Niagara Mohawk Power Corporation d/b/a National Grid

Program Performance and Cost Effectiveness of

Dynamic Load Management Programs

Case 15-E-0189

November 15, 2018

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Table of Contents

Introduction ....................................................................................................................................... 1

Commercial Demand Response Programs– DLRP/CSRP ...................................................................... 3

Program Enrollment.....................................................................................................................3

Program Costs and Savings ..........................................................................................................4

Cost Recovery ...............................................................................................................................5

Benefit-Cost Analysis for Commercial Programs ............................................................................6

Program Operations .....................................................................................................................8

DLRP/CSRP Event Performance and System Impacts ....................................................................10

Program Marketing ....................................................................................................................12

2019 DLRP/CSRP Program Changes ...........................................................................................13

Website Development for DRLP and CSRP ...................................................................................16

DLRP/CSRP Conclusions ............................................................................................................16

Direct Load Control (“DLC”) Program – coolControl

Introduction ..................................................................................................................................16

Technology Overview and DR Events .............................................................................................18

Incentives .....................................................................................................................................19

Program Costs and Savings ...........................................................................................................20

Marketing and Recruitment............................................................................................................20

Website Development ...................................................................................................................22

Direct Load Control (“DLC”) Program – ConnectedSolutions

Introduction and Program Operations ............................................................................................22

Technology Overview and DR Events .............................................................................................25

Incentives .....................................................................................................................................26

Program Costs and Savings ...........................................................................................................26

Benefit Cost Analysis for DLC Programs ........................................................................................27

Marketing and Recruitment ............................................................................................................29

Website Development .....................................................................................................................30

2019 DLC Program Changes..........................................................................................................31

DLM Program Conclusion ...................................................................................................................................................... 32

1

INTRODUCTION

Niagara Mohawk Power Corporation d/b/a National Grid (“National Grid” or the “Company”) submits

this 2018 end-of-year annual filing in compliance with the New York State Public Service Commission’s

(“Commission”) April 23, 2018 Order Adopting Program Changes with Modification and Making Other

Findings (“April 2018 Order”).1 The April 2018 Order requires the Company to submit a report to the

Commission each year on November 15, 2018.2 This annual filing assesses National Grid’s 2018

Dynamic Load Management (“DLM”) programs as approved by the Commission.3

National Grid’s DLM programs consist of: the Distribution Load Relief Program (“DLRP”) as described

in Rule 61 of the Company’s PSC No. 220 Electricity – Schedule for Electric Service (“Tariff”); the

Commercial System Relief Program (“CSRP”) as described in Rule 62 of the Tariff; and the Direct Load

Control (“DLC”) Program, as described in Rule 63 of the Tariff. This annual filing reviews the 2018

capability period results from all three DLM Programs, discusses all proposed changes to the

implementation of these programs in 2019, and highlights the cost recovery mechanism, which is

described in Rule 64 of the DLM Tariff, for National Grid’s DLM programs in 2019.

While customers in most rate classes are eligible for all three DLM programs, National Grid considers the

DLRP and CSRP to be commercial and industrial (“C&I”) customer-focused programs, while the DLC

program targets residential and small-business customers. The CSRP and the system-wide Bring Your

Own Device (“BYOD”) DLC program (also known as the ConnectedSolutions program) are currently

offered system-wide. The DLRP and the DLC program (also known as the coolControl program) have

been focused in the Village of Kenmore for the 2018 season. While National Grid does not intend to

expand the DLRP or CSRP for the 2019 season, evaluative efforts are underway to reduce electrical

system load in identified areas of need through the Company’s non-wires alternatives (“NWA”)

solicitations and in identified constrained areas through targeted DR offerings. These areas are not

currently incorporated into this DLM funding mechanism but are anticipated to be incorporated in future

years either through DLRP program mechanisms or through enhanced funding sources for NWA

opportunities. Preliminary information and next steps regarding these DR solutions are discussed

subsequently in this filing.

1 Cases 14-E-0423 et al., Proceeding on Motion of the Commission to Develop Dynamic Load Management

Programs (“DLM Programs Proceeding”), Order Adopting Program Changes with Modification and Making Other

Findings (issued April 23, 2018)(“April 2018 Order”). 2 Id., Ordering Clause No. 2, pp. 24-25.

3 See DLM Programs Proceeding, April 2018 Order.

2

A summary of National Grid’s DLM Programs is highlighted below and illustrates the pricing incentives

applicable to National Grid’s current DLM programs:

Table 1: National Grid’s 2018 DLM Programs

Program Name Program Type Program Event Triggers and Duration Incentives

Distribution

Load Relief

Program

(“DLRP”)

Contingency Contingency program activated for system critical

situations (i.e., unforeseen distribution system

emergencies wherein stressed electrical equipment may

exceed established limits).

Events are called with short/no advance notice

("Immediate") or at least two (2) hours advance notice

("Test" or "Contingency"). Test events last one (1) hour

whereas Contingency or Immediate events may last four

(4) or more hours.

Includes Reservation and Voluntary participants.

Focused in designated or identified constrained areas of

the service territory with participation available to

customers served at primary and secondary voltages

only.

Reservation Payment Option:

Reservation Payment =

$4.69/kW Month;

Performance Payment =

$1.02/kWh;

Voluntary Performance Option:

Performance Payment =

$1.20/kWh

Commercial System

Relief Program

(“CSRP”)

Peak Shaving Activated for peak shaving needs.

For "Planned Events" the Company provides > 21 hours’

advance notice and the Planned Event may last four (4)

hours or more.

For "Unplanned Events" the Company will provide

< 21 hours’ advance notice.

Includes Reservation and Voluntary options for

participants.

System-wide program available to customers served

from all voltages.

Reservation Payment Option:

Reservation Payment (up to four

(4) events) = $2.75/kW Month;

Reservation Payment (over four

(4) events) = $3.00/kW Month;

Performance Payment - Planned

Event = $0.18/kWh;

Performance Payment

Unplanned Event =

$0.22/kWh.

Voluntary Performance Option:

Payment Option:

Performance Payment Planned

Event = $0.16/kWh;

Performance Payment

Unplanned Event =

$0.19/kWh

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Direct Load

Control

(“DLC”)

program

Contingency and

Peak Shaving

Activated for system critical situations or for peak

shaving. National Grid has the ability to remotely adjust

thermostat settings.

Customers in designated areas may receive a free DR-

ready/remote controllable thermostat (Company

Provided Thermostat (“CPT”)) during the 2018 season.

The plug-load controlled devices have been discontinued

for the 2018 season.

Bring Your Own Device (“ BYOD”) program connects

existing Wi-Fi thermostats to National Grid’s Demand

Management Platform (EnergyHub).

One-time sign-up payment of

$30 and a $20 yearly incentive

- payable the second year of

participation - for reducing

load during 80% of called

events and event-hours.

Commercial Demand Response Programs—DLRP and CSRP

National Grid offers two commercial DR programs in New York: the DLRP and the CSRP. The DLRP

is a contingency program wherein individual participants are required to curtail 50 kW when

participating directly in this program with the Company. Aggregators are required to deliver at least 50

kW of load relief in aggregate in order to participate in the DLRP or CSRP An event under the DLRP

is to be called when identified or stressed electrical equipment exceeds certain limits or during any

system emergency. In contrast, the CSRP is activated for peak-shaving needs when National Grid’s

electrical system exceeds 92% of the system-wide 95/5 peak forecast, as defined in the Tariff.

