must notify the Company by
submitting a completed “Customer Election to Opt-Out” form at least 15 days in
advance of the end of the Term of Service. Customers that do not provide such notice
shall continue to receive service under Smart Grid Pricing.
                            Niagara Mohawk Power Corporation d/b/a National Grid
                                                                Case 09-E-0310
                                             New York Smart Program Proposal
                                                                  Attachment 18
                                                                     Page 3 of 7

              Terms and Conditions for Smart Grid Pricing

e. Rates for Smart Grid Pricing

The Rule 46.2.2 and the Critical Peak Pricing Statements filed with Commission from
time to time in compliance therewith set forth the applicable Unforced Capacity
hourly charges for each service classification for the Critical Peak Pricing, the Peak
Rebate Pricing, and the Hourly Pricing programs as described below for the
applicable period.

        i. Critical Peak Pricing Program (“CPPP”)

              1. Availability

              Customers receiving retail delivery service on Residential and Farm
              Service, Service Classification No. 1 (“SC-1”), Residential and Farm
              Service - Optional Large Time of Use Rate, Service Classification No.
              1-C (“SC-1C”), and non-demand metered customers on Small General
              Service, Service Classification No. 2 (“SC 2ND") and non-demand
              metered customers on Sale of Standby Service to Customers with On-
              Site Generation Facilities, Service Classification No. 7 (“SC 7”) in the
              New York Smart Program Areas will be enrolled in the CPPP unless
              they have elected to opt out pursuant to the Opt-Out Procedure.
              Customers who participate in the CPPP are not eligible to receive Peak
              Time Rebates.

              2. CPPP Pricing Seasons

              The CPPP Pricing Seasons are defined as follows: (1) Summer Season
              is the calendar months June through August; (2) Winter Season is the
              calendar months December through February; and (3) Off-Season is
              the fall calendar months September through November and the spring
              calendar months March through May.

              3. On-Peak, Shoulder-Peak, Off-Peak, and Critical Peak Time

              On-Peak hours occur Monday through Friday, excluding holidays,
              from 11:00 a.m. to 5:00 p.m. during the Summer Season, and from
              5:00 p.m. to 8:00 p.m. during the Winter Season.
              Niagara Mohawk Power Corporation d/b/a National Grid
                                                  Case 09-E-0310
                               New York Smart Program Proposal
                                                    Attachment 18
                                                       Page 4 of 7

Terms and Conditions for Smart Grid Pricing

Shoulder-Peak hours occur Monday through Friday, excluding
holidays, from 8:00 a.m. to 11:00 a.m. and from 5:00 p.m. to 8:00 p.m.
during the Summer Season, and from 9:00 a.m. to 5:00 p.m. during the
Winter Season.

Off Peak hours will be all other hours.

Critical Peak hours are flexible by event and occur when a Critical
Peak Event is initiated by the Company. During the hours designated
as a Critical Peak Event, the applicable Unforced Capacity hourly
charges for each service classification set forth on the Critical Peak
Pricing Statements in accordance with Rule 46.2.2 shall apply.

The holidays will be: New Year’s Day, Memorial Day, Independence
Day, Labor Day, Thanksgiving Day and Christmas Day. All holidays
will be the nationally observed day.

4. Critical Peak Events for CPPP

The Company may, at its discretion, invoke a Critical Peak Event
during the hours between 8:00 a.m. and 8:00 p.m. during the Summer
Season and during the hours between 9:00 a.m. and 8.00 p.m. during
the Winter Season when the Company determines any of the following
conditions exist: High system peak demand and/or low generation
reserves; system constraints; high wholesale market prices; and/or for
testing/evaluation purposes.

5. Number of Critical Peak Events for CPPP

Critical Peak Events will be limited to 30 Events per year. Each
Critical Peak Event will contain up to eight contiguous Critical Peak
Hours. Critical Peak Hours are limited to a total of 200 hours during
any twelve month period.

