1. NH Grid Modernization Working Group: Slides for 1st Meeting
April 29, 2016
Facilitator/Mediator: Dr. Jonathan Raab, Raab Associates
Consultant: Tim Woolf, Synapse Energy Economics

2. NH Grid Mod WG: Members (18)
Stakeholder Type
Candidate Stakeholders
State Government (2)
OEP, PUC (ex officio)
Utilities (3)
Eversource, Unitil, Liberty
Clean Energy Sector (5)
NHSEA/NECEC, NEEP, Revolution Energy, Energy Freedom Coalition of America, The Jordan Institute
Energy Consumers (2)
OCA, NH Legal Assistance
Environmental NGOs (2)
Acadia, CLF
Retail Energy Suppliers; Aggregators (2)
RESA (Constellation; Direct Energy), Axsess Group
Other Members (Cities, individual) (2)
City of Lebanon, Patricia Martin (retired engineer)
Resources
ISO New England, New Hampshire Energy Coop

3. NH Stakeholder Process
NH PUC
NH Grid Mod
Stakeholder Group
Raab Associates, Facilitator
Synapse Energy Economics, Consultant

4. NH Proposed Grid Modernization Stakeholder Process
Months
Tasks
1-2
Stakeholder Process Design
NH PUC Scoping Order
3 - 4
Outcomes and Capabilities
Joint Fact Finding on Existing Functionality
5 - 8
Grid Mod Planning Issues and Processes
Customer Engagement (rate design, meters, etc.)
Cost Recovery/Incentives
9 - 10
Final Recommendations/Report
Note: No stakeholder meetings July/Aug - approximately a one year process

5. NH Grid Mod Workplan by Meeting
Outcomes & Capabilities
Data Gathering
Distribution System Planning
Customer Engagement (rate design, meters, etc.)
Cost Recovery/Incentives
Final Report
SH Mtg. #1:
April 29
Introduce/
Discuss
SH Mtg. #2:
May 26
Develop Recommendations
Review
SH Mtg. #3:
June 24
SH Mtg. #4:
Sept. (TBD)
SH Mtg. #5:
Oct. (TBD)
SH Mtg. #6:
Nov. (TBD)
Refine Recommendations
SH Mtg. #7:
Dec. (TBD)
Finalize Recommendations
Detailed Report Outline
SH Mtg. #8
Jan. (TBD)
Review/Finalize

6. NH PUC Grid Modernization: Working Group-DRAFT Groundrules
April 29, 2016
Facilitator/Mediator:
Dr. Jonathan Raab, Raab Associates, Ltd

7. Participation
Each representative in the Working Group can designate an alternate (drawn either from their own organization or from another related organization).
Only the representative or alternate (in the case of the representative’s absence or delegation), will have a seat at the table and participate in any formal deliberations (negotiation and recommendation decisions).
NH PUC Staff (as ex officio members) can participate in all discussions but will refrain from participating in any deliberations.
Other attendees who are not seated at the the table (alternates and members of the public) may also be given a chance to express their opinions and make suggestions at appropriate junctures, as time allows and as determined by the Facilitator/Mediator.

8. Roles & Responsibilities: Members
Working Group representatives and alternates will make every attempt to attend all applicable meetings, to be on-time, and to review all documents disseminated prior to the meeting.
If a representative or his\her alternate cannot attend a meeting, the representative should let the Facilitator/Mediator know prior to the meeting (by telephone or ).
Representatives, alternates, and other participants are charged with participating in a constructive forum where diverse points of view are voiced and examined in a professional and balanced way. Personal attacks will not be permitted.
All representatives and alternates agree to act in good faith in the discussions and negotiations. ‘Good faith’ means that they will be forthright and communicative about the interests and preferences of their organization and will actively seek agreement wherever possible.

9. Roles & Responsibilities: Members (continued)
It is the responsibility of the representatives and alternates to keep their organizations informed of developments in the Working Group process.
Representatives and alternates may confer with each other during meeting breaks and in between meetings, and are encouraged to do so.
Representative and alternates are not permitted to quote or otherwise represent other members of the Working Group process to the press or other outside entities (including in blogs), or to speak on behalf of the Working Group unless so designated to do so by the Working Group.
Representatives and alternates are free to discuss pertinent matters with the Facilitator/Mediator and the PUC Staff’s Consultant if and when the need arises.

10. Report Recommendations Decision-making
The goal of the process is to make substantive recommendations by unanimous agreement (i.e., consensus) of the Working Group members (organizations) where possible.
The Working Group’s Final Report to the PUC at the end of the process will identify all areas of agreement, and will provide a description of the alternative approaches preferred by members if and where the Group is split on what to recommend.
Where multiple options are offered, Working Group members supporting alternative approaches will ascribe their organizations’ names to their preferred alternative.
NH PUC staff will not participate directly in decision- making or add their organizational names to the Final Report.

