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NET METERING POLICY AND THE
ROLE OF VALUE OF SOLAR STUDIES
&
NY BENEFIT COST ANALYSIS
HANDBOOK
APRIL 13, 2018
INNOVATION ADVISORY
COMMITTEE SUPPORT
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TABLE OF CONTENTS
SECTION 1.0: NET METERING POLICY AND THE ROLE OF VALUE
OF SOLAR STUDIES
SECTION 1.1: Net Metering Policy
SECTION 1.2: Value of Solar Framework
SECTION 1.3: Meta Analysis of Value of Solar Studies
SECTION 2.0: NY BENEFIT COST ANALYSIS HANDBOOK
SECTION 2.1: NY Handbook History
SECTION 2.2: Methodology
SECTION 2.3: Cost Effectiveness Tests
SECTION 2.4: Distributed Energy Resources
SECTION 2.5: Benefit Parameter Example
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INTRODUCTION
• Navigant was engaged by the Ontario Energy Board to support the Innovation
Advisory Committee with discreet research tasks
• To date, three research tasks have been identified:
1. Net Metering Policy and the Role of Value of Solar Studies: This section provides an
overview of net metering policy in the US, a framework for valuing solar, and a meta
analysis on the value of solar studies.
2. NY Benefit Cost Analysis Handbook: This section provides a history of the NY Benefit Cost
Analysis Handbook, a summary of key methodological issues, a discussion of the
characterization of DERs in the Handbook, and a benefit parameters example for solar.
3. Sector Disruption Case Studies: Three sectors that have experienced or are experiencing
disruption and how those sectors have addressed, managed, and adapted to the change
• This slide deck includes findings from Task #1 and #2 outlined above
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1.0
NET METERING
POLICY AND THE
ROLE OF VALUE
OF SOLAR
STUDIES
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1. VALUE OF SOLAR AND NET METERING POLICY
INTRODUCTION
• This section provides a discussion of net metering policy, and an overview of the
value of solar study frameworks
• This section is sub-divided into the following sub-sections:
- 1.1 Net Metering Policy: Overview of net metering, how stakeholders are changing their
perceptions of it, US State policies, and rate reform. This section also highlights three case
studies to illustrate the evolution of net metering policy from the past, present, and future
- 1.2 Value of Solar Framework: Overview of the various viewpoints from which solar is
valued from. Also provides the benefit and cost categories for solar valuation
- 1.3 Meta Analysis of Value of Solar Studies: Provides an overview of solar studies to date
across the US, including the variations among studies, and range in type and magnitude of
costs and benefits
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1.1 NET METERING POLICY
WHAT IS NET ENERGY METERING?
Net Energy Metering (NEM) enables a customer with distributed renewable generation to sell
excess electricity back to the utility at the same rate at which the customer purchases
electricity from the grid when the solar PV system is not producing enough electricity to meet
demand.
• Policy related to net metering has varied by jurisdiction, and is evolving with over time
Source: “Learn About Net Metering.” Pacific Gas & Electric Company.
Net Metering Electricity Flows
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1.1 NET METERING POLICY
WHAT’S CHANGING?
Net Metering (NEM) policies have contributed to the rapid growth of the distributed
solar industry in the US, however, with higher levels of market penetration, debates are
taking place in many states regarding “fair” compensation.
• Various stakeholders are raising concerns regarding NEM including cost shifting, low penetration, and
price signals
Utilities
Raised concerns about cost shifting to non-solar customers and utility shareholder profitability.
Solar Advocates
Point to studies showing at low penetrations and under certain assumptions, the marginal value of solar can be calculated as exceeding the retail rate in some areas.
Other Stakeholders
Describe NEM as an instrument that sends inaccurate price signals to the demand side of the market.
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1.1 NET METERING POLICY
NET ENERGY METERING STATE POLICIES
State-developed mandatory rules for certain utilities (38 states + DC+ 3 territories)
No statewide mandatory rules, but some utilities allow net metering (2 states)
KEY
38 States + DC,AS, USVI, & PR
have mandatory
Net Metering
rules
DC
Statewide distributed generation compensation rules other than net metering (7 states + 1 territory) (Source: www.dsireusa.org, April, 2018)
GU
AS PR
VI
U.S. Territories
Most states have some form of NEM policy.
