BEFORE THE NEW YORK STATE PUBLIC SERVICE COMMISSION ----------------------------------------------------------------------------x Proceeding on Motion of the Commission as to the Rates, Charges, Rules and Regulations of Case 17-E-____ Central Hudson Gas & Electric Corporation for Electric Service ----------------------------------------------------------------------------x ----------------------------------------------------------------------------x Proceeding on Motion of the Commission as to the Rates, Charges, Rules and Regulations of Case 17-G-____ Central Hudson Gas & Electric Corporation for Gas Service ----------------------------------------------------------------------------x DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL July 28, 2017
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DIRECT TESTIMONY OF THE DISTRIBUTED … A. Our names are Paul Haering, Hal Turner, David Dittmann, Heather 6 Adams, John Borchert and Tim Hayes. 7 Q. Mr. Haering, please ... 8 Design
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BEFORE THE NEW YORK STATE
PUBLIC SERVICE COMMISSION
----------------------------------------------------------------------------x Proceeding on Motion of the Commission as to the Rates, Charges, Rules and Regulations of Case 17-E-____ Central Hudson Gas & Electric Corporation for Electric Service ----------------------------------------------------------------------------x ----------------------------------------------------------------------------x Proceeding on Motion of the Commission as to the Rates, Charges, Rules and Regulations of Case 17-G-____ Central Hudson Gas & Electric Corporation for Gas Service ----------------------------------------------------------------------------x
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
July 28, 2017
i
1
TABLE OF CONTENTS 2
I. INTRODUCTION ........................................................................................... 1 3
II. PURPOSE OF TESTIMONY .......................................................................... 9 4
III. SYSTEM PLANNING / DER INTERCONNECTION ENHANCEMENTS ...... 10 5
IV. DISTRIBUTION SYSTEM OPERATIONS .................................................... 36 6
V. DSP FORMATION AND POLICY ................................................................ 46 7
VI. NON WIRES AND NON PIPES ALTERNATIVES ....................................... 48 8
VII. ENERGY STORAGE PROJECTS ............................................................... 50 9
VIII. REV DEMO PROJECT ................................................................................ 55 10
11
12
13
14
15
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
1
1 I. INTRODUCTION 2
Q. Please state the names of the members of the Distribution System 3
Platform Panel (“Panel”). 4
A. Our names are Paul Haering, Hal Turner, David Dittmann, Heather 5
Adams, John Borchert and Tim Hayes. 6
Q. Mr. Haering, please state your current employer and business address. 7
A. I am employed by Central Hudson Gas & Electric Corporation (“Central 8
Hudson” or the “Company”) and my business address is 284 South 9
Avenue, Poughkeepsie, New York 12601. 10
Q. Mr. Haering, in what capacity are you employed by Central Hudson and 11
what is your scope of responsibilities? 12
A. I am Senior Vice President of Engineering and System Operations. In that 13
capacity, I am responsible for the engineering planning and designs for 14
Central Hudson’s gas and electric transmission and distribution systems. I 15
am also responsible for the construction, operation, and maintenance of 16
our electrical substations. In addition, I have responsibility for the 17
Company’s System Operations, Energy Management System, and North 18
American Electric Reliability Corporation (“NERC”) Reliability Compliance 19
organizations. 20
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
2
Q. Mr. Haering, what is your educational background and professional 1
experience? 2
A. I graduated from Manhattan College in 1986 with a Bachelor of 3
Engineering in Electrical Engineering. In 1992, I received a Masters of 4
Electrical Engineering from Polytechnic University. In 2007, I received a 5
Master of Business Administration from Rensselaer Polytechnic Institute. 6
I joined Central Hudson in 1986 as a Junior Engineer in the Substation 7
Design Section. In 1989, I was transferred to work as a Staff Engineer in 8
the Operations Services Division, which is responsible for the operation, 9
maintenance, and construction of the Company’s substation facilities. 10
In 1994, I was promoted to the position of Operations Supervisor in the 11
Operations Services Division. In 2000, I was transferred to the position of 12
Engineer in the Electric System Protection Section. In 2001, I became 13
Section Engineer for the Distribution Engineering Section. In 2003, I was 14
promoted to the position of Manager of Electric Transmission and 15
Distribution. In 2004, I was promoted to the position of Manager of 16
Electric Engineering Services. In May 2007, I was named the Assistant 17