Dispatch of CSRP events is handled by the Transmission Control Center (“TCC”) when this peak

threshold has been overcome.

2018 CSRP and DLRP Participation

While the Village of Kenmore has a very small pool of eligible, interval-metered commercial

customers capable of curtailing 50 kW or more, there are no participants currently enrolled in the

DLRP. In contrast, there were 306 resources that participated in the CSRP during the 2018 capability

period, totaling 287.47 MW of contracted curtailment and 248.48 MW of performed curtailment.

Contracted curtailment in 2018 was 99.9 MW greater than that of 2017. In the 2018 program year there

were five (5) aggregators (one more than the 2017 DR capability period) and three (3) individual

participants (two more than the 2017 DR capability period) who participated in the CSRP. Additional

information about the 2018 CSRP performance is presented below in the Program Operations section of

this report.

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2018 DLRP and CSRP Costs and Savings

There were no customers in the DLRP in 2018. Total costs for the DLRP, which include internal

administrative (labor) costs and vendor costs associated with operating the program in 2018, are

shown in Table 2 below. Total DLRP costs were $66,335.02.

Table 2: 2018 DLRP Costs

DLRP Components

DLRP

Component

Costs

DLM

Surcharge

(recoverable)

DLM Surcharge

(non-recoverable)

Program Operations

(internal) $ 7,691.22 $ - $ 7,691.22

Vendor Costs $ 58,643.80 $ 58,643.80

Total $ 66,335.02 $ - $ 66,335.02

Total costs associated with the CSRP are $4,905,866.29 and are shown in Table 3 below. CSRP costs are

separated by incentive payments (including both reservation and performance payments), internal

administrative (labor) costs, and vendor costs. Base costs associated with the original set-up of AutoGrid

Systems, Inc. (“AutoGrid”), a commercial Demand Response Management System (“DRMS”) vendor,

were introduced in National Grid’s 2017 DLM Annual Report and were paid in full upfront for three (3)

years. These initial fees have not been included in Table 2 below as part of the total costs for CSRP;

however, additional operating costs from participating vendors for the CSRP are included in Table 3

below.

Table 3: 2018 CSRP Costs

CSRP Components CRSP

Component Costs

DLM

Surcharge Recoverable

DLM Surcharge

Non-Recoverable

Incentive Payments $ 4,617,021.11 $ 4,617,021.11

Program

Operations

(internal)

$ 230,201.38 $ 230,201.38

Vendor Costs $ 58,643.80 $ 58,643.80

Total $ 4,905,866.29 $4,617,021.11 $ 288,845.18

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In designing the incentive rates for the 2018 DLM program, National Grid wanted to ensure that CSRP

customers were being incentivized based only on their avoided transmission and distribution (“T&D”)

value, with no generation capacity cost reduction value included. The MCOS study is currently used to

set incentives for high-voltage customers (and for distribution-level customers), which are still well

below the avoided marginal cost of transmission that these customers provide. National Grid believes

that CSRP incentives are appropriate for both high-voltage and distribution-level customers, based upon

future program enrollment and costs. As such, this methodology has not been altered from that in the

Company’s 2017 DLM programs. The Company is not proposing to change the CSRP pricing incentives

for the 2019 program year from the current 2018 program year values.

Cost Recovery

Per the Commission’s order on cost recovery issued April 19, 2018,4 the Company revised the

allocation of costs recovered for each DLM Program for the 2018 DR capability period. Prior to

2018, all DLM Program costs were recovered through the Company’s DLM surcharge from all

customer classes using a transmission allocator. However, since May 1, 2018, National Grid

recovers the costs of the DLRP and the DLC Program from all customers served at secondary or

primary voltage delivery levels only and uses a non-coincident peak allocator to apportion costs

among the service classes whereas the CSRP costs are still recovered from all customers using a

transmission allocator to apportion costs among the service classes.

DLRP and CSRP Benefits

There are several benefits for both the customer and utility from the implementation of commercial

DR programs. Highlighted below are some of these benefits:

Customer Benefits:

Monetary compensation that potentially has the ability to lower electric bills

Non-traditional revenue streams from incentives and related rebates

Demand charge reduction on customer bills

Potential ratchet avoidance (demand)

Reduced stress on customer’s electrical equipment

4 DLM Programs Proceeding, Order Directing Tariff Filings (issued April 19, 2018).

6

Utility Benefits:

Deferred capital project costs that are due to:

Reduced overall electric system stress

Direct project savings in designated or constrained areas

Enhanced communications and interactions with customers, which include:

Positive touch points and interactions with customers

Enhancements of the Company’s “trusted advisor” role

Reduced commodity costs

Reduction in electrical system stress

Community/Societal Benefits:

Lower greenhouse gas (“GHG”) emissions due to reduced need for peaking power plants,

which have been historically higher polluters

Potential increase in electrical reliability, particularly in designated or constrained areas

Deferral of disruptive utility construction projects

Benefit-Cost Analysis for DLRP and CSRP

This section provides the results of the completed benefit-cost analysis (“BCA”)5 for the DLRP and

CSRP using the Societal Cost Test (“SCT”), Utility Cost Test (“UCT”), and Ratepayer Impact Measure

(“RIM”). At the request of the New York State Department of Public Service Staff (“Staff”), National

Grid has created a model to determine the cost effectiveness for the DLRP and CSRP that includes

avoided generation capacity costs and a model that excludes any avoided generation capacity costs for

commercial customers. Both models analyze the cost effectiveness of the DLRP and CSRP individually,

and the Company’s commercial DLM programs collectively, considering the cost effectiveness of DLRP

and CSRP as a combined C&I program portfolio. There are program-specific cost and benefit inputs that

are incorporated into the analysis to calculate the BCA.

The BCA for the DLRP and CSRP is performed for each of the three tests (SCT, UCT, and RIM) and the

resulting costs, benefits, and net benefits are provided below in Tables 4-6. The BCA was performed

using the 2018 program year pricing incentives in each of the three tests.

The SCT is used to measure and value the net costs and benefits to society, as based on current DR

programs. This test analyzes New York State’s BCA in entirety and compares the costs that have been

5 Utilizing BCA Handbook, v2.

7

incurred for the implementation of the program to customer costs with avoided electricity and other

supply-side resource costs. The SCT also includes the cost of externalities to provide a framework for

whether a program should be continued to be implemented. The SCT for the commercial portfolio (i.e.,

the combined DLRP and CSRP), excluding avoided generation capacity costs, yields a result of 1.93 and

$5,683,365 in net benefits over a ten-year period. Table 4 below applies the SCT test to the DLRP and

CSRP and as a commercial program portfolio.

Table 4: Cost-effectiveness Tests for 2018 DLRP and CSRP Using the SCT (excluding avoided generation capacity costs):

National Grid Demand Response Cost-effectiveness SCT Results

DLRP CSRP Total C&I

Benefits $ - $ 11,826,037.18 $ 11,826,037.18

Costs $ 627,781.30 $ 5,514,891.09 $ 6,142,672.39

Net

Benefits $ (627,781.30) $ 6,311,146.09 $ 5,683,364.79

SCT 0.00 2.14 1.93

The UCT determines the costs and benefits from the perspective of National Grid. This test is integral in

identifying impacts on utility revenue requirements and provides information on the effectiveness of

program delivery in 2018. The UCT is determined by the costs that have been incurred to implement the

commercial DLM programs as compared to the avoided electricity supply-side costs. The UCT,

excluding avoided generation capacity costs, for the commercial DLM portfolio yields a result of 1.71

and $4,890,762 net benefits over a ten -year period. Table 5 below displays the UCT for the DLRP and

CSRP and as a commercial program portfolio.