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1.1 NET METERING POLICY
TOP NEM AND RATE REFORM TRENDS
Nearly every US state took some type of policy action related to distributed energy
in 2016, aligning with the following trends.
Reconsider net energy metering rates, in many cases reducing or proposing to reduce NEM rates
Consider the development of a Value of Solar (VOS) and Community Solar Credit Rate
Request to increase fixed charges and/or increase and in some case introduce demand charges
NC Clean Energy Technology Center, 50 States of Solar, January 2017, https://nccleantech.ncsu.edu/wp-
content/uploads/Q42016_ExecSummary_v.3.pdf
1
3
2
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1.1 NET METERING POLICY
NEM POLICY CHANGES & RATE REFORM
Of the 249 actions taken in 2017, the most common were related to
residential fixed charge and minimum bill increases (84), followed by net
metering (66).
NC Clean Energy Technology Center, 50 States of Solar, January 2018, https://nccleantech.ncsu.edu/wp-
content/uploads/Q4-17_SolarExecSummary_Final.pdf
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1.1 NET METERING POLICY
CASE STUDY - ARIZONA
FUTURE
Additional Changes.
This deal being passed
has given distributed
generators, especially the
solar industry, economic
clarity when building new
projects.
After years of
disagreement, Arizona
utilities and solar backers
seem to agree on this
settlement.
PAST
Policy. Under previous NEM policy,
customers were credited full retail
rate ($0.13-$0.14/kWh). Utilities and
other rate payers argued that these
rates resulted in a cost shift.
Shifts. In March 2017, Arizona
Public Service Co. and a group of
solar interests filed a settlement on
rate design and rooftop solar
compensation with the Arizona
Corporation Commission.
Arizona transitioned from a full retail rate NEM compensation to a slightly lower fixed
rate called net billing to minimize cost shifts to others
CURRENT
Policy. Under the new agreement,
called net billing, the rooftop solar
customer will be paid $0.129/kWh for
excess energy exported to the grid.
Export rate will fall 10% annually, but
customers will lock in rates for 10 years
at sign up. Solar energy consumed by
end users valued at ~$0.105/kWh, with
a lower rate for demand charge rate
options, likely in the $0.096-$0.078/kWh
range.
Shifts. New settlement includes a 20-
year grandfathering period for
customers who file for interconnection
before rate case decision.
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1.1 NET METERING POLICY
CASE STUDY – NEW YORK
FUTURE
Additional Changes. The
PSC expects to develop a
VDER Phase II
methodology and
transition plan by the end
of 2018. This
methodology will consider
rate design changes,
improvements to the
VDER compensation
model, and eligible
projects.
PAST
Policy. Enacted in 1997, NEM
originally only applied to PV
systems but later expanded to other
distributed generation.
Shifts. In December 2016, New
York Dept. of Public Service (PSC)
released a report on the value of
distributed energy, indicating
existing solar projects
interconnected by March 2017
should receive the full retail rate
NEM credit for 20 years.
New York is continuing its transition from full retail rate NEM compensation to Value
of DER (VDER) tariffs to more accurately reflect the costs/benefits of DERs.
CURRENT
Policy. In March 2017, the PSC ordered
a transition from NEM to Value of DER
(VDER) tariffs to more accurately reflect
the costs and benefits of DERs on the
grid.
Shifts. DER projects interconnected
before March 9, 2017 will be
grandfathered in and continue to be
compensated by NEM. Others will be
compensated by VDER tariffs with a
term limit of 25 years.
In May 2017, the utilities submitted
implementation and calculation
proposals for these new tariffs.
*LMP (locational marginal price) represents wholesale market value and D represents all
other values, including distribution system benefits and environmental externalities.
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1.1 NET METERING POLICY
CASE STUDY – CALIFORNIA
FUTURE
Additional Changes.
Policymakers and key
stakeholders continue to
discuss the NEM 3.0
program. A key focus of
this program will be
incorporating the
locational and temporal
benefits of solar.