11. Roles & Responsibilities: Facilitator/Mediator & Consultant
The Facilitator/Mediator’s primary function is to help design and manage productive and well-informed meetings. The Facilitator/Mediator will also be responsible for recording points of agreement and disagreement.
 The Facilitator/Mediator will impartially, and in a non-partisan manner, (not favoring any representative, alternate, or organization over another), facilitate all meetings of the Working Group.
The Facilitator/Mediator (with assistance from the PUC Staff and its Consultant) will prepare draft agendas and meeting summaries in a timely fashion for distribution to the members.
The Facilitator/Mediator (with assistance from the PUC Staff and its Consultant) will take the lead in assembling the Final Report to the Commission on the Working Group’s behalf, and with their review and sign-off.
Facilitator/Mediator (and the PUC Staff’s Consultant) are free to talk with representative and alternates outside the regularly scheduled meeting as they deem appropriate.

12. Documents and Comments
All documents will be posted on a web site in a timely manner (maintained by Raab Associates) for the duration of the process.
Parties and members of the public will have an opportunity to comment on the Working Group’s recommendations after the Final Report is issued.

13. Grid Mod: Outcomes, Capabilities, & Enablers
See Table 2 from NH PUC Order originally from MA Grid Mod Final Stakeholder Report

14. Grid-Facing Data
Supplied by Utilities--Eversource, Liberty, and Unitil
Compiled by Synapse Energy Economics
See following slides

15. T&D components automated
Feeders
Substations
Capacitors
Eversource
Total
Automated
Percent
464
170
37%
173
102
59%
983
628
64%
Unitil
100 97
97% 30 28
94%
129 51
40%
Liberty 41 7
17% 15 10
67%
128 6 5%

16. T&D components measure min. load
Feeders
Substations
Line section
Total
Min load
Percent
Eversource
464
170
37%  
173
102
59%
Unclear question – thus answer not provided
Eversource (including source only)
252
54%
Unitil
System not configured to record
Liberty 41 28
68% 15 5
33% 0%
*Number of fully automated feeders. Source automation can only be measured at source.

17. Systems capable of reverse power flow
Substation transformers
Substation regulation
Feeder regulation
Eversource
8 known locations have reverse power flows due to larger Non-Utility Generator coming on line and detailed interconnection studies were completed to determine required system upgrades. Ultimately, each site could be made to accept reverse power, but scope of upgrades unknown till interconnection study is done.
For pole top regulators 48%
Unitil
No substation transformers designed for reverse power flow
No substation regulators designed for reverse power flow
No feeder/circuit regulators capable of reverse power flow. Sub-transmission systems designed for reverse power flow.
Liberty
No substation transformers capable of reverse power flow
27%
75%

18. Type & location of Network System Enablers - Eversource
Capability
System Location
Notes
Fault Detection, Isolation, Restoration (FDIR)
Distribution System and Substations
329 SCADA controlled substation breakers and 550 SCADA controlled pole top units capable of detecting faults.
Some designed to trip while all others can be manually switched through SCADA to pick up load. A Distribution Management System (DMS) pilot installed in 2010 will be upgraded later in 2016.
Expansion to the rest of the system is planned in future years to allow full automation for all existing SCADA controlled breaker and pole top units and any new units.
Automated Feeder Reconfiguration
FDIR devices continuously monitor the system, alerting operators of loading concerns and faults. A DMS pilot installed in 2010 will be upgraded later in 2016.
Expansion to the rest of the ESNH system is planned in future years. to allow full automation for all existing SCADA controlled breaker and pole top units and any new units installed.
Integrated Volt/VAR Control, Conservation Voltage Reduction
Transmission, Distribution and Substations
65 substation capacitor banks controlled via SCADA. 14 pole top distribution capacitors controlled via SCADA. 563 distribution pole mounted capacitors that are controlled remotely via time, voltage, temperature or VAR controls. No CVR.
Remote Monitoring & Diagnostics (equipment conditions)
At major Transmission and Distribution Substations, alarms alert operators for various abnormal conditions.
Remote Monitoring & Diagnostics (system conditions)
All remotely controlled pole mounted reclosers and switches monitor the system providing voltage, current, power factor and fault indication.