6. Notification of Critical Peak Events for CPPP

The Company will notify customers of a Critical Peak Event by
[X:00 p.m.] the day before the Critical Peak Event. Notification will be
provided by selected communications devices as offered by the
Company and as elected by the customer at the time of their
                     Niagara Mohawk Power Corporation d/b/a National Grid
                                                         Case 09-E-0310
                                      New York Smart Program Proposal
                                                           Attachment 18
                                                              Page 5 of 7

       Terms and Conditions for Smart Grid Pricing

       enrollment in Smart Grid Pricing and through direct communication
       with advanced metering and associated equipment configured to
       support to support the Smart Grid Pricing program.

ii. Peak Time Rebate (“PTR”)

Customers who opt out of Smart Grid Pricing pursuant to the Opt-Out
Procedure will receive a Peak Time Rebate. A bill credit will be paid for each
kWh of actual reduction in consumption during the period covered by a
Critical Peak Event. The actual reduction in consumption will be measured
using a customer-specific reference level (“CRL”). The bill credit will be
paid out for any regularly scheduled billing period in which the actual
reduction in consumption is greater than zero. If no Critical Peak Events are
called or there is no reduction in consumption, then no bill credit will be

       1. Critical Peak Event for PTR

       The Company may, at its discretion, invoke a Critical Peak Event for
       PTR as described in Critical Peak Events for CPPP. Critical Peak
       Events for PTR shall be limited as described in Number of Critical
       Peak Events for CPPP.

       2. Customer-Specific Reference Level (“CRL”)

       In order to receive a bill credit, a valid reference usage level must be
       established no later than the occurrence of the first Critical Peak Event
       of the applicable billing period. A CRL is unique to each customer and
       will be calculated for each event. The CRL for each regularly
       scheduled billing period is defined to be the sum of all the CRL’s
       corresponding to all the Critical Peak Events which occur within the
       regularly scheduled billing period.

       A CRL will be:

              a. the kWh usage, as measured by the Company’s metering
                 equipment, for each hour of the Critical Peak Period and
                 for the hour that is two hours prior to the Critical Peak
                 Period, during each of the five business days (excluding
                     Niagara Mohawk Power Corporation d/b/a National Grid
                                                         Case 09-E-0310
                                      New York Smart Program Proposal
                                                           Attachment 18
                                                              Page 6 of 7

       Terms and Conditions for Smart Grid Pricing

                  holidays, shutdowns, and days having called events)
                  immediately prior to the Critical Peak Event, adjusted by

              b. the difference between the kWh usage, as measured by the
                 Company’s metering equipment, for the hour that is two
                 hours prior to the Critical Peak Period, and the value
                 calculated in Part a. above.

       3. Notification of Critical Peak Events for PTR

       The Company will notify customers of a Critical Peak Event as
       described in Notification of Critical Peak Events for CPPP.

iii. Hourly Pricing Program (“HPP”)

       1. Availability

       Customers receiving retail delivery service on all P.S.C. No. 220
       Electricity Tariff Service Classification ineligible to receive Smart
       Grid Pricing under CPPP will be enrolled in the HPP. Customers who
       participate in the HPP are not eligible to receive Peak Time Rebates.

       2. Critical Peak Event for HPP

       The Company may, at its discretion, invoke a Critical Peak Event for
       HPP as described in Critical Peak Events for CPPP. Critical Peak
       Events for HPP shall be limited as described in Number of Critical
       Peak Events for CPPP. During the hours designated as a Critical Peak
       Event, the applicable Unforced Capacity hourly charges for each
       service classification set forth on the Critical Peak Pricing Statements
       in accordance with Rule 46.2.2 shall apply.

       3. Notification of Critical Peak Events for HPP

       The Company will notify customers of a Critical Peak Event as
       described in Notification of Critical Peak Events for CPPP.
                             Niagara Mohawk Power Corporation d/b/a National Grid
                                                                 Case 09-E-0310
                                              New York Smart Program Proposal
                                                                   Attachment 18
                                                                      Page 7 of 7

              Terms and Conditions for Smart Grid Pricing

               4. Price Notification

               The Company will make hourly energy prices available on its Hourly
               Electric Supply Charges website each day by 4:00 p.m. for the
               subsequent day.

f. Bill Protection

Smart Grid Pricing Customers billed under CPPP and HPP will be provided an annual
bill credit to the extent alternative Rule 46 Electricity Supply Service charges under
Smart Grid Pricing exceed what would have been charged under Standard Rule 46
Electricity Supply Service rates for a full year. The Company shall calculate what
Standard Rule 46 Electricity Supply Service charges would have been billed. Bill
credits will be applied to eligible customers during the fifth billing month subsequent
to the end of the initial Term of Service.