PAST
Policy. Original NEM applied to
customers who installed distributed
solar, wind, biogas, and fuel cell
generating assets. Customers
received the full retail rate.
Shifts. Discussions around fair
compensation arose and in January
2016, the California Public Utilities
Commission issued the NEM 2.0
decision. This decision required to
offer NEM until utility reaches NEM
cap (exceeds 5% of its aggregate
customer peak demand) or July 1,
2017, whichever is first.
California transitioned from a full retail rates for NEM to NEM 2.0, which adds
additional fees for solar customers but maintains a full retail rate compensation
CURRENT
Policy. NEM 2.0 upheld retail rate bill
credits through 2019 but requires solar
owners to switch to TOU rates, pay a
system interconnection fee, and pay a
non-bypassable charge ($0.02-
0.03/kWh) for utility delivered electricity.
NEM 2.0 grandfathers customers under
NEM or NEM 2.0 for 20 years from
interconnection date.
Shifts. NEM 2.0 extends through 2019.
In 2019, the CPUC will implement a new
NEM program, or NEM 3.0.
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1.1 NET METERING POLICY
CASE STUDY SOURCES
14
General Policy
• DSIRE, http://www.dsireusa.org/
Arizona
• Krysti Shallenberger, Arizona Public Service, solar industry reach critical rate case settlement, March 2017,
http://www.utilitydive.com/news/arizona-public-service-solar-industry-reach-critical-rate-case-settlement/437186/
New York
• Shayle Kann, How to Find Compromise on Net Metering, April 2016, https://www.greentechmedia.com/articles/read/how-to-find-compromise-on-
net-metering
• Katherine Tweed, New York Resets Distributed Energy rates, maintains Residential Net Metering, October 2016,
https://www.greentechmedia.com/articles/read/new-york-resets-distributed-energy-rates-maintains-residential-net-metering
• Energy and Environmental Economic, Inc., Nevada Net Energy Metering Impacts Evaluation, July2014,
http://puc.nv.gov/uploadedFiles/pucnvgov/Content/About/Media_Outreach/Announcements/Announcements/E3%20PUCN%20NEM%20Report%2
02014.pdf
• Latham Watkins, New York is transitioning Away from Net Energy Metering for Distributed Resources, May 2017,
https://www.lw.com/thoughtLeadership/new-york-transitioning-away-net-energy-metering-distribution-resources
California
• Breaking: California’s NEM 2.0 Decision Keeps Retail Rate for Rooftop Solar, add Time-of-Use
https://www.greentechmedia.com/articles/read/Californias-Net-Metering-2.0-Decision-Rooftop-Solar-to-Keep-Retail-Payme
• Net Metering 2.0 in California: Everything You Need to Know, http://news.energysage.com/net-metering-2-0-in-california-everything-you-need-to-
know/
• California Public Utilities Commission, Net Energy Metering, http://www.cpuc.ca.gov/General.aspx?id=3800
• PV Tech, Recognizing solar’s value key to NEM 3.0, says interim SEIA chief, https://www.pv-tech.org/news/recognising-solars-value-key-to-nem-
3.0
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1.2 VALUE OF SOLAR FRAMEWORK
THE VALUE OF SOLAR DEPENDS ON THE PERSPECTIVE
Value of solar (VOS) analyses focus on developing assessments for the costs and benefits of distributed
behind the meter net energy metering (NEM) resources such as solar photovoltaics (PV). Depending on the
jurisdiction, studies are conducted from multiple viewpoints (i.e., cost tests) as described below:
Cost Test Description
Utility Cost Test (UCT)The UCT is also known as the Program Administrator Cost Test (PACT). It looks to
answer: Is the solar or other distributed generation program cost-effective for the
utility?
Ratepayer Impact Measure (RIM) What is cost impact of the solar program on non-participating utility customers?
Participant Cost Test (PCT) How cost-effective is the solar for customers who install solar as part of the program?
Total Resource Cost (TRC) TestDoes the solar program reduce the overall cost for Ontario, excluding societal values
such as health impacts and climate change effects?
Societal Cost Test (SCT)Does the solar program reduce the overall cost for Ontario, including societal values
such as health impacts and climate change effects?