Table 5: Cost-effectiveness Tests for 2018 DLRP and CSRP Using the UCT (excluding avoided generation capacity costs):

National Grid Demand Response Cost-effectiveness UTC Results

DLRP CSRP Total C&I

Benefits $ - $ 11,826,037.18 $ 11,826,037.18

Costs $ 708,785.41 $ 6,226,490.11 $ 6,935,275.52

Net

Benefits $ (708,785.41) $ 5,599,547.07 $ 4,890,761.66

UTC 0.00 1.90 1.71

The RIM is from the viewpoint of National Grid’s customers in aggregate. This test determines what

happens to average prices for customers due to changes in utility revenue and operating costs. The test

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determines whether funding requirements need to be increased for the utility program. The RIM for the

commercial DLM portfolio, excluding avoided generation capacity costs, yields a result of 1.16 and

$813,808 in net benefits over a ten-year period. Table 6 below displays the RIM for the DLRP and CSRP

and as a commercial program portfolio.

Table 6: Cost-effectiveness Tests for 2018 DLRP and CSRP Using the RIM (excluding avoided generation capacity costs):

National Grid Demand Response Cost-effectiveness RIM Results

DLRP CSRP Total C&I

Benefits $ - $ 11,826,037.18 $ 11,826,037.18

Costs $ 891,045.20 $ 7,827,587.47 $ 8,718,632.67

Net

Benefits $ (891,045.20) $ 3,998,449.71 $ 3,107,404.51

RIM 0.00 1.51 1.36

According to the BCA Handbook, a benefit-cost ratio (“BCR”) above 1.0 indicates that a program is cost

effective. The BCR for each of the tests for National Grid’s commercial DLM portfolio is above 1.0. In

order to maintain the cost-effectiveness of the DLM portfolio, the Company will continue to effectively

manage program spending and will endeavor to increase participation and enrollment in these commercial

programs.

2018 CSRP Operations

National Grid has enrolled 306 customers through five (5) aggregators for CSRP in 2018. The total

amount of enrolled capacity from these 306 customers was 287.47 MW.

Program operating costs for 2018 were included in Table 3 in the 2018 CSRP Program Costs section

above, and were composed of implementation activities including, but not limited to:

Tariff leaves preparation

Incentive setting

Internal departmental outreach and coordination

Program implementation

Incentive calculation and processing

Sales team presentations

Customer acquisition

Measurement and Verification (“M&V”) preparation and calculation of results

9

Aggregator communications

Valuation and analyzing constrained areas

Coordination work with other utilizes, and

Document and report preparations

Implementation activities are not recovered through the DLM surcharge, as identified in program costs

listed above.

As discussed, AutoGrid was under contract as the DRMS vendor for National Grid for the 2018 DR

capability period and will continue to work with the Company for one (1) more year (i.e., through

2019). National Grid’s TCC dispatched CSRP events through the AutoGrid DRMS portal in 2018

on a twenty-one (21) hour day-ahead notification. To ensure proper dispatch of all resources,

National Grid created notification tests and employed communications testing for all customers who

were enrolled through aggregators or as direct participants. AutoGrid worked with National Grid’s

Meter Data Services team to obtain data after each CSRP event and proceeded to develop both

event-specific and monthly settlement reports for National Grid for accurate calculation of payments

to participating CSRP customers. The 2018 DR capability period was the first summer for which

this more automated process took effect and there were some initial challenges with providing data

and calling events efficiently. National Grid anticipates streamlining efforts for the 2019 season

with greater coordination efforts between the Meter Data Services team and AutoGrid to ensure a

more seamless process for calling CSRP events.

Activities in 2018 for implementation of the CSRP included:

Checking all accounts in National Grid’s customer system for accuracy of:

Customer account information

New York Independent System Operator (“NYISO”) zones

Customer service/mailing addresses

Supply station/feeder/voltage-level data

Peak load information

Aggregator and customer management:

Cooperative discussions about process improvements with AutoGrid

Creation of bulk enrollment comma-separated values (“CSV”) files

10

Identification of website improvements required for internal teams

Discussion and guidance on event M&V results

Program Management:

Aggregator administrative support

Event notification process improvements

Day-ahead forecast accuracy checks

Accounting set up – CSRP payments with customers

Customer Base Load (“CBL”) calculations for M&V review

kW reduction calculation

Customer payment calculation

Performance factor maintenance

NYISO customer coordination with CSRP

DRMS Configuration:

Customer enrollment and set up in DRMS

Settlement calculations for customers (completed through AutoGrid, with manual M&V

calculations for review)

Accurate reporting of DR event calculations by working with internal TCC and AutoGrid

Effective internal IT integration for AutoGrid

Event notification tests for customers to ensure accurate event dispatch

2018 CSRP Event Performance and System Impacts

National Grid’s service territory experienced high temperatures during the 2018 DR capability period.

The majority of CSRP events were held from 3:00-7:00 p.m. during the 2018 DR capability period; the

last three CSRP events were held from 2:00-6:00 p.m. CSRP participants contracted with National Grid

through five (5) aggregators and three (3) individual participants for a total of 287.47 MW of load relief.

Three (3) individual participants enrolled in the CSRP contributed 38.024 MW of load relief. Table 7

below provides the enrolled curtailment for each of the individual participants and the five aggregators

for 2018.

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Table 7: CSRP Enrolled Demand (kW and MW) for 2018

Aggregator/Individual

Participant

Enrolled Curtailment

(kW)

Enrolled Curtailment

(MW)

Aggregator 1 138,264.00 138.26

Aggregator 2 31,144.00 31.14

Aggregator 3 45,760.00 45.76

Aggregator 4 29,875.00 29.88

Aggregator 5 4,400.00 4.40

Individual Participant 1 7,124.00 7.12

Individual Participant 2 2,000.00 2.00

Individual Participant 3 28,900.00 28.90

Total 287,467.00 287.47

Demand curtailment benefits National Grid’s electrical system. In addition, the majority of the load

shedding was concentrated in NYISO Load Zone A, National Grid’s Western Division. Refer to Table 9

below for load shedding associated with each load zone. National Grid’s customer-facing energy

efficiency teams worked toward increasing participation in other National Grid zones this year.

System impacts for the test event date and the total energy saved per event are shown in Table 8 below.

Table 8: 2018 CSRP Event Results

Event Date Actual Event Curtailment (MW)

Total Energy Saved (MWh)

7/2/2018 290.66 1,162,625

7/3/2018 275.74 1,102,976

7/5/2018 254.21 1,016,851

7/16/20186 220.00 880,008

8/6/2018 246.73 986,904

8/28/2018 225.19 900,766

8/29/2018 252.94 1,011,776

9/5/2018 222.37 889,493

6 A technical complication while calling the DR event through AutoGrid resulted in some resources not being called

on this date. This issue was immediately identified and resolved.