Vice President of Engineering and Environmental Services and, in 18
December 2007, I was named Vice President of Engineering and 19
Environmental Services. In August 2011, I was named Vice President of 20
Engineering and System Operations and, in February 2017, I was named 21
to my current position. 22
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
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Q. Mr. Haering, have you previously testified before the New York State 1
Public Service Commission (“PSC” or “Commission”)? 2
A. Yes. I testified in Cases 05-E-0934, 05-G-0935, 08-E-0887, 08-G-0888, 3
09-E-0588, 09-G-0599, 14-E-0318, and 14-E-0319. 4
Q. Mr. Turner, please state your current employer and business address. 5
A. I am employed by Central Hudson and my business address is 284 South 6
Avenue, Poughkeepsie, New York 12601. 7
Q. Mr. Turner, in what capacity are you employed by Central Hudson and 8
what is your scope of responsibilities? 9
A. I am the Manager of Electric Engineering Services. In that capacity, I am 10
responsible for the engineering planning and designs for Central Hudson’s 11
electric transmission systems and for the planning and engineering 12
operations of Central Hudson’s electric distribution systems. 13
Q. Mr. Turner, what is your educational background and professional 14
experience? 15
A. I graduated from Rensselaer Polytechnic Institute in 1988 with a Bachelor 16
of Science in Electrical Engineering. In 1992, I received a Master of 17
Engineering in Electrical Power Engineering from Rensselaer Polytechnic 18
Institute. I am currently a registered Professional Engineer in New York 19
State. I joined Central Hudson in 1988 as a Junior Engineer in the Electric 20
System Protection Section within our Electric Engineering Services Group. 21
Since that time, I have held various technical and supervisory positions 22
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
4
within both our Electric Engineering Services and Operations Services 1
Groups. In the Electric Engineering Services Group, I had responsibility 2
for the engineering, planning and designs for Central Hudson’s electric 3
transmission systems and for the planning and engineering operations of 4
Central Hudson’s distribution systems. In the Operations Services Group, 5
I had responsibility for the operation, maintenance, and construction of the 6
Company’s substation facilities. In 2013, I was transferred to my current 7
position of Manager – Electric Engineering Services. 8
Q. Mr. Turner, have you previously testified before the Commission? 9
A. Yes, I testified before the Commission in Cases 14-E-0318 10
and 14-G-0319. 11
Q. Mr. Dittmann, please state your current employer and business address. 12
A. I am employed by Central Hudson and my business address is 284 South 13
Avenue, Poughkeepsie, New York 12601. 14
Q. Mr. Dittmann, in what capacity are you employed by Central Hudson and 15
what is your scope of responsibilities? 16
A. I am the Manager of Transmission Operations and Reliability Compliance 17
with Central Hudson. In that capacity, I am responsible for Gas and 18
Electric Transmission Operations, NERC Reliability Standards 19
Compliance, including acting as the Critical Infrastructure Protection 20
(“CIP”) Senior Manager, and Operational Technology systems, including 21
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
5
the Energy Management System, Distribution Management System and 1
the Company’s internal communication network. 2
Q. Mr. Dittmann, what is your educational background and professional 3
experience? 4
A. I received a Bachelor of Science in Electrical Engineering from Clarkson 5
University in 1990, a Master of Engineering in Electric Power Engineering 6
from Rensselaer Polytechnic Institute in 1994 and a Master of Business 7
Administration from Rensselaer Polytechnic Institute in 2007. I have a 8
prior registration as a Professional Engineer in New York State (currently 9
inactive). Over the last 27 years, I have been an engineering and 10
management employee of Central Hudson. Prior to my current position, I 11
was Manager of Electric Engineering at Central Hudson. I joined Central 12
Hudson in 1990 as a Junior Engineer and had been promoted to several 13
positions within the utility, including Section Engineer – Electric System 14
Design and Manager of Customer Services. 15
Q. Mr. Dittmann, have you previously testified before the Commission? 16
A. No, I have not. 17
Q. Ms. Adams, please state your current employer and business address. 18
A. I am employed by Central Hudson and my business address is 284 South 19
Avenue, Poughkeepsie, New York 12601. 20
Case 17-E-____; Case 17-G-____
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6
Q. Ms. Adams, in what capacity are you employed by Central Hudson and 1
what is your scope of responsibilities? 2
A. I am the Director of Electric Distribution and Standards. I have served in 3
this capacity since March 2015. In addition to general supervision of 4
Electric Distribution Planning, Operations, and Construction Standards 5