Some recent VOS studies have accounted for front-of-the-meter systems and have also started to
focus on the value of distributed storage as well. Studies include various cost and benefit
categories which are mapped to the cost tests described above (example shown on next slide).
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1.2 VALUE OF SOLAR FRAMEWORK
BENEFIT-COST ANALYSIS FRAMEWORK
Cost Test (as defined in previous slide)
Value Category UCT RIM PCT TRC SCT
Avoided Energy Costs Benefit Benefit N/A Benefit Benefit
Avoided Capacity Costs Benefit Benefit N/A Benefit Benefit
Avoided Transmission and Distribution Capacity Costs Benefit Benefit N/A Benefit Benefit
Avoided System Losses Benefit Benefit N/A Benefit Benefit
Avoided Environmental Compliance Costs Benefit Benefit N/A Benefit Benefit
Avoided Environmental Externalities N/A N/A N/A N/A Benefit
Fuel Hedging / Avoided Risk Benefit Benefit N/A Benefit Benefit
Avoided Outages Costs Benefit Benefit Benefit Benefit Benefit
Non-Energy Benefits Benefit Benefit N/A Benefit Benefit
Reduced Revenue N/A Cost Benefit N/A N/A
Administrative Costs Cost Cost N/A Cost Cost
Interconnection Costs Cost Cost N/A Cost Cost
Integration Costs Cost Cost N/A Cost Cost
Grid Support Services Costs Cost Cost N/A Cost Cost
Participant Cost N/A N/A Cost Cost Cost
VOS studies use a defined set of benefit and cost categories and map these values to each cost test to
calculate cost-effectiveness from various scenarios. The following table outlines an example of this framework:
A detailed description of each value category and associated methodologies are included in the following pages.
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1.2 VALUE OF SOLAR FRAMEWORK
BENEFIT CATEGORIES
Categories Description Methodology
Avoided Energy Costs
Increase/reduction in variable costs to the utility
from market and conventional energy sources, i.e.
fuel use and power plant operations, associated
with the adoption of solar.
Value typically derived using production cost modeling software (e.g.,
PROMOD™) to compare the energy production costs in a business-
as-usual scenario to a higher solar penetration scenario.
Avoided Capacity Costs
Increase/reduction in the fixed costs to the utility of
capacity purchases from the open market or
deferred generation resources as a results of the
adoption of solar.
First, a forecast of “nameplate” solar capacity behind-the-meter (in
MW) is converted to “firm” capacity at the bulk system (in MW) using
an equivalent load carrying capability (ELCC) factor or another
capacity contribution method. Then, this forecast of “firm” capacity is
multiplied by a forecast of avoided capacity costs (in $/MW-yr) to
derive the value.
Avoided Transmission
and Distribution (T&D)
Capacity Costs
Increase/reduction of costs to the utility associated
with expanding, replacing and/or upgrading
transmission and/or distribution capacity
associated with the adoption of solar.
A simplified methodology applies the same calculation methodology as
described above in “Avoided Capacity Costs” but with a T&D-specific
capacity contribution factor and T&D-specific capacity costs.
A more rigorous method involves the determination of specific T&D
investments that could be deferred based on location-specific
forecasts of “firm” solar capacity. The T&D value can then be
calculated by estimating the deferred infrastructure costs and years of
deferral and applying an annual fixed carrying charge rate.
Avoided System Losses
Increase/reduction of electricity losses by the utility
from the points of generation to the points of
delivery associated with the adoption of solar.
Value derived using the hourly energy generated from solar and the
incremental (i.e., hourly) energy loss factors (if data is available)
between the point of the solar net meter and the point of wholesale
energy purchase. In the absence of hourly data, annual averages may
be used.
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1.2 VALUE OF SOLAR FRAMEWORK
BENEFIT CATEGORIES CONT’D
Categories Description Methodology
Avoided
Environmental
Compliance Costs
Avoided compliance costs to the utility related to the
reduction of the emissions of carbon dioxide equivalent
(CO2e), sulfur oxides (SOx), nitrogen oxides (Nox),
particulate matter (e.g., PM2.5, PM10), and other criteria
air pollutant emissions due to a reduction in production
from marginal generating resources associated with solar
energy generation.