For Smart Grid Pricing Customers who leave a New York Smart Program Area
during the initial Term of Service, no bill credit will be provided.

For new Smart Grid Pricing Customers who move into a New York Smart Program
Area during the initial Term of Service and for existing Customers residing in the
New York Smart Program Area who are returning to Rule 46 Electricity Supply
Service from Competitive Suppliers, no bill credit will be provided for the remaining
initial Term of Service.

The Company will issue bill credits annually during the operation of the New York
Smart Program for customers remaining on Smart Grid Pricing.
For Smart Grid Pricing Customers under CPPP and HPP that are billed less under
Smart Grid Pricing as compared to Standard Rule 46 Electricity Supply Service rates,
no bill credit will be provided.
Attachment 19
Niagara Mohawk Power Corporation d/b/a National Grid
Case 09-E-0310
New York Smart Program Proposal
Attachment 19
Page 1 of 3
Niagara Mohawk Power Corporation d/b/a National Grid
Case 09-E-0310
New York Smart Program Proposal
Attachment 19
Page 2 of 3
Niagara Mohawk Power Corporation d/b/a National Grid
Case 09-E-0310
New York Smart Program Proposal
Attachment 19
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Attachment 20
                                                                                        Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                            Case 09-E-0310
                                                                                                          New York Smart Program Proposal
                                                                                                                              Attachment 20
                                                                                                                                 Page 1 of 4