Engineering, I oversee the development and engineering implementation 6
of distribution capital projects. In this role, I am also responsible for the 7
interconnection of distributed generation (“DG”). 8
Q. Ms. Adams, what is your educational background and professional 9
experience? 10
A. I graduated with a Bachelor of Science in Electrical Engineering from 11
Lehigh University and a Master of Business Administration from New York 12
University’s Stern School of Business. I am a registered Professional 13
Engineer in New York State. Following a summer internship, I joined 14
Central Hudson in 2003 as a Junior Engineer in the Electric System 15
Protection Section. In 2004, I was promoted to Assistant Engineer. 16
In 2006, I was transferred to the Electric Distribution Planning Section, 17
where I held positions of increasing responsibility. Most recently, these 18
included Engineer – Section Leader, Electric Distribution Planning in 2010, 19
Associate Director, Electric Distribution and Standards in 2013, and 20
Director, Electric Distribution and Standards in 2015. 21
Case 17-E-____; Case 17-G-____
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Q. Ms. Adams, have you previously testified before the Commission? 1
A. No, I have not. 2
Q. Mr. Borchert, please state your current employer and business address. 3
A. I am employed by Central Hudson and my business address is 284 South 4
Avenue, Poughkeepsie, New York 12601. 5
Q. Mr. Borchert, in what capacity are you employed by Central Hudson and 6
what is your scope of responsibilities? 7
A. I am Senior Director of Energy Policy and Transmission Development with 8
Central Hudson. In my current position, I monitor and provide strategic 9
input in the technical aspects of state and federal regulatory energy policy. 10
I serve as Central Hudson’s representative on various New York 11
Independent System Operator (“NYISO”) Committees, as well as the New 12
York State Transmission Owners Technical Committee. I represent 13
Central Hudson in the development and formation of the NY Transco, a 14
public-private partnership of the NY Transmission Owners to jointly 15
develop and own transmission facilities in New York. 16
Q. Mr. Borchert, what is your educational background and professional 17
experience? 18
A. I received a Bachelor of Engineering in Electric Engineering from SUNY 19
Maritime College in 1985, and a Master of Science degree in Electric 20
Engineering from Polytechnic University in 1992. I am a registered 21
Professional Engineer in the State of New York. Over the last 32 years, I 22
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
8
have been an engineering and management employee of Central Hudson. 1
Prior to my current position, I was Manager of Electric Engineering at 2
Central Hudson. I joined Central Hudson in 1985 as a Junior Engineer 3
and had been promoted to several positions within the Company, 4
including Power Quality Services Engineer, Supervisor of New Business, 5
Manager of Customer Services, and Manager of Gas & 6
Mechanical Engineering. 7
Q. Mr. Borchert, have you previously testified before the Commission? 8
A. Yes. I have testified most recently in Cases 05-E-0934, 05-G-0935, 9
08-E-0887, and 08-G-0888. 10
Q. Mr. Hayes, please state your current employer and business address. 11
A. I am employed by Central Hudson and my business address is 284 South 12
Avenue, Poughkeepsie, New York 12601. 13
Q. Mr. Hayes, in what capacity are you employed by Central Hudson and 14
what is your scope of responsibilities? 15
A. I am the Manager of T&D Operations Services and Emergency Response 16
with Central Hudson. In my current position I am responsible for Gas and 17
Electric Distribution Dispatch Operations, Emergency Management, and 18
several of the software applications that are used in those operations, 19
including the Outage Management System and the Mobile Workforce 20
Management application. 21
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
9
Q. Mr. Hayes, what is your educational background and professional 1
experience? 2
A. I received a Bachelor of Science in Industrial Distribution from Clarkson 3
University in 1988 and a Master of Business Administration from Union 4
College in 1993. Over the last 29 years, I have been an engineering and 5
management employee of Central Hudson. Prior to my current position, I 6
was the Section Engineer in Gas Standards and Engineering at Central 7
Hudson. I joined Central Hudson in 1988 as a Junior Engineer and had 8
been promoted to several positions within the Company, including 9
Operating Supervisor in four of Central Hudson’s five geographic districts. 10
Q. Mr. Hayes, have you previously testified before the Commission? 11
A. No, I have not. 12
II. PURPOSE OF TESTIMONY 13
Q. What is the purpose of this Panel’s testimony in these proceedings? 14
A. Our testimony describes the Company’s proactive efforts to address 15
changes required to implement the Distributed System Platform (“DSP”). 16
We will first address system planning and Distributed Energy Resources 17