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Table 9: 2018 Contracted CSRP Load by NYISO Zone

NYISO Zone CSRP

Customers Load (MW)

A 119 185.13

B 1 1.00

C 45 11.66

E 43 15.72

F 96 74.76

Performance factors are calculated for each month of the DR capability period and displayed below for

each of the five (5) aggregators and the three (3) individual participants. Performance factors for the

months of May and June were carried over from 2017 for the four (4) aggregators and one (1) individual

participant who were enrolled in CSRP:

Table 10: 2018 Performance Factors by Month

May June July August September

Aggregator 1 0.96 0.96 1.00 0.87 0.96

Aggregator 2 1.00 1.00 0.38 0.25 0.30

Aggregator 3 0.63 0.63 0.29 0.45 0.05

Aggregator 4 1.00 1.00 1.00 0.91 0.51

Aggregator 5 0.50 0.50 0.50 0.53 0.46

Individual Participant 1 1.00 1.00 1.00 0.94 1.00

Individual Participant 2 0.50 0.50 0.86 1.00 1.00

Individual Participant 3 0.50 0.50 0.68 1.00 1.00

2018 DLRP and CSRP Sales and Marketing

While National Grid performed outreach for the DLRP in 2018 through account managers responsible for

the Kenmore area, the CSRP outreach was conducted by aggregators. National Grid directly marketed

the 2018 CSRP to the aggregator pool via phone calls, emails, and in-person meetings.

National Grid’s Market Development team, jurisdiction managers, and sales representatives served as the

main point of contact for engaging customers to participate in the Company’s commercial DLM

programs; these internal stakeholders maintain trusted relationships between the Company’s largest

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customers and internal customer-facing groups. These National Grid teams are in constant contact with

customers regarding issues that include but not limited to energy efficiency measures, billing matters,

energy-related projects, and distributed energy resources (“DER”). The Company developed a DR

information package for the jurisdiction managers and sales representatives to talk from and leave behind

this year. These materials will be upgraded for 2019 with any pertinent changes.

2019 DLRP and CSRP Changes

In the April 2018 Order, National Grid was asked to comment on several topics related to the DLRP and

CSRP. These topics and any DLRP and CSRP changes for the 2019 capability period are discussed

below:

1. Re-evaluation of DLRP. The April 2018 Order instructs National Grid to re-evaluate the need

and intended use of the DLRP. The DLRP was originally intended for use with distribution-

level customers, which mainly include identified NWA areas that are either load-constrained

and/or have reliability below NWA planning criteria in order to defer capital infrastructure

investment. While the Commission had asked National Grid to expand the DLRP system-wide

in its July 18, 2015 Order Adopting Dynamic Load Management Filings with Modifications,7

National Grid sought to focus the program in identified NWA opportunity areas. After having

internal conversations and discussions with Staff, the Company did not make any changes to the

DLRP in 2016 or 2017. DLRP pricing incentives have been set to $0.00 within the Kenmore

area for the 2019 DR capability period.8

Throughout 2018, National Grid evaluated the use of the DLRP to determine how the program

offering can be used more broadly. In particular, the enhanced MCOS study (referred to therein

as the Marginal Avoided Distribution Capacity (“MADC”) study) which the Company filed with

the Commission concurrently with its Distributed System Implementation Plan (“DSIP”) Update

on July 31, 2018 (“MADC Study”),9 provides insight into appropriate locational value in areas of

the distribution system. The MADC study determines locational marginal costs through a

forward-looking, system-wide analysis to determine: (1) where DERs may be able to provide

locational support to the electric distribution system through targeted relief in areas where load

7 DLM Programs Proceeding, Order Adopting Dynamic Load Management Filings with Modifications (issued June

18, 2015). 8 This is reflected in National Grid’s draft tariff leaves and supporting draft pricing statements filed

contemporaneously. 9 Cases 15-E-0751 et al., In the Matter of the Value of Distributed Energy Resources (“VDER Proceeding”),

Enhanced Marginal Cost of Service Study of Niagara Mohawk Power Corporation d/b/a National Grid to

Determine Locational Value of Distributed Energy Resources (filed July 31, 2018) (“MADC Study”).

14

growth has the potential to create electrical stress on the system; and (2) assigns a value to that

relief by comparing it to the traditional investment needed to alleviate such forecasted stress.

There are 68 unique areas identified by the filed MADC Study where an appropriate quantity of

DER could defer the need for a traditional utility investment during the ten-year duration of the

study. These 68 areas that were studied are listed in Appendix C of the filed MADC Study.

However, the values generated by the MADC Study have not yet received Staff or Commission

approval for use in the VDER Value Stack for compensating DER for their distribution value.

The Company is considering an update to the MADC Study at regular intervals as part of its

evolving integrated planning process. Going forward, forecasts will improve to incorporate more

types of DER. The MADC can be a tool which National Grid uses to evaluate future system

needs as specified by violations against planning criteria, which can inform system planning.

Any identified grid violations will be assessed for a traditional wires-based solution (i.e., capital

project) or if the need is suitable for a NWA solution, in alignment with the NWA suitability

criteria. For projects added to the NWA list, National Grid’s DR team will work alongside the

Company’s NWA team to determine if targeted DR can support the NWA solution. In cases

where DR is part or all of an NWA solution, DR will be funded through the NWA deferral

mechanism.

In addition, the Company believes there may be scenarios outside of those specified by the

MADC Study where targeted DR can play a role. For example, using targeted DR may alleviate

a short-term thermal overload identified during summer preparation that would otherwise be

typically monitored but not solved. Second, targeted DR may also enhance near-term reliability

in the event of a feeder fault by enabling greater levels of load transfer to an adjacent un-faulted

feeder through a reduction of the load on that un-faulted feeder.

Additionally, National Grid is currently evaluating new and/or alternative methods to increase

customer participation in targeted DR via greater incentives, increased marketing efforts, and

evolving behind-the-meter (“BTM”) technologies, such as ESS and Advanced Metering

Infrastructure (“AMI”).10

For the reasons described above, National Grid believes there is value to keeping the DLRP as a

part of the overall DLM Program portfolio. However, outside of identified constrained areas, the

10

National Grid’s AMI Implementation Plan required approval by the Commission.

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Company does not believe that the DLRP provides additional system value not already provided

by the CSRP. As such, National Grid does not intend to expand the DLRP system-wide, but to

keep it a targeted program that is a valuable tool in the system planner’s toolbox.

2. Minimum threshold for performance factor for CSRP to be changed to 0.25. As the performance

factors shown above illustrate, this threshold would have been a factor for the summer of 2018.

National Grid proposes to change the minimum threshold for its performance factor (“PF”) for

the CSRP to 0.25 in order for customers to receive eligible reservation payments. Currently,

National Grid does not employ a certain threshold for the PF for the CSRP or DLRP. This

modification will allow for more committed participation in CSRP and will mitigate “bad

actors,” as Orange and Rockland Utilities, Inc. has employed in its DLRP and CSRP

programs.11

National Grid believes this change will result in more conservative customer

curtailment commitments, providing more reliability in customer participation and more

certainty for system operators who use these curtailment totals to plan system operation.