19. Type & location of Network System Enablers - Unitil
Capability
System Location
Notes
Fault Detection, Isolation, Restoration (FDIR)
None
Automated Feeder Reconfiguration
Distribution/Substation
2 locations
Integrated Volt/VAR Control, Conservation Voltage Reduction
Remote Monitoring & Diagnostics ( equipment conditions)
Substation
4 substations with GE and Weidman transformer hydrogen monitoring systems; SCADA system monitors e.g. communications, pressure, oil temps. Etc.
Remote Monitoring & Diagnostics (system conditions)
AMI system provides system voltage, loads, outage and health information. SCADA sustem monitors e.g. communications, pressure, frequency, oil temps. Etc.

20. Type & location of Network System Enablers - Liberty
Capability
System Location
Notes
Fault Detection, Isolation, Restoration (FDIR)
Distribution Line Sections
Fault Indicators and Grid Sentry Line Sensors
Automated Feeder Reconfiguration
5 Loop Schemes
Integrated Volt/VAR Control, Conservation Voltage Reduction
None
Remote Monitoring & Diagnostics ( equipment conditions)
Remote Monitoring & Diagnostics (system conditions)
Substation
Remote monitoring in 68% of breakers

21. Customer Engagement and Metering
Supplied by Utilities--Eversource, Liberty, and Unitil
Compiled by Synapse Energy Economics
See following slides

22. No. customers for each rate offering
Eversource
Unitil
Liberty
Residential
Gen. Service
Outdoor lighting
Flat energy rates
426,576 -
953
724
7,239
Inclining block rates
65,237
35,435
Declining block rates
75,517
Seasonal Rate
Time-of-use rates 38
159
1,420
Critical peak pricing
Peak-time rebates
Total no. of customers:
426,614
75,676
11,181
1,706
35,877
6,436
685

23. Customer participation in EE programs, 2006 to 2015
No. of customers
Eversource
Unitil
Liberty
Residential
C&I
Gen. Service
Non-residential
2006
61,490
1,042
11,295 93
4,297
144
2007
77,143
972
10,883
110
5,194 87
2008
87,328
917
11,819 80
22,537
112
2009
71,216
1,187
9,456
100
14,064 83
2010
94,020
944
11,196 26
17,465 85
2011
79,194
862
9,887 77
19,386
118
2012
83,489
1,017
10,180 54
7,464
131
2013
80,714
1,252
10,498 81
20,622 47
2014
100,827
1,512
6,611 95
18,201
275
2015
94,840
987
8,295
22,317
176

24. Customer participation in DR programs, 2006 to 2015
No. of customers
Eversource
Unitil
Liberty
Residential
C&I
Gen. Service
Non-residential
2006
3,279
157 -
2007
3,319
136
2008
3,166
231
2009
3,303
251
2010
3,554
269
2011
3,614
229
2012
3,659
220
2013
3,675
219
2014
3,669
217
2015
3,620
211

25. Behind-the-meter technologies installed
 No. of customers
Eversource
Unitil
Liberty
Residential
Gen. Service
Total
Non-residential
Photovoltaics
2,407
266
2,673
389*
39*
428*
272 24
296
CHP 1 14 15 2
Other DR 34 33 67
2**
7**
9**
N/A
Plug-in electric vehicles
Unable to determine
Batteries or other storage devices
Total no. of customers:
426,614
75,676
502,290
65,237
11,181
76,418
35,877
6,436
42,313
* Data response by Unitil gives installations by fuel type. Unitil's "Solar" category is assumed to be PV.
** Other DR is the summation of Wind, Hydro, Gas, Wood and Biomass installations provided by Unitil

26. Annual installation schedule of current meters - Liberty
The table below provides an annual schedule of the installation date of all of our current meters.
Liberty Utilities converted the majority of the meter population to AMR in Of the
approximately 43,000 meters, 3,000 are manually read and approximately 385 are interval
meters probed monthly for hourly reads. Since 2002, the Company has introduced an AMR
meter for customers with a demand of 20 KW – 200 KW. These meters are read using a probe
wireless technology, or analog phone line.
Year
No. meters installed in year
No. AMR meters installed
No. of AMI meter
2002
Conversion year - majority of meters
Total current meters
43,333
40,254

27. Annual installation schedule of current meters - Unitil
Year
UES Total
Notes
2005
158
Decision to AMI System was made, we started purchasing AMI meters even though the system wasn't in place.
2006
2,953
AMI project started in 3rd quarter of 2006
2007
49,786
AMI project replaced whole system
2008
3,116
These meter sets reflect URV replacement problem, not all new meter sets.
2009
1,782
2010
3,983
2011
2,188
2012
2,268
2013
3,178
2014
2,567
2015
4,013
These meter sets reflect URV replacement problem, not all new meter sets and PLX meter additions in Seacoast.
2016
1,029
Total
77,021