(“DER”) interconnection enhancements. Next, the Panel addresses the 18
need to establish a centralized Distribution System Operations 19
organization. We describe ongoing collaborative efforts that the Company 20
is participating in with the other New York State electric utilities and 21
stakeholders in developing the future state of the DSP. We also discuss 22
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
10
how recovery for the Company’s Non-Wire Alternative projects should be 1
handled in the future, introduce new Non-Pipes Alternative projects, 2
provide details on the Company’s proposed battery storage projects being 3
implemented pursuant to the Commission’s Order on Distributed System 4
Implementation Plan Filings (“Updated DSIP Order”) in Case 14-M-0101,1 5
as well as a proposed demonstration project specifically related to 6
Granular Real Time pricing. As we discuss each topic, we will also 7
describe the incremental staffing needs associated with each initiative, as 8
summarized in the exhibits of Company Witness McGinnis. 9
Q. Are you sponsoring any exhibits in support of your testimony? 10
A. No. 11
III. SYSTEM PLANNING / DER INTERCONNECTION ENHANCEMENTS 12
Q. Please provide an overview of your testimony related to System 13
Planning/DER Interconnection Enhancements. 14
A. In regard to System Planning/DER Interconnection Enhancements, the 15
purpose of our testimony is to describe the requirements necessary to 16
further develop our planning methods and techniques to permit us to 17
effectively plan, forecast, and integrate higher penetration of DERs into 18
Central Hudson’s system. This section is focused on five areas: 19
1) Probabilistic Planning; 2) DER Forecasting; 3) Hosting Capacity; 4) the 20
1 Case 14-M-0101 - Proceeding on Motion of the Commission in Regard to Reforming the
Energy Vision and Case 16-M-0411 – In the Matter of Distributed System Implementation Plans, Order on Distributed System Implementation Plan Filings (March 9, 2017)
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
11
Interconnection Online Application Portal (“IOAP”); and 5) Interconnection 1
Process Enhancements. 2
Q. Has Central Hudson previously made filings with the Commission 3
associated with these five areas? 4
A. Yes, the Commission issued its Order Adopting Distribution System 5
Implementation Plan Guidance on April 20, 2016 in Case 14-M-0101. As 6
a result, the Company filed its Initial Distributed System Implementation 7
Plan (“Initial DSIP”) on June 30, 2016. The Company’s Initial DSIP filing 8
provided our inaugural approach to developing probabilistic planning 9
methodologies at the Transmission Area and Substation level, our initial 10
efforts to forecast DER by DER type at a more granular (substation) level, 11
an initial framework and supporting whitepaper defining our Hosting 12
Capacity analysis roadmap, and the status of our IOAP and 13
interconnection process improvements. Together with the Joint Utilities,2 14
the Company filed the Supplemental Distributed System Implementation 15
Plan (“Supplemental DSIP”) on November 1, 2016 in Case 16-M-0411. 16
This filing provided further details on the roadmaps associated with 17
each topic. 18
2 The Joint Utilities include Central Hudson, Consolidated Edison Company of New York, Inc.
(Con Edison), New York State Electric & Gas Corporation, Niagara Mohawk Power Corporation d/b/a National Grid, Orange and Rockland Utilities, Inc. (O&R), and Rochester Gas and Electric Corporation.
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
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Q. Has Central Hudson sought deferral authority and cost recovery 1
associated with any of these items to date? 2
A. Yes, on March 7, 2017, Central Hudson filed its Petition Seeking New 3
York State Public Service Commission’s Approval for Deferral Accounting 4
Authority and Recovery of Incremental Costs Associated with Reforming 5
the Energy Vision3 (“Cost Recovery Petition”). Specific to the Panel’s 6
discussion of these initiatives, Central Hudson sought deferral authority for 7
the costs associated with hosting capacity analysis and Phases 1 and 2 of 8
the IOAP, as well as on-going Initial and Supplemental DSIP and 9
Interconnection Earnings Adjustment Mechanism costs. The Commission 10
approved the recovery of previously incurred costs and authorized the 11
continued deferral of costs related to the hosting capacity analysis and 12
IOAP through its July 13, 2017 Order. 13
Q. Are there any other costs related to the DSP for which the Company is 14
requesting deferral authority? 15
A. Yes. As we will discuss throughout our testimony, there are a number of 16
unknowns associated with the implementation of the DSP. In Section V of 17
our testimony, we summarize the DSP implementation expenses for which 18
we are requesting full deferral. 19
3 Case 17-E-0113 – Petition Seeking New York State Public Service Commission’s Approval
for Deferral Accounting Authority and Recovery of Incremental Costs Associated with Reforming the Energy Vision (Mar. 7, 2017).