3. Customer Base Load (“CBL”) Flexibility. National Grid was asked to comment on the

application of CBL flexibility for the DLRP and CSRP in the April 2018 Order. Currently,

National Grid’s CBL operating procedures are described on the Company website in further

detail for all customers and aggregators.12

During initial enrollment, customers and aggregators

that are enrolled in the CSRP are given the choice to opt for either the Average-Day CBL or the

Weather-Adjusted CBL, which are both defined in the Tariff and described in the Customer

Baseline Load Procedure on National Grid’s website. Either method of calculating CBL is used

to determine the load relief provided by a customer or aggregator during a DR event by

comparing the customer’s load during an event to the customers’ baseline load during similar

non-event days. While these two scenarios cover many of the potential enrolled customer

curtailment methods, the Company recognizes that there may be future opportunities with the

use of DERs to alter the CBL methodology for participation in DR. Alternate CBL methods

may particularly be applicable if and when there are Energy Storage Systems (“ESS”) to be

incorporated for eligible customers who participate in DLM programs. Customers who intend

to use alternate forms of CBL methodology shall notify National Grid by December 1 of each

year and the Company will review the process and methodology by January 1 of the subsequent

year. The Company will advise aggregators and Staff of any potential additional baseline

11

DLM Programs Proceeding, April 2018 Order, p. 7. 12

Available at https://www.nationalgridus.com/media/pdfs/bus -ways-tosave/customer_baseline_load_procedure.pdf

16

options to be added to the methodology, and if the Company does propose any changed to the

CBL methodology, the Company will hold a meeting with involved parties to obtain feedback

about those additional baselines at least one month before they are to go into effect.

Website Development for DRLP and CSRP

National Grid made enhancements to the DRLP and CSRP content on the National Grid website in

advance of the 2018 DR capability period to ensure accuracy and clarity of program descriptions. The

main page for commercial customers to access DR information is available at:

https://www.nationalgridus.com/Upstate-NY-Business/Energy-Saving-Programs/Demand-Response-

Programs.

DLRP and CSRP Conclusion

National Grid has re-evaluated the use of the DLRP in 2018 and will continue to assess these findings in

2019. Future implementation of the DLRP and CSRP will include increased automation of processes

through integration with AutoGrid, the addition of vendors that promote and manage administrative

aspects of the program as additional constrained areas are investigated, and increased targeted DR

offerings through coordination with the Company’s NWA and Distribution Planning and Asset

Management (“DPAM”) teams. Innovation in cost-effective DLM technology presents exciting

opportunities for the Company to collaborate with vendors, aggregators, and end-use DR customers to

address future electric system needs. Some of these solutions may involve ESS, fuel cells, backup

generation, solar photovoltaic systems, cogeneration, and other technologies as appropriate.

2018 CSRP results exceeded the Company’s expectations and CSRP results achieved this year provided a

benefit to National Grid’s electrical system and system control operators and asset management teams,

while demonstrating that DR is a valuable tool in the system planner’s toolbox.

Direct Load Control (“DLC”) Program coolControl Program

Introduction

The coolControl program targets residential and small commercial customers located in the Village

of Kenmore area of electrical stress. This program is currently implemented and administered by

ThinkEco, Inc. The coolControl program is intended to curtail electricity demand from

approximately 19,000 residential and small-business customers in the North Buffalo, Kenmore, and

17

Tonawanda suburbs. Customers are currently offered the Emerson Sensi™ Wi-Fi thermostat as a

direct-install measure and are also incentivized to participate in the coolControl program. In the

previous two years, National Grid had also offered the ThinkEco modlet controller that controlled

both smartAC kits and dehumidifiers. These two measures were also provided to customers as a

direct-install measure but were discontinued in 2018 in an effort to improve the coolControl

Program’s overall cost-effectiveness. Customers who already have a ThinkEco modlet controller

were permitted to continue to participate in the 2018 coolControl Program but no additional

marketing was undertaken in the region for this measure.

In 2018, enrollment increased to 442 Emerson Sensi™ Wi-Fi thermostats from 355 such

thermostats in 2017, resulting in 58 new thermostats enrolled during the 2018 capability period.

There were no new installed smartAC kits in 2018. Table 11 below provides a coolControl

program summary which shows the basic requirements for customer participation:

Table 11: 2018 coolControl Program Summary

Emerson Sensi™

2018 DR Capability Period May 1 to Sept 30

Potential Event Days Weekdays

Potential Event Times 10 am to 8 pm

Maximum events in season 4

Maximum events in 1 week N/A

Maximum events in 1 day 1

Event duration 4 hours

Pre-cooling temp

adjustment

N/A

DR event temp adjustment 5°F

Incentive $30 sign-up and $20 for each year of participation, starting 2

nd year

of participation

Participation Requirement 80% of events or event-hours

Below is a territory map for the coolControl program which is an area of electrical stress located on

the outskirts of the City of Buffalo.

18

Figure 1: coolControl Territory Map

In addition, the map below shows the penetration rate for both Emerson Sensi™ Wi-Fi thermostats

(in blue), as well as the ThinkEco SmartAC kits (in orange) which were installed in 2016 and 2017,

as discussed above. Kenmore was initially chosen for the coolControl Program due to the need for

load reduction in this area of National Grid’s distribution grid.

Figure 2: coolControl Program Penetration

Program penetration (blue = Emerson Sensi™ thermostat, orange = ThinkEco smartAC kit)

coolControl Technology Overview and DR Events

Electric power reductions from Emerson Sensi™ Wi-Fi thermostats averaged 0.35 kW value in

2018. This reduction is half of what it was in 2016 and 2017, likely due to the increase in the

19

number of event-hours and technological challenges with the Emerson Sensi™ thermostat this

summer. In 2018, there were six (6) DR events held on the following dates: July 2, July 3, August

6, August 28, August 29, and September 5. These events had an average duration of four (4)

hours each whereas in the 2017 DR capability period the events lasted two (2) hours.

There were challenges this year in collecting event data for the two (2) events held in July for

Sensi thermostats. As such, Table12 below only reports findings for the August and September

events for the Emerson Sensi™ thermostats. This lack of data was due to the incomplete data

transmission from the Emerson Sensi™ thermostat onto the Whisker Labs Platform, and although

there was an effort to resolve this issue, no data has been able to be recovered for the two DR

events that were held in July. The temperature offset for the Emerson Sensi™ thermostats was 5

degrees Fahrenheit and the DR events were held between 2:00-6:00 p.m.

Table 12: 2018 coolControl Event Data for August and September

Date Outside

Temperature

(F)

Emerson

Sensi™

Thermostat Participation

Opt out

Percentage

(%)

Average

reduction

(kW/tstat)

Total

reduction

(kW)

8/6 86°F 310 36 0.34 103.9

8/28 83°F 326 37 0.48 156.7

8/29 85°F 328 33 0.26 84.5

9/5 90°F 323 43 0.33 107.8

Average reduction for the August and September events is 0.35 kW per thermostat, and the average

reduction for the August and September is 113.23 kW. The greatest reduction for the Emerson

Sensi™ thermostats was 0.48 kW across six (6) events.

coolControl Incentives

Customers receive a $30 sign-up incentive for registering in the coolControl Program once their device

was connected via Wi-Fi. A $20 incentive is available at the end of the second capability period (May 1

– September 30) if customers participate in 80 percent of called events/event-hours. Customer incentives

totaled approximately $29,312.00 during the 2018 DR capability period.13

13

Total costs for the coolControl Program are approximate because performance incentives and labor/administrative

costs have been forecasted for the months of November and December of 2018.

20

Think Eco’s sign-up incentives are in the form of an electronic Tango Card®, a platform that allows

customers to redeem the card at dozens of major retailers and non-profits.

coolControl Program Costs and Savings

Total costs for the coolControl Program totaled $225,083.04. Table 13 below depicts the expenses for the

2018 capability period with ThinkEco for the coolControl Program which include hardware costs for the

Sensi thermostats; costs for program services, including administrative and operations functions;

customer incentives for the 2018 season; and the annual operations and maintenance costs for the points

and rewards platform.