28. Annual installation schedule of current meters - Eversource
AMR meters
Remotely read meters
Manually read meters
Total
Purchase years
C&I
Residential
2016
5,646
4,220 1
9,867
2015
45,090
238,967 28 25
284,110
2014
23,460
219,928 8
107
243,503
2013
875
8,128 10 83 9
9,105
2012
458
3,494 6
208 14
4,180
2011
468
3,242 58
714
4,483
2010
292
1,768 43
261 2
2,366
2009 19
106 33
291 15
465
2008 30
445
337
828
2007
104
392
141
648
2006 13 75
320
420
2005 77
413 5
148 4
647
2004
228
1,356 7
339 20
1,950
2003
314
2,473
138 3
2,932
2002
227
1,173
114
1,664
2001
123
700 11
900
2000
130
731
1,333
1999 and earlier
105
363
816
TOTALS
77,563
487,716
234
4,139
564
570,217

29. Utility metering age and cost recovery assumptions
Eversource
Unitil
Liberty
Average meter age (years) 2
All meters: 20 Electronic endpoint meters: 7.5
Does not have data on meter life of the meters retrofitted to accomodate the AMR technology
Average book life (years) 35 20 19
Average assumed operating life (years)
20 to 25
Avg meter: 40 Endpoint: 20
Average expected life remaining (years)
18 to 23
12.5 (based on age of endpoints)
6 to 18

30. No. customers with following meter capabilities
Eversource*
AMR & remotely read meters
Manually read meters
Liberty
Unitil
Residential
C&I
a. Drive-by meter reading
40,254
All AMI
487,716
77,563
b. Time-of-use register
1178
All 40 1
345
c. Reading of interval data
358
2170, currently expanding capabilities
234
112
1,815
d. Daily reading at the Company’s office 8
e. On-demand / real-time meter reading
f. Communication to meter from the Company
g. Communication from meter to customer end-use equipment
None, but system capable 16
1,537
h. Remote switch for service connection / disconnection.
451, but system capable
11,799
1,011
i. Power quality reading
1903, but system capable
j. Outage identification and restoration notification
k. Planning data (snap-shot demand and system reads).
*Eversource also has 1,927 interval recording meters that are read manually (via probe) and not classified as either AMR or remotely read.

31. Planning for Meeting #2 Outcomes, Capabilities, & Enablers
Provide us any suggested changes (including for definitions)— by May 19th
Data gathering
Any other data from distribution companies needed?
Other information that would be useful?
Distribution System Planning
See Questions from Order (next slide)
How to prepare for this between now and next meeting?

32. Distribution Planning
Do the current IRP requirements sufficiently define the scope of grid modernization capabilities and resources to be assessed in each plan, both in terms of grid-facing and customer-facing grid modernization technologies?
How frequently should utilities be required to file their plans?
Should the Commission review of the plans be modified in any way to account for grid modernization planning needs and challenges?
Should the process for stakeholder participation in the planning process be modified in any way to account for grid modernization planning?

33. Distribution Planning (continued)
How should cost-effectiveness be evaluated for grid modernization technologies and practices? Should cost- effectiveness account for (1) the geographic location of technologies and practices; and (2) the time-varying nature of generation, transmission, and distribution costs?
How should the utility planning process account for the role of third-party vendors in providing grid modernization technologies and services, particularly customer-facing technologies and services?

34. Meeting Notes on Outcomes

35. Outcome: Consumer/Customer Engagement and Empowerment
Capabilities/Activities
TVR and Rate Design (more broadly)
Choice
Prosumers
Home Energy Mgt. Systems/Remote Control/Internet of Things
Information Transparency/Management/Control/Privacy
Stakeholder Engagement in Grid Planning
Education and Enhanced Technical Assistance
Enabling Innovation/New Ideas
Access to (consistent) Customer and System Data (privacy respected)

36. Outcome: Consumer/Customer Engagement and Empowerment
Network System Enablers
Billing System (possibly 3rd party option)
Metering System
Targeted Tariffs (e.g., EV rates)
Geotargeting-(ID areas of high value for DERs, storage, etc, energy efficiency)
Customer Information Management Systems
Communication System for 2-Way Information Flow (e.g.., Customer Portals)

37. Outcome: Resilience (Prevent and Reduce Impact of Outages)
Capabilities/Activities
[Include all Capabilities/Activities under Reduce Impact of Outages and Prevent Outages]
Pre-detection of potential outages
Intentional Islanding (e.g., Strategic Microgrids)
Distributed Energy Resources (including demand response)
Situational Awareness
Back-Up Generation Resources
Network Systems Enablers
Real-Time Communication System
System Sensors
Voltage and Frequency Controls, Protection