Case 17-E-____; Case 17-G-____
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Q. Can you provide background on Central Hudson’s initial approach to 1
developing probabilistic planning methodologies at the Transmission Area 2
and Substation level? 3
A. As part of its Initial DSIP filing, Central Hudson engaged with our 4
consultant, Nexant, to develop a probabilistic load forecasting 5
methodology for granular transmission areas and substations. A study 6
was undertaken to develop a system-wide avoided cost value for 7
transmission and substation reinforcements identified using the 8
probabilistic forecast. The study focused on substation and transmission 9
area forecasting (it does not include circuit feeders) and was designed to 10
meet the following objectives: 11
Analyze load patterns, excess capacity, load growth rates, and 12
the magnitude of expected infrastructure investments at a 13
local level; 14
Develop location specific forecasts of growth with probabilistic 15
bands of growth trajectories taking into account 16
forecast uncertainty; 17
Quantify the probability of any need for infrastructure upgrades 18
at specific locations; 19
Calculate local avoided T&D costs by year and location using 20
probabilistic methods; and 21
Identify beneficial locations for DERs. 22
Case 17-E-____; Case 17-G-____
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Q. Can you provide a brief description of the study methodology? 1
A. Forecasts inherently include uncertainty, with the degree of uncertainty 2
increasing for forecast years further into the future. In practice, actual 3
growth trajectories rarely are linear and growth patterns relate to each 4
other across time and location. Probabilistic distribution forecasting 5
requires estimating historical load growth patterns and variability and 6
simulating load growth trajectories. The process we used produced 7
several thousand potential trajectories for each location, each of which 8
reflects the non-linear nature of growth and has its own path. However, 9
some outcomes are far more likely than others. These are summarized 10
into probabilistic bands that identify the likelihood of load growth falling 11
within specific confidence bands. 12
Q. At what level of detail were the probabilistic growth projections developed? 13
A. Forecasts for 10 distinct transmission areas and 54 of 69 distribution load 14
serving substations, where detailed metering data was available, were 15
developed. 16
Q. Why were forecasts not completed for all distribution load 17
serving substations? 18
A. Some substations either lacked data or had lower quality data and, as a 19
result, we were unable to estimate location specific forecasts for all 20
substations. Substations with lower quality data include those substations 21
with older chart style metering or those with single peak readings. The 22
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
15
substations lacking hourly data are generally smaller stations serving 1
relatively few customers. The portion of the system where detailed hourly 2
data was available accounted for 89.5% of Central Hudson's 2016 peak. 3
Central Hudson continues to improve its metering capability as part of 4
ongoing infrastructure investments and, as of the submission date of this 5
testimony, the Company has hourly metering at an additional four 6
substations accounting for 91.8% of the 2016 system peak. The Capital 7
forecast supported by Company Witness Haering includes project plans to 8
add hourly metering to additional substations over the next five years, 9
accounting for 98.7% of the cumulative system load data by 2021. These 10
metering upgrades will increase the accuracy of future avoided 11
transmission and distribution cost studies. 12
Q. Please describe the probabilistic forecasting process. 13
A. The forecasting process can be described in four main steps. 14
1. Clean the data. Poor data quality for some substations due to 15
load transfers, outages, data gaps, and data recording errors 16
has historically been a barrier to utilizing substation data for load 17
forecasting. This step required extensive use of data analytics 18
to identify and remove these load transfers, outages, data gaps, 19
and data recording errors. Load transfers were of particular 20
importance since they can be confused with load decreases 21
or growth. 22
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
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2. Estimate historical load growth trends and noise. The objective 1
of this step was to estimate historical load growth for each year 2
from 2010–2015 in terms of percentage growth. The year-to-3
year growth patterns were then used to assess the growth trend 4
and the variability of load growth patterns; the degree of growth 5
in a given year was related to growth during the prior year—6
technically known as auto-correlation. The econometric models 7
were purposefully designed to both estimate historical load 8
growth and allow us to weather-normalize loads for 1-in-2 9
weather peaking conditions. 10
3. Weather adjust loads for 1-in-2 and 1-in-10 conditions. Based 11
on historical patterns, the 2013 and 2010 year load data, 12
respectively, reflect the 1-in-2 and 1-in-10 weather conditions. 13
Econometric models were used to weather normalize the loads 14
and remove the inherent variation of weather across years. 15
4. Simulate potential load growth trajectories. The load growth 16
forecasts were developed using probabilistic methods—Monte 17
Carlo simulations—that produced the range of possible load 18
growth outcomes by year. This method simulates the reality 19
that the near term forecast has less uncertainty than forecasts 20