                                                          Results of Cluster Analysis

                 Date            ISO Hour         Hourly Load         Day of Week       Max Load                Cluster           Distance
           06/09/2008          9:00:00 AM            27,312.2             Monday         32,431.6                     3           6,027.1
           06/09/2008         10:00:00 AM            28,732.0             Monday         32,431.6                     3           6,027.1
           06/09/2008         11:00:00 AM            29,795.9             Monday         32,431.6                     3           6,027.1
           06/09/2008         12:00:00 PM            30,539.8             Monday         32,431.6                     3           6,027.1
           06/09/2008          1:00:00 PM            31,261.0             Monday         32,431.6                     3           6,027.1
           06/09/2008          2:00:00 PM            31,728.6             Monday         32,431.6                     3           6,027.1
           06/09/2008          3:00:00 PM            32,126.4             Monday         32,431.6                     3           6,027.1
           06/09/2008          4:00:00 PM            32,431.6             Monday         32,431.6                     3           6,027.1
           06/09/2008          5:00:00 PM            32,181.0             Monday         32,431.6                     3           6,027.1
           06/09/2008          6:00:00 PM            31,390.1             Monday         32,431.6                     3           6,027.1
           06/09/2008          7:00:00 PM            30,649.2             Monday         32,431.6                     3           6,027.1
           06/09/2008          8:00:00 PM            30,154.7             Monday         32,431.6                     3           6,027.1
           06/09/2008          9:00:00 PM            29,649.3             Monday         32,431.6                     3           6,027.1
           06/09/2008         10:00:00 PM            27,434.8             Monday         32,431.6                     3           6,027.1
06/09/2008 Hours                       14
           06/10/2008          9:00:00 AM                28,308.7         Tuesday         31,805.9                   3             5,401.4
           06/10/2008         10:00:00 AM                29,597.5         Tuesday         31,805.9                   3             5,401.4
           06/10/2008         11:00:00 AM                30,422.3         Tuesday         31,805.9                   3             5,401.4
           06/10/2008         12:00:00 PM                30,779.4         Tuesday         31,805.9                   3             5,401.4
           06/10/2008          1:00:00 PM                31,256.3         Tuesday         31,805.9                   3             5,401.4
           06/10/2008          2:00:00 PM                31,477.8         Tuesday         31,805.9                   3             5,401.4
           06/10/2008          3:00:00 PM                31,717.8         Tuesday         31,805.9                   3             5,401.4
           06/10/2008          4:00:00 PM                31,805.9         Tuesday         31,805.9                   3             5,401.4
           06/10/2008          5:00:00 PM                31,375.3         Tuesday         31,805.9                   3             5,401.4
           06/10/2008          6:00:00 PM                30,241.9         Tuesday         31,805.9                   3             5,401.4
           06/10/2008          7:00:00 PM                29,207.7         Tuesday         31,805.9                   3             5,401.4
           06/10/2008          8:00:00 PM                28,481.0         Tuesday         31,805.9                   3             5,401.4
06/10/2008 Hours                       12
           06/11/2008          3:00:00 PM                27,299.1      Wednesday          27,675.4                   3             1,270.9
           06/11/2008          4:00:00 PM                27,675.4      Wednesday          27,675.4                   3             1,270.9
           06/11/2008          5:00:00 PM                27,414.0      Wednesday          27,675.4                   3             1,270.9
06/11/2008 Hours                        3
           07/07/2008         12:00:00 PM                27,015.5         Monday          28,642.4                   3             2,237.9
           07/07/2008          1:00:00 PM                27,652.4         Monday          28,642.4                   3             2,237.9
           07/07/2008          2:00:00 PM                28,187.7         Monday          28,642.4                   3             2,237.9
           07/07/2008          3:00:00 PM                28,525.0         Monday          28,642.4                   3             2,237.9
           07/07/2008          4:00:00 PM                28,642.4         Monday          28,642.4                   3             2,237.9
           07/07/2008          5:00:00 PM                28,220.0         Monday          28,642.4                   3             2,237.9
           07/07/2008          6:00:00 PM                27,416.0         Monday          28,642.4                   3             2,237.9
07/07/2008 Hours                        7
           07/08/2008         10:00:00 AM                27,461.6         Tuesday         30,217.7                   3             3,813.2
           07/08/2008         11:00:00 AM                28,579.8         Tuesday         30,217.7                   3             3,813.2
           07/08/2008         12:00:00 PM                29,239.1         Tuesday         30,217.7                   3             3,813.2
           07/08/2008          1:00:00 PM                29,703.0         Tuesday         30,217.7                   3             3,813.2
           07/08/2008          2:00:00 PM                29,985.6         Tuesday         30,217.7                   3             3,813.2
           07/08/2008          3:00:00 PM                30,196.7         Tuesday         30,217.7                   3             3,813.2
           07/08/2008          4:00:00 PM                30,217.7         Tuesday         30,217.7                   3             3,813.2
           07/08/2008          5:00:00 PM                29,889.3         Tuesday         30,217.7                   3             3,813.2
           07/08/2008          6:00:00 PM                29,022.5         Tuesday         30,217.7                   3             3,813.2
           07/08/2008          7:00:00 PM                28,150.2         Tuesday         30,217.7                   3             3,813.2
           07/08/2008          8:00:00 PM                27,651.1         Tuesday         30,217.7                   3             3,813.2
           07/08/2008          9:00:00 PM                27,394.3         Tuesday         30,217.7                   3             3,813.2
07/08/2008 Hours                       12
           07/09/2008         11:00:00 AM                27,697.3      Wednesday          28,686.6                   3             2,282.1
           07/09/2008         12:00:00 PM                28,049.3      Wednesday          28,686.6                   3             2,282.1
           07/09/2008          1:00:00 PM                28,329.3      Wednesday          28,686.6                   3             2,282.1
           07/09/2008          2:00:00 PM                28,520.4      Wednesday          28,686.6                   3             2,282.1

Attachment 20 2008 Cluster Analysis Results.XLS by JJB                                                                           07/02/2009
                                                                                        Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                            Case 09-E-0310
                                                                                                          New York Smart Program Proposal
                                                                                                                              Attachment 20
                                                                                                                                 Page 2 of 4