Value is typically based on the weight of displaced emissions by
solar energy production multiplied by the value per weight of the
displaced emissions accrued to the utility.
Avoided
Environmental
Externalities
Benefits to society in terms of human health, ecological
health, and other environmental values related to
reductions in CO2e, NOx, SOx, PM, and other criteria air
pollutants.
Value is typically based on the weight of displaced emissions by
solar energy production multiplied by the societal value per weight of
the displaced emissions accrued to society. Society may be defined
on a local, provincial, national, or global level.
Fuel Hedging /
Avoided Risk
Added or avoided utility costs of locking in future fuel prices
associated with the adoption of solar.
Value is based on the monetization of the reduction in risk
associated with price volatility, project development risk, and
increases or decreases in administrative costs of a utility's current
fuel hedging program if applicable.
Avoided Outages
Costs
Reduced costs associated with avoided power
interruptions attributed to the ability of net metered systems
to operate during outages.
This benefit stream is typically monetized only when solar energy is
paired with battery storage. It is important to distinguish the benefit
accrued to customers due to the value of reduced customer minutes
of outage (CMI) and the value to the utility on restoration cost
reduction and better reliability metrics.
Non-Energy
Benefits
Benefits not associated with energy delivery, such as
increased customer satisfaction, fewer service complaints,
reduced land usage, reduced water usage, etc.
Most VOS studies conducted in recent years do not attempt to
monetize non-energy benefits and instead address them
qualitatively.
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1.2 VALUE OF SOLAR FRAMEWORK
COST CATEGORIES
Categories Description Methodology
Reduced
Revenue
Lost utility revenue (i.e., customer bill savings) associated with
reduced sales due to solar. This category is generally treated
as a transfer payment for the TRC, SCT, and UCT costs tests
and as a cost for the RIM test.
Value of the reduced customer energy and demand charges (where
applicable) due to solar based on the retail tariffs.
Administrative
Costs
Increase/reduction of costs borne by the utility to administer a
solar program.
Sum of customer service, program marketing, application fees, billing,
and other back office costs associated with the solar program.
Interconnection
Costs
Increase/reduction of costs borne by the utility to interconnect
solar. Typically, interconnection costs may be borne when a
large amount of solar is installed in areas where load density
is high or when a customer installs solar whose capacity
exceeds the rating of the transformer or service line.
Value is typically based on studies to estimate the costs to the utility
required to interconnect solar at varying adoption levels. Some VOS
studies apply an estimate of these costs based on a literature review
of interconnection studies in other jurisdictions.
Integration
Costs
Increase/reduction of costs borne by the utility to integrate
NEM. Integration costs may be defined as upgrade costs for
mitigation of primary and secondary line and transformer
overloads, system protection, and mitigation of power quality
impacts from solar.
Value is typically based on studies to estimate the costs to the utility
required to integrate solar at varying adoption levels. Some VOS
studies apply an estimate of these costs based on a literature review
of integration studies in other jurisdictions.
Grid Support
Services Costs
Added or reduced costs to the utility for grid support services
including operating reserves, voltage control, reactive supply,
and frequency regulation needed to grid stability associated
with the adoption of solar.
The monetization of these costs (or benefits) is typically based on the
cost to procure grid support services. This category may also include
future costs and benefits associated with advanced technologies such
as smart inverters that may provide grid support services.
Participant
Cost
The cost incurred by the customer to purchase, install, and
operate the solar system.
Based on the cost of the solar system to the customer, including
financing and other costs.
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1.3 META ANALYSIS OF VALUE OF SOLAR STUDIES
VALUE OF SOLAR STUDIES TO DATE
Many states have commissioned studies assessing the cost and benefits of solar and
other renewables. Meta-studies on the value of solar also exist.
Source: GTM Research Unlocking the Locational Value of DERs, 2016
Value of Solar Meta-Studies:
▪ Rocky Mountain Institute (2013)
▪ Interstate Renewable Energy
Council (2013)
▪ Environment America and
Frontier Group (2016)
▪ Brookings (2016)
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1.3 META ANALYSIS OF VALUE OF SOLAR STUDIES
VALUE OF SOLAR STUDY VARIATIONS
Value of solar studies can be narrow or broad in scope, using different evaluation
perspectives. Some cost categories are widely recognized while others are more
contentious.