10 years out. A total of 10,000 simulations were implemented 21
for each transmission area and 2,000 simulations were 22
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
17
implemented for each load area and substation. Each 1
simulation produced a distinct growth trajectory that took into 2
account the historical trend, variability in growth patterns, 3
and the fact that growth patterns are auto-correlated. 4
The result was a full picture of the possible growth outcomes by 5
year and location. 6
Q. Can you provide background on the more traditional local transmission 7
and substation planning criteria currently used? 8
A. The local transmission system, as well as urban substations, are generally 9
developed with n-1 contingency planning. For local transmission 10
networks, the load serving capabilities (“LSC”) are developed by 11
evaluating the maximum load level at which the load can be served 12
reliably without violating thermal or voltage limits while at the same time 13
considering contingencies. 14
For basic transmission loops with only two feeds and for urban 15
substations (those containing greater than one transformer with a lowside 16
bus tie breaker), the LSC is determined based on the long-term 17
emergency rating with the highest rated transmission line or substation 18
transformer removed (unless limited by another breaker, switch, fuse, 19
cable/conductor, bus, other component, or voltage) or design rating. For 20
rural substations (those that contain a single transformer or multiple 21
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
18
transformers with no lowside bus tie), the summer normal rating of the 1
transformer or other limiting element (i.e., buswork) is applied. 2
Q. At what level of detail are growth estimates currently developed? 3
A. Central Hudson produces growth estimates for each of the 10 distinct load 4
areas and applies those growth estimates to each individual substation 5
within the load area. The growth rates are customized to these areas, but 6
are not unique to each individual substation. This approach was adopted 7
due to challenges in the data quality of substation level data as previously 8
described. Not all substations had hourly data and many of those that did 9
included outages, data gaps, and both permanent and temporary or 10
seasonal load transfers between substations. Unless identified and 11
removed, load transfers can be confused with growth or decay in local 12
peak loads. Because most load transfers occur between substations in a 13
specific load area, load areas provided a stable unit of analysis for 14
developing forecasts. 15
Q. Do forecast loads in excess of the LSC or design ratings automatically 16
trigger an infrastructure upgrade? 17
A. The forecast load is allowed to exceed the LSC without triggering an 18
infrastructure upgrade, with the understanding of the low probability of a 19
contingency occurring during peak loading. 20
Central Hudson has specified explicit risk tolerances, based on the 21
total hours that forecast load can exceed design ratings, which 22
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
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vary by category and are summarized in Table 1 below. More risk is 1
tolerated for less critical components of the system. 2
Table 1: Risk Tolerances 3
Category Risk Tolerance
Transmission Network 2% of seasonal capability period (88 hours) Transmission Loop 6% of seasonal capability period (263 hours) Urban Substation 6% of seasonal capability period (263 hours) Rural Substation 8% of seasonal capability period (350 hours) or 7 MVA unreserved
Q. Do you envision modifying the risk criteria described above? 4
A. As penetration of DERs increases to the point of significantly changing a 5
load curve at a substation, risk criteria may need to be reevaluated, 6
particularly in the case of intermittent resources. 7
Q. Does Central Hudson plan on utilizing its traditional planning 8
methodologies or transitioning to a more probabilistic methodology in 9
the future? 10
A. Central Hudson plans on utilizing both our traditional planning 11
methodologies and the more probabilistic approach in the future. The 12
recent Avoided T & D Cost Study was Central Hudson’s first study based 13
on probabilistic methodologies with the results of this study addressing a 14
number of requirements outlined in the Order Adopting Distributed System 15
Implementation Plan Guidance (“DSIP Guidance Order”), issued on 16
April 20, 2016 in Case 14-M-0101. In addition, since the probabilistic 17
approach we utilized identified a system-wide value based on probabilistic 18
forecasts developed at a granular level, we believe it represented a 19
superior approach to determining system wide value, although it is likely 20
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
20
that our investment-triggering criteria utilized for the system-wide value will 1
need to be refined over time. This study and the associated analysis can 2
both serve the aforementioned purpose of developing forecasts at 3
granular levels. 4
Q. Does Central Hudson plan on modifying its probabilistic methodologies in 5
the future? 6
A. Central Hudson plans on continuing to develop and improve our use of 7
probabilistic methodologies. In addition, the overall risk profile utilized 8
within the system wide study was significantly more conservative than our 9
traditional approach and will require refinement as we gain experience. 10
Q. Is Central Hudson planning on completing a similar study in the future? 11
A. Yes, Central Hudson plans on completing this type of study every two 12
years. The timing of the study will correspond with the update of our BCA 13