                                                          Results of Cluster Analysis

                 Date            ISO Hour         Hourly Load         Day of Week       Max Load                Cluster           Distance
           07/09/2008          3:00:00 PM            28,637.9          Wednesday         28,686.6                     3           2,282.1
           07/09/2008          4:00:00 PM            28,686.6          Wednesday         28,686.6                     3           2,282.1
           07/09/2008          5:00:00 PM            28,209.0          Wednesday         28,686.6                     3           2,282.1
           07/09/2008          6:00:00 PM            27,370.3          Wednesday         28,686.6                     3           2,282.1
07/09/2008 Hours                        8
           07/15/2008          4:00:00 PM                27,115.1         Tuesday         27,115.1                   3              710.6
           07/15/2008          5:00:00 PM                27,020.0         Tuesday         27,115.1                   3              710.6
07/15/2008 Hours                        2
           07/16/2008          1:00:00 PM                27,501.7      Wednesday          28,818.5                   3             2,414.0
           07/16/2008          2:00:00 PM                28,083.5      Wednesday          28,818.5                   3             2,414.0
           07/16/2008          3:00:00 PM                28,517.5      Wednesday          28,818.5                   3             2,414.0
           07/16/2008          4:00:00 PM                28,818.5      Wednesday          28,818.5                   3             2,414.0
           07/16/2008          5:00:00 PM                28,646.5      Wednesday          28,818.5                   3             2,414.0
           07/16/2008          6:00:00 PM                27,709.3      Wednesday          28,818.5                   3             2,414.0
07/16/2008 Hours                        6
           07/17/2008         11:00:00 AM                27,719.0        Thursday         29,667.9                   3             3,263.4
           07/17/2008         12:00:00 PM                28,312.5        Thursday         29,667.9                   3             3,263.4
           07/17/2008          1:00:00 PM                28,945.9        Thursday         29,667.9                   3             3,263.4
           07/17/2008          2:00:00 PM                29,310.2        Thursday         29,667.9                   3             3,263.4
           07/17/2008          3:00:00 PM                29,547.4        Thursday         29,667.9                   3             3,263.4
           07/17/2008          4:00:00 PM                29,667.9        Thursday         29,667.9                   3             3,263.4
           07/17/2008          5:00:00 PM                29,353.5        Thursday         29,667.9                   3             3,263.4
           07/17/2008          6:00:00 PM                28,323.6        Thursday         29,667.9                   3             3,263.4
           07/17/2008          7:00:00 PM                27,372.9        Thursday         29,667.9                   3             3,263.4
07/17/2008 Hours                        9
           07/18/2008         10:00:00 AM                27,951.2           Friday        31,195.6                   3             4,791.1
           07/18/2008         11:00:00 AM                29,116.5           Friday        31,195.6                   3             4,791.1
           07/18/2008         12:00:00 PM                29,918.0           Friday        31,195.6                   3             4,791.1
           07/18/2008          1:00:00 PM                30,641.2           Friday        31,195.6                   3             4,791.1
           07/18/2008          2:00:00 PM                31,011.7           Friday        31,195.6                   3             4,791.1
           07/18/2008          3:00:00 PM                31,195.6           Friday        31,195.6                   3             4,791.1
           07/18/2008          4:00:00 PM                31,092.5           Friday        31,195.6                   3             4,791.1
           07/18/2008          5:00:00 PM                30,593.7           Friday        31,195.6                   3             4,791.1
           07/18/2008          6:00:00 PM                29,440.3           Friday        31,195.6                   3             4,791.1
           07/18/2008          7:00:00 PM                28,372.8           Friday        31,195.6                   3             4,791.1
           07/18/2008          8:00:00 PM                28,013.9           Friday        31,195.6                   3             4,791.1
           07/18/2008          9:00:00 PM                27,578.1           Friday        31,195.6                   3             4,791.1
07/18/2008 Hours                       12
           07/19/2008         11:00:00 AM                27,214.7         Saturday        28,176.0                   3             1,771.5
           07/19/2008         12:00:00 PM                27,910.3         Saturday        28,176.0                   3             1,771.5
           07/19/2008          1:00:00 PM                28,176.0         Saturday        28,176.0                   3             1,771.5
           07/19/2008          2:00:00 PM                28,095.0         Saturday        28,176.0                   3             1,771.5
           07/19/2008          3:00:00 PM                27,850.9         Saturday        28,176.0                   3             1,771.5
           07/19/2008          4:00:00 PM                27,644.2         Saturday        28,176.0                   3             1,771.5
           07/19/2008          5:00:00 PM                27,368.6         Saturday        28,176.0                   3             1,771.5
07/19/2008 Hours                        7
           07/20/2008          2:00:00 PM                27,051.3          Sunday         27,082.4                   3              677.9
           07/20/2008          3:00:00 PM                27,082.4          Sunday         27,082.4                   3              677.9
           07/20/2008          4:00:00 PM                27,008.3          Sunday         27,082.4                   3              677.9
07/20/2008 Hours                        3
           07/21/2008         10:00:00 AM                27,527.4         Monday          29,905.5                   3             3,501.0
           07/21/2008         11:00:00 AM                28,352.5         Monday          29,905.5                   3             3,501.0
           07/21/2008         12:00:00 PM                28,897.6         Monday          29,905.5                   3             3,501.0
           07/21/2008          1:00:00 PM                29,269.2         Monday          29,905.5                   3             3,501.0
           07/21/2008          2:00:00 PM                29,587.6         Monday          29,905.5                   3             3,501.0
           07/21/2008          3:00:00 PM                29,759.2         Monday          29,905.5                   3             3,501.0
           07/21/2008          4:00:00 PM                29,905.5         Monday          29,905.5                   3             3,501.0