Study
TypeDescription
Cost CategoriesStudy Example
Variable Capital Externalities Societal
Narrow
Short-run marginal
cost savings from solar
additions.
X NV Energy 2015
Long-RunGeneration capacity
and energy valueX X Nevada (E3)
Broad
Generation,
transmission,
distribution, and other
utility system values
X X XMinnesota (State Energy
Office)
SocietalUtility system and
societal benefitsX X X X
Colorado (Crossborder
Energy)
Source: Regulatory Assistance Project, Solar Valuation and Cost/Benefit Analyses, May 2017
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1.3 META ANALYSIS OF VALUE OF SOLAR STUDIES
STUDY RANGES
-$0.20
-$0.10
$0.00
$0.10
$0.20
$0.30
$0.40
E3
20
14
(N
V)
SC
TY
201
6 (
NV
)
AP
S 2
01
3 (
AZ
)
CE
201
3a (
AZ
)
LB
NL
20
12
(C
A)
CE
201
3b (
CA
)
E3
20
13
(C
A)
XC
EL 2
01
3 (
CO
)
MD
OC
20
14 (
MN
)
CE
201
3c (
NC
)
CP
R 2
012
b (
NJ/P
A)
CP
R 2
013
b (
TX
)
AE
SC
20
15
(M
A)
CP
R 2
015
(M
E)
SE
20
14 (
MS
)
OR
S 2
01
6 (
SC
)
CP
R 2
014
(U
T)
$/k
Wh
in
20
15
$
Env. Unspecified
Plant O&M Value
Social
Env. Avoided RPS
Security Risk
Mkt Price Response
Bill Savings (cost)
Ancillary Services (cost)
DPV Technology (cost)
Equip. Extent.
Voltage Support
Environmental Cost
Utility Admin Cost
Utility Integration and Interconnection
Fuel Hedging
Avoided Carbon Dioxide
Avoided Criteria Pollutants
T&D Capacity
Ancillary Services
Avoided Capacity
Energy Losses/Line Losses
Avoided EnergySource: Navigant analysis of various value of solar studies
• Value of solar studies results can vary by the categories included, the jurisdiction, as well as the methods
used. In many cases the viewpoint of the authors also play a role
Benefit/Cost
Categories
further
detailed on
the next slide
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1.3 META ANALYSIS OF VALUE OF SOLAR STUDIES
STUDY RANGES
Source: Navigant analysis of various value of solar studies
• A review of value of solar studies
shows a wide range in type and
magnitude of costs and benefits
• The table to the right provides the list
of the categories listed in the previous
slide and min/max values across the
studies
• These are then categorized as
benefits, costs, or in some cases,
both
Category Min Max Benefit Cost
Env. Unspecified 0.00 0.20 X
Plant O&M Value 0.01 0.07 X
Social 0.05 0.13 X
Env. Avoided RPS 0.00 0.33 X
Security Risk 0.02 0.13 X
Mkt Price Response 0.05 0.20 X
Bill Savings (cost) -0.10 0.00 X
Ancillary Services (cost) 0.00 0.07 X X
DPV Technology (cost) -0.14 0.07 X X
Equip. Extent. 0.00 0.00 X X
Voltage Support 0.00 0.01 X X
Environmental Cost 0.00 0.00 X
Utility Admin Cost -0.01 0.07 X X
Utility Integration and Interconnection -0.15 0.33 X X
Fuel Hedging 0.01 0.33 X
Avoided Carbon Dioxide 0.00 0.47 X
Avoided Criteria Pollutants 0.00 0.33 X
T&D Capacity 0.00 0.87 X
Ancillary Services 0.00 0.20 X
Avoided Capacity 0.01 1.00 X
Energy Losses/Line Losses 0.00 0.40 X
Avoided Energy 0.03 1.00 X
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2.0
NY BENEFIT
COST ANALYSIS
HANDBOOK
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2.0 NY BENEFIT COST ANALYSIS HANDBOOK
INTRODUCTION
• This section provides an overview of the Benefit Cost Analysis (BCA) Handbooks
developed in NY