handbook and filing of future DSIPs. 14
Q. Are there specific resource requirements necessary to complete this study 15
work and further develop probabilistic planning methodologies? 16
A. As indicated, Central Hudson engaged a consultant, Nexant, to complete 17
this initial study. The initiative included compiling the historic load data, 18
assisting with the data cleansing efforts and providing information for 19
traditional reinforcement projects and associated cost estimates. Central 20
Hudson sees significant value in refining and completing similar Avoided 21
T & D Costs Studies on an ongoing basis and further incorporating 22
Case 17-E-____; Case 17-G-____
DIRECT TESTIMONY OF THE DISTRIBUTED SYSTEM PLATFORM PANEL
21
probabilistic methodologies into our planning processes. This type of 1
analyses will become core to our planning functions in the future. The 2
Company feels there are significant benefits to developing the internal 3
capabilities necessary to complete these probabilistic analyses in the 4
future versus contracting out the work. The necessary incremental 5
resources for this work effort were identified within our Initial DSIP. Two 6
Junior Engineers are required to complete probabilistic planning: one in 7
Electric Distribution Planning and another in Electric Transmission 8
Planning. These resources, as summarized in the exhibits of Company 9
Witness McGinnis, will also be required to complete the DER forecasting, 10
described later in this section. As probabilistic planning becomes a core 11
Company function and the Company develops the necessary skills and 12
tool sets to perform probabilistic planning analyses, this type of work will 13
be completed in-house as part of our normal planning processes. 14
Q. Has DER forecasting been identified within System Planning as an area 15
requiring further development? 16
A. Yes. 17
Q. Can you provide some background on Central Hudson’s current approach 18
to DER forecasting? 19
A. Within its electric system peak demand forecast, Central Hudson 20
historically has accounted for adjustments due to energy efficiency (“EE”) 21
and DERs, specifically net-metered customer-sited photovoltaic (“PV”) 22
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units. Once the base projections are developed, adjustments for EE and 1
PV are applied to yield net projections. Since the impacts of all EE and 2
PV are embedded in the historical demand data, the demand projections 3
must be reduced by an estimate of the incremental impacts of future EE 4
and PV. 5
Q. Has Central Hudson performed any DER forecasting at a more granular 6
level than its current approach to DER forecasting? 7
A. As part of our Initial DSIP filing, Central Hudson engaged with Nexant to 8
produce DER penetration forecasts for EE end uses, PV, and electric 9
vehicles (“EV”). Demand Response (“DR”) was not forecasted, as it is 10
fully managed by Central Hudson. Battery storage was not included due 11
to lack of data; no public data source was available on either historical or 12
forecast penetration of behind-the-meter batteries or customer adoption 13
rates. Although the details of each analysis differed for each DER, the 14
methodology was guided by common principles and was broadly similar 15
across DERs. Where possible, existing forecasts were used to estimate 16
future annual penetration; otherwise, historical trends were analyzed and 17
extrapolated. If historical locational data on the distribution of a DER was 18
available, those distributions were used for forecast years, and if no such 19
data was available, billing data was used to distribute penetration 20
according to the population’s annual usage. Finally, where forecasts were 21
only available in annual MWh, penetration in each hour was estimated 22
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based on end use specific load shapes, or demand, allocated to each of 1
the 8,760 hours in a year on a percentage basis – a normalized load 2
shape. Multiplying the load shapes on a percentage basis with annual 3
MWh values ultimately yielded forecasts in kW on an hourly, weather 4
adjusted basis for each forecast year. 5
Q. Earlier in your testimony the Panel discussed the Company’s probabilistic 6
approach to demand forecasting. Were the DER forecasting 7
methodologies probabilistic? 8
A. As described above, the DER forecasts were not probabilistic. Instead, 9
explicit goals were reflected for EE while interconnection queue activity 10
was utilized to forecast solar PV. The EV forecast was based on existing 11
vendor pre-order data. 12
Q. Are there recommended improvements to your DER forecasting 13
methodologies going forward? 14
A. As indicated, Central Hudson is transitioning its Distribution System 15
Planning process to incorporate probabilistic and more granular elements. 16
The DER forecasts were not fully integrated into the system peak forecast. 17
Future iterations will need to focus on coordinating the integration of DER 18
forecasts into location specific and system peak forecasts. Additional 19
refinements will also be needed to transition DER forecasts to a 20
probabilistic forecast of intermittent resources. DERs have risk associated 21
with performance (especially intermittent resources), which can be 22
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exacerbated by increasing adoption rates. In order for the DSP to be able 1
to effectively rely on and fully leverage these resources, enhanced 2
monitoring, control, and visibility will be critical. With the increased 3
intermittency associated with many DERs, application of a linear forecast, 4
along with Engineering knowledge and judgment, may be insufficient to 5