Attachment 20 2008 Cluster Analysis Results.XLS by JJB                                                                           07/02/2009
                                                                                        Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                            Case 09-E-0310
                                                                                                          New York Smart Program Proposal
                                                                                                                              Attachment 20
                                                                                                                                 Page 3 of 4

                                                          Results of Cluster Analysis

                 Date            ISO Hour         Hourly Load         Day of Week       Max Load                Cluster           Distance
           07/21/2008          5:00:00 PM            29,804.7             Monday         29,905.5                     3           3,501.0
           07/21/2008          6:00:00 PM            29,045.4             Monday         29,905.5                     3           3,501.0
           07/21/2008          7:00:00 PM            28,096.9             Monday         29,905.5                     3           3,501.0
           07/21/2008          8:00:00 PM            27,648.2             Monday         29,905.5                     3           3,501.0
           07/21/2008          9:00:00 PM            27,292.5             Monday         29,905.5                     3           3,501.0
07/21/2008 Hours                       12
           07/22/2008         12:00:00 PM                27,406.3         Tuesday         28,338.1                   3             1,933.6
           07/22/2008          1:00:00 PM                27,908.1         Tuesday         28,338.1                   3             1,933.6
           07/22/2008          2:00:00 PM                28,188.7         Tuesday         28,338.1                   3             1,933.6
           07/22/2008          3:00:00 PM                28,338.1         Tuesday         28,338.1                   3             1,933.6
           07/22/2008          4:00:00 PM                28,098.2         Tuesday         28,338.1                   3             1,933.6
           07/22/2008          5:00:00 PM                27,529.1         Tuesday         28,338.1                   3             1,933.6
07/22/2008 Hours                        6
           07/29/2008          1:00:00 PM                27,402.8         Tuesday         28,097.9                   3             1,693.4
           07/29/2008          2:00:00 PM                27,731.3         Tuesday         28,097.9                   3             1,693.4
           07/29/2008          3:00:00 PM                27,953.1         Tuesday         28,097.9                   3             1,693.4
           07/29/2008          4:00:00 PM                28,097.9         Tuesday         28,097.9                   3             1,693.4
           07/29/2008          5:00:00 PM                27,860.0         Tuesday         28,097.9                   3             1,693.4
07/29/2008 Hours                        5
           07/30/2008          1:00:00 PM                27,341.6      Wednesday          27,675.3                   3             1,270.8
           07/30/2008          2:00:00 PM                27,597.2      Wednesday          27,675.3                   3             1,270.8
           07/30/2008          3:00:00 PM                27,622.8      Wednesday          27,675.3                   3             1,270.8
           07/30/2008          4:00:00 PM                27,675.3      Wednesday          27,675.3                   3             1,270.8
           07/30/2008          5:00:00 PM                27,320.8      Wednesday          27,675.3                   3             1,270.8
07/30/2008 Hours                        5
           07/31/2008         10:00:00 AM                27,176.6        Thursday         28,950.5                   3             2,546.0
           07/31/2008         11:00:00 AM                28,070.5        Thursday         28,950.5                   3             2,546.0
           07/31/2008         12:00:00 PM                28,619.0        Thursday         28,950.5                   3             2,546.0
           07/31/2008          1:00:00 PM                28,950.5        Thursday         28,950.5                   3             2,546.0
           07/31/2008          2:00:00 PM                28,892.9        Thursday         28,950.5                   3             2,546.0
           07/31/2008          3:00:00 PM                28,884.9        Thursday         28,950.5                   3             2,546.0
           07/31/2008          4:00:00 PM                28,802.3        Thursday         28,950.5                   3             2,546.0
           07/31/2008          5:00:00 PM                28,682.2        Thursday         28,950.5                   3             2,546.0
           07/31/2008          6:00:00 PM                27,869.5        Thursday         28,950.5                   3             2,546.0
07/31/2008 Hours                        9
           08/01/2008         12:00:00 PM                27,381.1          Friday         28,169.8                   3             1,765.3
           08/01/2008          1:00:00 PM                27,863.3          Friday         28,169.8                   3             1,765.3
           08/01/2008          2:00:00 PM                28,041.7          Friday         28,169.8                   3             1,765.3
           08/01/2008          3:00:00 PM                28,136.5          Friday         28,169.8                   3             1,765.3
           08/01/2008          4:00:00 PM                28,169.8          Friday         28,169.8                   3             1,765.3
           08/01/2008          5:00:00 PM                27,851.0          Friday         28,169.8                   3             1,765.3
08/01/2008 Hours                        6
           08/05/2008          2:00:00 PM                27,111.1         Tuesday         27,421.2                   3             1,016.7
           08/05/2008          3:00:00 PM                27,372.8         Tuesday         27,421.2                   3             1,016.7
           08/05/2008          4:00:00 PM                27,421.2         Tuesday         27,421.2                   3             1,016.7
           08/05/2008          5:00:00 PM                27,045.0         Tuesday         27,421.2                   3             1,016.7
08/05/2008 Hours                        4
           08/06/2008          1:00:00 PM                27,398.9      Wednesday          28,201.1                   3             1,796.6
           08/06/2008          2:00:00 PM                27,800.2      Wednesday          28,201.1                   3             1,796.6
           08/06/2008          3:00:00 PM                28,089.8      Wednesday          28,201.1                   3             1,796.6
           08/06/2008          4:00:00 PM                28,201.1      Wednesday          28,201.1                   3             1,796.6
           08/06/2008          5:00:00 PM                27,829.5      Wednesday          28,201.1                   3             1,796.6
08/06/2008 Hours                        5
           08/18/2008          3:00:00 PM                27,150.4         Monday          27,209.1                   3              804.6
           08/18/2008          4:00:00 PM                27,209.1         Monday          27,209.1                   3              804.6
08/18/2008 Hours                        2
           09/04/2008          1:00:00 PM                27,545.5        Thursday         28,752.8                   3             2,348.3