• This section is sub-divided into the following sub-sections:
- 2.1 NY Handbook History: Provides an overview of the timeline of how the Handbooks
came to existence, including the NY State Public Service Commission Order
- 2.2 Methodology: Describes key issues and challenges that should be considered when
developing a project, program, or portfolio-specific BCAs based on the methodology in the
Handbook
- 2.3 Cost Effectiveness Tests: Summarizes which cost-effectiveness tests can be applied to
the benefits and costs included in the BCA Order by the NYC PSC. This section also
describes the four types of benefits and four types of costs considered in the BCA
framework
- 2.4 Distributed Energy Resources: Discusses the characterization of DERs, and provides
the DER category defined in the Handbook, a DER example technology, resource, and
attributes of the technology. It also provides the applicability for each DER type to contribute
to each benefit and cost
- 2.5 Benefit Parameter Example: This slide provides benefit parameters for an example
intermittent DER
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2.1 NY HANDBOOK HISTORY
TIMELINE OF DEVELOPMENT
NYS PSC Issues REV Order
• The New York State Public Service
Commission (NYS PSC) issues an Order
Adopting Regulatory Policy Framework
and Implementation Plan (Track One) for
the Reforming the Energy Vision (REV)
proceeding
• Framework is meant “to define good utility
practice for the new century”
• Within it, the BCA framework development
will focus on (i) utility investments to build
DSP capabilities; (ii) procurement of DERs
via selective process; (iii) procurement of
DERs via tariffs; (iv) energy efficient
programs
• Also included is a Staff direction to issue a
BCA White Paper by May 1, 2015. Staff
will then conduct a comment process, with
the objective of proposing to the
Commission a common framework that
can be applied
Staff White Paper on BCA in the
Reforming Energy Vision Proceeding
• Staff release white paper describing a
framework for considering utility
proposals within the Reforming the
Energy Vision (REV) proceedings
• An underlying objective of the White
Paper is to facilitate dialogue among
parties addressing the components
and application of a BCA in the context
of REV
• White Paper discusses how the BCA
framework will be employed by utilities
in implementing REV programs and
policies
• It also proposes utilities develop BCA
Handbooks to guide DER providers in
structuring their projects and proposals
• The Handbooks should establish
methodologies based on common
analytics and standardized
assumptions
NYS PSC Order
establishing the BCA
framework
• NYS PSC states that
each utility shall file its
proposed BCA Handbook
along with its Distributed
System Implementation
Plan (DSIP) filing due
June 30th, 2017
• Utilities were directed to
work collaboratively in
preparing the Handbooks
(i.e. common
methodologies such as
use of the SCT)
• Uniform application
across the State where
feasible, with the
Handbooks deviating from
each other only where
necessary
February, 2015 July, 2015 January 2016
The development of the BCA Handbooks evolved from a REV order from the NYS PSC and Staff White Paper that
provided recommendations for the sector.