recognize the range of potential generation and load scenarios. While in 6
the past a net load forecast was sufficient for planning, the forecast going 7
forward must be separated into a DER forecast and base load. DER 8
forecasts should consider not only technical drivers of load shapes, but 9
also current and anticipated policy decisions and interconnection queues 10
that will impact the penetration of DERs. 11
Q. Are there other challenges specific to DER forecasting? 12
A. Yes. The incorporation of DER into location specific forecasts is a 13
challenging issue. Ignoring DER adoption in location-specific forecasts 14
may not reflect the reality that customers are installing solar PV, 15
purchasing EVs, and adopting EE on their own. However, incorporating 16
DERs that have not yet been built or installed into a forecast can dilute 17
any locational value signals and potentially slow down DER adoption. A 18
prerequisite for more improved forecasting approaches is accurate 19
tracking of DERs and dispatch events so that both the gross and net 20
(gross minus load shaping DERs) loads can be estimated. Many types of 21
DERs—e.g., naturally occurring EE and EVs—are not administered by a 22
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utility and do not require an interconnection. Another consideration is 1
forecast uncertainty. Forecasting DERs early in the adoption process 2
such as battery storage and EVs is highly uncertain and, at the same time, 3
difficult to quantify. 4
Q. With this in mind, do you envision specific multiple use cases for DER 5
forecasts? 6
A. Yes, we envision multiple use cases for DER forecasts. One likely use 7
case is to reflect a system peak demand forecast which accounts for 8
adjustments due to EE and DERs; specifically, net-metered customer-9
sited PV to yield net projections and an associated forecast with the 10
demand projections reduced by an estimate of the incremental impacts of 11
future DER. In addition, we foresee more granular/location-specific use 12
cases. These use cases potentially would be utilized in conjunction with 13
probabilistic demand forecasting methodologies to determine system and 14
locational values. In addition, there may be forecasts utilized to determine 15
locational growth scenarios with embedded naturally occurring DER (i.e., 16
customer adopted EE and EV) as input into the planning process to 17
perform more traditional needs assessments. 18
Q. Are there specific forecasting, skill, and resource improvements necessary 19
to perform DER forecasts in the future? 20
A. As discussed above, to better plan for and effectively value and 21
accommodate increased levels of different types of DERs onto our 22
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system, advances in DER forecasting will be required. The development 1
of additional skill sets and knowledge bases will be required both in the 2
Transmission and Distribution Planning Areas to complete this work. 3
Q. Are there additional tasks associated with the proliferation of DERs that 4
will require the addition of resources within the Electric Transmission and 5
Distribution Planning Areas? 6
A. Yes, the Company’s existing planning methodologies will need to be 7
augmented to account for both the increased penetration of DERs and the 8
intermittency associated with some of these technologies. The DERs 9
interconnected on both the underlying distribution system and those 10
interconnected directly to the transmission system will require 11
modifications to our planning methodologies. The use of probabilistic 12
DER planning approaches will need to be investigated. This will require 13
the development of new skill sets and completion of tasks not currently 14
performed. As identified within our Initial DSIP, in order to more 15
accurately forecast and ultimately accommodate higher penetrations of 16
DERs onto Central Hudson’s system, DER forecasting requires 17
incremental work. The two Junior Engineers identified earlier in this 18
section to support probabilistic planning will also support DER forecasting. 19
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Q. Will new models or software be required to complete this work? 1
A. Specialized forecasting programs with the ability to specifically handle 2
differing DER technologies and to address varying DER penetration rates, 3
intermittency and other variables may be required. 4
Q. Moving on to the topic of Hosting Capacity, please summarize the 5
Company’s efforts to date regarding Hosting Capacity analysis. 6
A. To support each utility’s Initial DSIP, the Joint Utilities worked together 7
with the Electric Power Research Institute (“EPRI”) to 1) develop a 8
whitepaper that supported the use of the EPRI Streamlined Hosting 9
Capacity methodology; 2) identify utility data gaps; and 3) provide an 10
implementation roadmap.4 The Joint Utilities then completed a 11
stakeholder engagement series consisting of six meetings to gather 12
feedback on its proposal and provide additional details and timelines. The 13
results of this discussion are detailed in the Supplemental DSIP. The 14
parties to the stakeholder engagement sessions agreed that the EPRI 15
streamlined approach for large centralized solar PV would be utilized for 16
analysis. A four stage roadmap was also developed: 17
1. Stage 1 – Distribution Indicators (2016 – Early 2017): identifies 18
where interconnection costs may be higher 19
4 Electric Power Research Institute, Defining a Roadmap for Successful Implementation of a
Hosting Capacity Method for New York State, Report No. 3002008848 (June 2016) (“EPRI Roadmap”).
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