Table 13: ThinkEco Expenses for 2018 coolControl Program

coolControl Program Expenses

Description Total Amount ($)

Hardware Costs $ 3,960.00

Program Services $ 51,010.00

CAC Program Addition $ 70,038.00

Customer Incentives $ 29,312.00

Points and Rewards Program (Annual Fee) $ 15,000.00

Internal Labor/Administration $ 55,763.04

Total $ 225,083.04

The total curtailment potential for the coolControl program was 154.7 kW. The cost/kW for the

coolControl program for the 2018 capability period was $1,454.96/ kW.

coolControl Program Marketing and Recruitment

Kenmore is composed of working-to-middle class suburbs, with primarily single or duplex housing

built in the 1930s. Many of those living in the area had retired from an industrial plant nearby;

therefore, the population tends to be older and less tech savvy, which posed a few challenges for the

installation and retention of Emerson Sensi™ thermostats.

This year, National Grid provided a list of 10,052 email addresses of eligible customers for Emerson

Sensi™ recruitment. The average open rate for an email was 14%. Over the course of the

recruitment season, 51% of people who received an email opened at least one, compared to 46% in

2017.

21

Below is the platform ThinkEco utilized to track customers’ performance during the 2018 DR

capability period:

Figure 3: coolControl Customer Activity Page

Recruitment began in May of 2018 for the Emerson Sensi™ Wi-Fi thermostats, which were installed

by professional HVAC installers at no cost to the customer. Throughout the 2018 capability period,

a number of cost-free recruitment techniques were used, including unpaid media and social media

appearances, and recruitment emails. Many of the recruitment emails also offered prizes for

signing up and these proved to be the most cost-effective of the paid recruitment strategies

employed in 2018. ThinkEco also utilized other channels to market the program including email

and digital marketing opportunities, and building out in-person opportunities with the program.

As introduced in the Company’s 2017 DLM Program Report, there was an opportunity in 2018 for

National Grid to work on a partnership pilot program with the New York State Energy Research and

Development Authority (“NYSERDA”) in the Kenmore area to benefit and engage low-income

customers. With the combined efforts of National Grid and NYSERDA, the coolControl program

can attempt to reach many more low-income customers. This pilot program was intended to be

launched in July 2018 but this launch date was delayed due to certain complexities associated with

multiple parties' involvement. Marketing materials were distributed to customers, contractor training

was conducted on September 19, 2018, and an evaluation vendor was contracted to evaluate this pilot

program. Thermostat installation began in the fall of 2018. This pilot program will continue in 2019

in order to obtain a greater number of participants in the program.

22

DR incentives for the DLC program will remain unchanged for the 2019 capability period.

coolControl Program Website Development

To prepare for recruitment, an enrollment site was developed last year for the coolControl Program at

www.ngrid.com/coolcontrol by ThinkEco and the site was updated for the 2018 summer. Customers can

access this New York-specific site and sign up to participate in the program. Changes have been made to

remove smartAC kits from the website.

ConnectedSolutions Program

Introduction and Program Operations

ConnectedSolutions is a system-wide DLC Program that began in 2016. This full-system peak-

shaving program was launched in partnership with Whisker Labs (formerly known as WeatherBug

Home (“WBH”)) and in coordination with the DR programs of National Grid’s affiliates in

Massachusetts and Rhode Island. Currently, ConnectedSolutions is a Bring-Your-Own-Device

(“BYOD”) program that has seven (7) total Wi-Fi connected thermostats. ConnectedSolutions is

operated in partnership with EnergyHub, a Brooklyn-based company that works with National

Grid to support the growth of the Company’s DLC Programs. National Grid was in search of an

administrative management system that would allow both residential and small-commercial customers to

sign up for DR programs through an automated registration process using a web-based interface.

National Grid administered the RFP at the end 2017 and went through an extensive process of

choosing EnergyHub as the residential demand management system. There were several

qualifications that National Grid desired from a residential demand management vendor including:

Ease of the initial set-up for the residential demand management platform

Platform capability to connect to major thermostat manufacturers to enable and

validate eligible customer information

Ability for residential customers to sign up for DLC Programs through an automated

registration process using a web-based interface

Verification of customer eligibility through contact information submitted to

National Grid and to the platform

Calling of DR events through the web-based interface or portal

Reception of post-event data for both customers and National Grid based on events

and the entire DR season

23

Scalability and growth potential for DLC Programs

Overall potential to integrate other connected devices, including electric vehicles,

solar inverters, storage, and battery storage devices in the future

Potential to cut costs and increase overall efficiencies through device integration

The partnership with EnergyHub was established in coordination with National Grid’s affiliates in

Massachusetts and Rhode Island, and total costs and efficiencies are split amongst all three

jurisdictions. While there were several qualified vendors for the residential demand management

system at the time of the RFP issue, EnergyHub met all of the requirements that National Grid and

its affiliates were seeking. One of the greatest benefits through this partnership is that EnergyHub

has the potential to manage a total of eight (8) thermostat vendors and work with them directly

and administer and control them directly. This added benefit decreases the administrative burden

and permits a common, integrated platform for these thermostat manufacturers.

The majority of the beginning of 2018 was spent on the planning and integration of EnergyHub,

including the following tasks:

Vendor Management:

Cooperative discussions about process improvements with EnergyHub

Identification of website improvements needed

Set-up of accounting, billing, and other procurement processes

Event notification discussions/processes with the vendor

Program Management:

Event trigger process improvements

Event notification process improvements

Payment of sign-up and performance incentives to customers

Verification of customer information through EnergyHub portal

Coordination of National Grid and EnergyHub marketing efforts

DRMS Configuration:

Customer enrollment and set up within online portal

Calling of DR events from EnergyHub portal

Migration of Nest devices from Rush-Hour Rewards portal to EnergyHub portal

24

Addition of five (5) new thermostat vendors to ConnectedSolutions Program and

management and calling of DR events for these thermostats

Additional benefits from the DLC Program include:

Avoided generation capacity costs

Avoided Locational Based Marginal Pricing (“LBMP”)

Avoided transmission capacity infrastructure costs

Wholesale market price impacts

Avoided distribution capacity infrastructure costs

Net avoided CO2, SO2, and NOx emissions

There were a total of 3,550 thermostats enrolled in ConnectedSolutions by November 5, 2018.

Below is a table highlighting the breakdown of thermostats:

Table 14: 2018 ConnectedSolutions Thermostat Enrollments:

Thermostat

Manufacturer

ecobee Honeywell Nest Lux Emerson

Sensi™

Alarm.com Radio

Thermostat

2018 Season

Enrollment

251 876 2,269 20 105 5 24

There were a total of 1,931 thermostats enrolled in the ConnectedSolutions program by

November 3, 2017. With the increase to 3,550 thermostats in 2018, there has been a 184%

increase in thermostat enrollment across the ConnectedSolutions Program over the last year.

National Grid anticipates growth of the ConnectedSolutions program in 2019, particularly with an

increase in marketing strategies that will be described later in this report and with additional

thermostat vendors that National Grid has engaged over the last year that have been added to the

program near the end of the 2018 summer. There were only 202 enrollment withdrawals u in the

program during the 2018 capability period, a little less than 6% of the population.