Attachment 20 2008 Cluster Analysis Results.XLS by JJB                                                                           07/02/2009
                                                                                        Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                            Case 09-E-0310
                                                                                                          New York Smart Program Proposal
                                                                                                                              Attachment 20
                                                                                                                                 Page 4 of 4

                                                          Results of Cluster Analysis

                 Date            ISO Hour         Hourly Load         Day of Week       Max Load                Cluster           Distance
           09/04/2008          2:00:00 PM            28,055.9            Thursday        28,752.8                     3           2,348.3
           09/04/2008          3:00:00 PM            28,475.4            Thursday        28,752.8                     3           2,348.3
           09/04/2008          4:00:00 PM            28,752.8            Thursday        28,752.8                     3           2,348.3
           09/04/2008          5:00:00 PM            28,315.6            Thursday        28,752.8                     3           2,348.3
           09/04/2008          6:00:00 PM            27,247.3            Thursday        28,752.8                     3           2,348.3
           09/04/2008          7:00:00 PM            27,002.8            Thursday        28,752.8                     3           2,348.3
09/04/2008 Hours                        7
           09/05/2008         11:00:00 AM                27,340.8          Friday         28,603.5                   3             2,199.0
           09/05/2008         12:00:00 PM                27,858.0          Friday         28,603.5                   3             2,199.0
           09/05/2008          1:00:00 PM                28,386.4          Friday         28,603.5                   3             2,199.0
           09/05/2008          2:00:00 PM                28,588.6          Friday         28,603.5                   3             2,199.0
           09/05/2008          3:00:00 PM                28,603.5          Friday         28,603.5                   3             2,199.0
           09/05/2008          4:00:00 PM                28,405.7          Friday         28,603.5                   3             2,199.0
           09/05/2008          5:00:00 PM                27,608.2          Friday         28,603.5                   3             2,199.0
09/05/2008 Hours                        7
Grand TTL Hours                       163
Number of Days                         23