National Grid continues to research additional technology additions to the program in 2019 and

beyond, including connected water heaters, pool pumps, and ESS that could increase participation

in the program. These technological advances can provide customers with various connected

devices and the Company is seeking out opportunities to integrate these options into current DR

25

programs over the next several years. Additions of these technologies into future DR programs

will ultimately depend upon their cost-effectiveness and National Grid will seek to find

collaborative opportunities to do so.

Technology Overview and DR Events

The summer of 2018 experienced high temperatures. There were a total of nine (9) events held

during the 2018 capability period for the ConnectedSolutions program. Below is a summary of the

season’s DR events:

Table 15: 2018 ConnectedSolutions DR Events

2018 ConnectedSolutions Events

14

Event Date 6/18/18 7/2/18 7/3/18 7/5/18 7/16/18 8/6/18 8/28/18 8/29/18 9/5/18

Number of Participants

2,550 2,696 2,706 2,714 2,711 2,936 3,306 3,340 2,973

Demand Reduction

(MW)

2.05 2.35 2.38 2.40 2.34 2.46 2.25 2.69 2.37

Total Energy Savings (MWh)

4.74 7.66 7.92 7.67 6.15 3.92 4.31 5.41 9.48

Average Reduction per Device (kW)

0.761 0.962 0.96 1.01 0.96 0.70 0.70 0.85 0.80

Average Participation (%)

63.6 66.6 68.0 67.9 68.06 64.5 71.4 72.9 73.6

Average duration of a DR event was four (4) hours this summer. Initially the hours for events

called were between 3:00-7:00 p.m. After August 6, DR events were scheduled and called between

2:00-6:00 p.m. The event times we designed to coincide with CSRP event windows. A similar

strategy was deployed with calling of events using regular dispatch versus Firm Load Dispatch,

which was implemented later in the summer. Firm Load Dispatch is an event dispatch method that

allows for more constant load reduction over the entire event, rather than an early curtailment spike

and reduction in performance over the duration of the event.

In the nine (9) events this summer, the number of participants has grown steadily with each event,

as thermostat participants in each event has grown by 187% in total between the first or last event.

The demand reduction has remained similar for all of the nine (9) events at an average demand

reduction of 2.34 MW. Average participation throughout all nine (9) events has remained steady at

a little over 60% throughout the summer.

14

This table is broken out by DR event by date. There were three main thermostat participants for the majority of

the summer: Nest, Honeywell, and ecobee. After August 6, four additional thermostat vendors were added to the

portfolio for a total of 7 thermostat manufacturers: Honeywell, Nest, Lux, ecobee, Emerson Sensi™, Alarm.com,

and Radio Thermostat Company of America (“RTCOA”) thermostats.

26

On the device level, the average demand shed per device throughout the entire 2018 capability

period is 0.86 kW. The demand per device has remained consistent throughout the season with a

high average shed per device on July 5, 2018 at 1.01 kW.

Program Incentives

Customers receive a $30 incentive for signing up for the ConnectedSolutions program through the

participation of the seven (7) thermostat manufacturers. Customers receive a $20 participation payment

beginning in their second year of participation in the program, as long as they participate in 80 percent of

the DR events or event-hours called.

2018 Program Costs and Savings

Total ConnectedSolutions Program costs include all demand management platform charges from

EnergyHub, any and all costs from the transition from Whisker Labs, program operation costs, any

hardware and equipment costs, and total marketing fees. Costs for the months of November and

December have been estimated15

. The table below illustrates program costs for ConnectedSolutions:

Table 16: ConnectedSolutions Program Costs

ConnectedSolutions Program Costs Total

Description

WhiskerLabs (formerly WeatherBug Home) DRMS Fees $ 8,162.00

Device Manufacturer Annual Fees and EnergyHub Platform Fees $ 83,419.66

All Incentive Fees (Sign-Up and Performance) $ 75,555.00

Internal Labor/Administrative Fees $ 55,763.04

Total $ 222,899.70

In aggregate, there were 3,550 devices signed up for the ConnectedSolutions program at the end

of the 2018 capability period. The total curtailment potential was 3.053 MW (3,053 kW) for all

devices in the 2018 capability period. With a corresponding total program cost of $222,899.70,

the cost/kW equals $73.01/kW.

15

As with the coolControl Program, performance incentives and labor/administrative costs have been forecasted for

November and December 2018.

27

The total costs for the DLC Program, including coolControl and ConnectedSolutions, as well as

labor charges, are represented in the table below:

Table 17: Total 2018 DLC Program Costs

2018 DLC Program Costs

coolControl Program $ 169,320.00

ConnectedSolutions Program

$ 222,899.70

Total $ 392,219.70

Table 18: Total 2018 DLC Program Curtailment

DLC Program

Curtailment

Average Demand

Reduction per

Device (kW)

Total Number

of

Participating

Devices

(thermostats)

Total

Curtailed

Demand

(MW)

coolControl Program 0.35 442 0.155

ConnectedSolutions Program

0.86 3,550 3.053

Total 1.21 3,992 3.208

Benefit-Cost Analysis for ConnectedSolutions and coolControl DLC Programs

This section details the evaluation of BCA for the coolControl and ConnectedSolutions Programs using

the SCT, UCT, and RIM tests. These BCA tests below portray the cost-effectiveness of the Company’s

DLM programs separately, as well as an entire DLC Program portfolio.

The SCT test for the ConnectedSolutions Program, including avoided generation capacity costs, yields a

result of 1.84 and $187,708 in net benefits over a ten-year period. Table 19 below applies the SCT test

for the coolControl and ConnectedSolutions Programs.

28

Table 19: Cost-effectiveness for 2018 DLC Programs Using the SCT (including avoided generation

capacity costs):

National Grid Demand Response Cost-effectiveness SCT Results

coolControl ConnectedSolutions Total DLC

Benefits $ 12,882.04 $ 410,607.63 $ 423,489.67

Costs $ 225,083.04 $ 222,899.70 $ 447,982.74

Net

Benefits $ (212,201.00) $ 187,707.93 $ (24,493.07)

SCT 0.06 1.84 0.95

The UCT, including avoided generation capacity costs, for ConnectedSolutions yields a result of 1.63

and $158,946.95 in net benefits over a ten-year period. Table 20 below displays the UCT for the

coolControl and ConnectedSolutions Programs.

Table 20: Cost-effectiveness Tests for 2018 DLC Programs Using the UCT (including avoided

generation capacity costs):

National Grid Demand Response Cost-effectiveness UTC Results

coolControl ConnectedSolutions Total DLC

Benefits $ 12,882.04 $ 410,607.63 $ 423,489.67

Costs $ 254,125.77 $ 251,660.68 $ 505,786.45

Net

Benefits $ (241,243.73) $ 158,946.95 $ (82,296.78)

UTC 0.05 1.63 0.84

The RIM for the DLC Portfolio, including avoided generation capacity costs, yields a result of 1.30 and -

$94,234.38 in net benefits over a ten-year period. Table 21 below displays the RIM for the coolControl

and ConnectedSolutions Programs.

29

Table 21: Cost-effectiveness Tests for 2018 DLC Programs Using the RIM (including avoided

generation capacity costs):

National Grid Demand Response Cost-effectiveness RIM Results

coolControl ConnectedSolutions Total RES

Benefits $ 12,882.04 $ 410,607.63 $ 423,489.67

Costs $ 319,472.54 $ 316,373.25 $ 635,845.80

Net

Benefits $ (306,590.50) $ 94,234.38 $ (212,356.13)

RIM 0.04 1.30 0.67

Based on the BCA Handbook, a BCR above 1.0 indicates that a program is cost effective. The BCR for

each of the tests for National Grid’s ConnectedSolutions Program is above 1.0. In 2018, National Grid

added more devices to the ConnectedSolutions Program and increased overall cost effectiveness by

decreasing overall cost per device. Based on interim enrollment trends, National Grid continues to expect

the number of devices participating at the start of the 2019 capability period to increase steadily.

Additionally, EnergyHub will continue to reduce per device management and administrative costs, which

will raise program BCA results for 2019.

The BCR for the coolControl Program for each of the tests is less than one. While the coolControl BCR

affects the overall DLC Program portfolio’s cost-effectiveness, National Grid is particularly focused on

the BCR for ConnectedSolutions; the Company does not plan on operating the coolControl Program for

the 2019 season and beyond. For more information on the discontinuation of the program, please refer to

the DLC Program Changes section below.

ConnectedSolutions Marketing and Recruitment

The ConnectedSolutions program outreach was undertaken mainly by the partnership between

National Grid and EnergyHub in 2018. While, as in years past, Honeywell, ecobee, and Nest

contacted customers directly for program recruitment, EnergyHub played a key role in engaging

with the three main thermostat vendors and with National Grid to align brand messaging,

recruitment efforts, and other marketing campaigns for the 2018 summer. Partner marketing

through the thermostat manufacturers has been driving recruitment. In 2018, the email open rates

for ConnectedSolutions were approximately 45.2%, which was 20% higher than the National

average. National Grid will continue to engage customers through these recruitment emails for

2019. The Company plans to augment those channels in 2019 and beyond with direct outreach to

customers who took advantage of $75 rebates available from gas utilities for installation of Wi-Fi

30

thermostats. Other methods, such as point-of-purchase displays in retail outlets (e.g., The Home

Depot) may also be used as a recruitment tool in future program years. Based on EnergyHub’s

findings, there are approximately 46,900 customers with connected thermostats that serve as the

Company’s base for this program; this is roughly 7% of the population enrolled.

There are several other recruitment opportunities National Grid has begun to look into in order to increase

participation in the ConnectedSolutions program. With the addition of EnergyHub, there have been

many more targeted marketing efforts that have taken effect in 2018 and the Company is also looking into

targeting customers who received energy efficiency program rebates but are not currently enrolled in

ConnectedSolutions. The Company is also investigating other residential devices for customers for 2019

and evaluating their cost effectiveness, and will continue to evaluate other residential technologies to

determine which devices merit addition to the DLC Program.

In 2018, National Grid partnered with NYSERDA through the EmPower New York Program to target

low-income customers in the Kenmore area. NYSERDA is responsible for the installation of the

Emerson Sensi™ thermostats to deliver the EmPower New York Program to eligible customers in

Kenmore, while National Grid provides these customers with the thermostats free-of-charge. The

program was launched at the end of the 2018 DR capability period and contractors are to begin the

installation of thermostats in early November. This pilot program will continue into the 2019 DR

capability period, which will allow both NYSERDA and National Grid to evaluate results and findings

from the effort. NYSERDA has procured an evaluation vendor to evaluate efforts of this pilot program at

the end of the 2019 season.

ConnectedSolutions Website Development

In 2018, the website and landing page for the ConnectedSolutions program was updated and includes all

the relevant information for National Grid customers. At the end of this capability period, all main

thermostat manufacturers have been included as a part of the landing page. National Grid envisions re-

visiting the ConnectedSolutions landing page through EnergyHub prior to next season as well.

Lastly, National Grid also plans to promote the ConnectedSolutions program as a part of Nest flash sales

that occur periodically as a part of the promotion of National Grid’s energy efficiency programs.

Customers can participate in the Nest flash sale and will be redirected to the DR website to allow for

participation in the program.

31

Customers can sign up and access information about the ConnectedSolutions program at

www.ngrid.com/ny-connectedsolutions for the enrollment portal through the EnergyHub platform.

The program websites serve as a central repository of information and direct customers to the sign-up

form for the ConnectedSolutions program. National Grid’s web marketing team has been administering

and improving the website in order to make it clear and easy for customers to access all relevant

information about the ConnectedSolutions Program.

2019 DLC Program Changes and Updates

Below are enhancements or changes that National Grid intends to make for the 2019 DR capability

period:

1. Four-hour hour test event. Although National Grid did not call any test events for either

coolControl or ConnectedSolutions this summer, all DLC events for the 2018 DR capability

period were called for four hours. As discussed, this summer was quite hot and there was no need

to call any test events. However, since all actual events were called for four (4) hours, it is

reasonable to justify the use of four-hour test events for future capability periods. Based on the

average demand reduction for all four events, there was no evidence of customer participation

fatigue, even with multiple events, sometimes on consecutive days. Therefore, National Grid will

call all test events in the future as four-hour test event timeframes.

2. Discontinuation of coolControl Program from 2019 DLM Programs. Kenmore was determined

to be the first NWA area for which there was a DR need in the Upstate New York area. The

DPAM team has re-evaluated the needs associated with the Kenmore area and has determined

that the most suitable opportunity for this area to address the system need is with an ESS

installation. An ESS will meet the Kenmore need, thus eliminating the need for additional

focused DR offerings. Existing Emerson Sensi™ thermostat participants will be offered the

ability to transition their participation into the ConnectedSolutions program. This will provide

these customers with an ongoing means to remain engaged in DR using the Emerson Sensi™

thermostat they have received. This allows the Company to continue to grow the rapidly

expanding, system-wide DLC Program.

In addition, National Grid was required to evaluate the BCA of all DLM programs and to ensure

that the BCA was greater than 1.0 for all implemented programs. While the Company’s

32

coolControl Program has been operational for the past three years, it has not been cost-effective

for that time period and there have not been any major improvements in the program over this

timeframe to indicate that it would reach cost-effectiveness. National Grid has learned a great

deal about the target demographic of the Kenmore area and can apply the engagement strategies

employed there to other potential areas in the future.

3. BCR and Continuation of ConnectedSolutions Program. Per the April 2018 Order, National

Grid was required to respond to the continuation and overall cost-effectiveness of the DLC

Programs. As the BCR for the system-wide ConnectedSolutions Program is greater than one,

the Company will continue to offer that program for the 2019 season and foreseeable future.

DLM Program Conclusion

Implementation of National Grid’s DLM Programs is aligned with New York State’s goals, particularly

those that are cited in the 2015 State Energy Plan referencing the achievement of 50% of electricity

generated by renewable energy resources by 2030, the 40% reduction of GHG emissions from the energy

sector by 2030, and the longer term goal of decreasing total carbon emissions 80% by 2050. Avoidance

of carbon reductions through DR programs contributes to the State’s goals, and DR has been proven to

lower carbon emissions and contribute to overall peak load reduction.

National Grid’s DLM Programs have grown significantly in the 2018 capability period. This past

summer was relatively warm and there were several events held for the CSRP and the DLC

Programs. National Grid was able to relieve stress on the Company’s electrical equipment and

overall electric system through implementing the system-wide DLM Programs. National Grid

seeks to increase customer engagement and impart an understanding about each customer’s role in

grid reliability and flexibility, reduction of GHG emissions, and peak load curtailment as an overall

benefit to the grid through the Company’s DLM Programs.