Attachment 20 2008 Cluster Analysis Results.XLS by JJB                                                                           07/02/2009
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                                                                                                              Niagara Mohawk Power Corporation d/b/a National Grid
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                                                                                                                                                    Attachment 22
                                                                                                                                                       Page 1 of 1

                              Illustrative Calculation of Proposed Rule 46.2.2 Critical Peak Capacity Charge

                                                                                              Delivery Voltage Level
                                                                         Secondary           Primary        Sub-Trans.       Transmission

     1. Marginal Peak Load Increase (kW)                                             1                1                  1              1

     2. Rule 39.18 Loss Factors                                              1.0751              1.0531          1.0370            1.0111

     3. Forecasted Reserve Margin Factor                                      1.165               1.165           1.165             1.165

     4. Forecasted Summer Clearing Price ($/kW-month)                $          4.00     $         4.00   $        4.00      $       4.00

     5. Adj. Capacity Price (Line 1 * Line 2 * Line 3 * Line 4)      $          5.01     $         4.91   $        4.83      $       4.71

     6. Annualized Capacity Cost (Line 5 * 12)                       $        60.12      $        58.89   $       57.99      $      56.54

     7. Estimated Critcal Peak Event Hours                                      163                 163             163               163

     8. Hourly Critical Peak Capacity Charge/kWh (Line 6 / Line 7)   $      0.36884      $     0.36130    $     0.35575      $    0.34686

Attachment 22 Capacity Charge Calculation.xls—Sheet1 by JJB                                                                                            07/02/2009
Attachment 23
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                                                                                                                                                  Page 1 of 2

                          Illustration of Critical Peak Pricing Program Rule 46 Electricity Supply Service Charges
                                                   for Load Zone C (Syracuse Program Area)

                                                       Load Weighted           Load Weighted          Critical Peak         Load Weighted
                                                       Average Hourly          Average Hourly        Hourly Capacity        Average Hourly
                                        Hours in        Energy Costs            Energy Costs             Charge             Costs Adjusted
                                         Period          per MWh                  per kWh               per kWh                per kWh

   1. Critical Peak                           163                $123.40   $           0.12340   $            0.36884   $            0.49224

   2. On-Peak                                 492                 $94.75   $           0.09475                          $            0.09475

   3. Shoulder-Peak                           862                 $74.10   $           0.07410                          $            0.07410

   4. Off-Peak                              7,267                 $65.55   $           0.06555                          $            0.06555

Attachment 23 Load Weighted Commodity with Capacity.xls—Load Zone C by JJB                                                                        07/02/2009
                                                                                                         Niagara Mohawk Power Corporation d/b/a National Grid
                                                                                                                                             Case 09-E-0310
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                                                                                                                                               Attachment 23
                                                                                                                                                  Page 2 of 2

                          Illustration of Critical Peak Pricing Program Rule 46 Electricity Supply Service Charges
                                                for Load Zone F (Capital District Program Area)

                                                       Load Weighted           Load Weighted          Critical Peak         Load Weighted
                                                       Average Hourly          Average Hourly        Hourly Capacity        Average Hourly
                                        Hours in        Energy Costs            Energy Costs             Charge             Costs Adjusted
                                         Period          per MWh                  per kWh               per kWh                per kWh

   1. Critical Peak                           163                $143.79   $           0.14379   $            0.36884   $            0.51263

   2. On-Peak                                 492                $108.84   $           0.10884                          $            0.10884

   3. Shoulder-Peak                           862                 $93.60   $           0.09360                          $            0.09360

   4. Off-Peak                              7,267                 $81.56   $           0.08156                          $            0.08156

Attachment 23 Load Weighted Commodity with Capacity.xls—Load Zone F by JJB                                                                        07/02/2009

Description: National Power Corporation Marketing Plan document sample