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2.1 NY HANDBOOK HISTORY
TIMELINE OF DEVELOPMENT CONT’D
Navigant Development of the BCA Handbooks
• In response to NYS PSC January 2016 Order, utilities issue RFP to develop BCA handbooks
Utilities include Consolidated Edison Company of New York, Inc., Orange and Rockland Utilities,
Inc., Central Hudson Gas & Electric Corporation, Niagara Mohawk Power Corporation d/b/a National
Grid, New York State Electric and Gas Corporation, and Rochester Gas & Electric Corporation the
New York (Joint Utilities, JU)
• Navigant worked with stakeholders to develop a consistent, state-wide implementation of the BCA
methodology for inclusion in each of the Joint Utilities Handbooks
• Navigant developed a “Handbook Template” format that can be readily adapted by each Joint
Utilities member to serve as its own BCA Handbook, as required in the DSIP Filing
• Navigant developed a common methodology for the Societal Cost Test (SCT) by evaluating each of
the 15 benefits and 5 costs identified for inclusion in the SCT, and developed a methodology for
calculating each item and/or applying a qualitative manner
• While the SCT is the primary measure of cost-effectiveness for the BCA framework, Navigant also
developed additional cost tests including Utility Cost Test and the Ratepayer Impact Measure
• After reaching consensus among the JU members on calculation methodology and developing the
BCA Handbook Template, Navigant extended the JU facilitation process to include Commission
Staff, as well as selected JU staff, in review of the Handbook Template. Navigant reviewed the
document with each of the Joint Utilities and with the Commission Staff to collect additional input
and comments
• Navigant delivered a final BCA handbook template for each Joint Utility
March, 2016
The remainder of the slides in this section draw from the NYSEG/RG&E BCA Handbook
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2.2 METHODOLOGY
GENERAL METHODOLOGICAL CONSIDERATIONS
Issue Discussion
Benefit
Definitions
and
Differentiation
• There are 16 benefits to be included in the cost-effectiveness tests included in The Handbook
• A key consideration in performing BCA is benefits and costs including under- and over-counting considerations
• For each benefit in a project or portfolio investment, potential overlapping benefits must be considered
o For example, two benefits defined in the BCA Order; bulk system benefits Avoided Generation Capacity Costs (ADCC)
and Avoided Locational Based Marginal Price (LBMP) result from system coincident peak demand reduction and
energy reduction impacts
• The BCA analysis should also be constructed to consider potentially overlapping costs
o For example, investment in a communications infrastructure for monitoring DER performance could be shared across
multiple DER installations and multiple applications
Incorporating
Losses and
Benefits
• Many of the benefit equations in the Handbook include a parameter to account for losses
• Losses can be accounted for by adjusting the impact parameter or the valuation parameter
Establishing
Credible
Baselines
• Establishing credible baselines associated with the benefit of a grid of DER project is critical
• The utility may develop baselines from recent historical data, forecasts, statistical or model-based projections, or
comparison/control groups during the course of the project
• Because the merits of grid modernization accrue over many years, baselines must be valid across the same time horizon
Normalizing
Impacts
• Normalizing impact data can present challenges. For example, a distribution feeder may go through changes that could
influence feeder performance independent of the technologies implemented
Establishing
Appropriate
Analysis Time
Horizon
• The duration over which the impact and benefits of new grid and DER investments accrue varies significantly
• Factors to consider in determining the time horizon include expected useful life of various hardware and software across
multiple projects, and how to reconcile differences in these lengths of expected useful lives
• The analysis timeframe should be based on the longest asset life in the portfolio/solution under consideration
The table below describes some key issues and challenges outlined in the BCA Handbook. These issues should be
considered when developing a project, program, or portfolio-specific BCAs based on the methodology in the Handbook.
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2.2 METHODOLOGY
GENERAL METHODOLOGICAL CONSIDERATIONS CONT’D
Issue Discussion
Granularity of
Data for
Analysis
• When granular data is not available, annual average or system average may be used, if applicable
• More granular or temporal assumptions are preferred
Performing
Sensitivity
Analysis
• A sensitivity analysis can be performed by changing selected parameters in each of the benefits and costs
• Since the largest benefits for DER are in the bulk system benefits of avoided LBM or AGCC, a sensitivity of LBMP
($/MWh) or annual average LBMPs could be compared across studies
• In addition, the applicability of certain benefits and costs could be considered a sensitivity analysis of the cost-
effectiveness tests
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2.3 COST EFFECTIVENESS TESTS
SUMMARY OF COST EFFECTIVENESS TESTS
SCT UCT RIM
Benefit
Avoided Generation Capacity ✓ ✓ ✓
Avoided LBMP ✓ ✓ ✓
Avoided Transmission Capacity Infrastructure ✓ ✓ ✓
Avoided Transmission Losses ✓ ✓ ✓
Avoided Ancillary Services ✓ ✓ ✓
Wholesale Market Price Impacts ✓ ✓
Avoided Distribution Capacity Infrastructure ✓ ✓ ✓
Avoided O&M ✓ ✓ ✓
Avoided Distribution Losses ✓ ✓ ✓
Net Avoided Restoration Costs ✓ ✓ ✓
Net Avoided Outage Costs ✓
SCT = Societal Cost Test
UCT = Utility Cost Test
RIM = Ratepayer Impact Measure
The following table summarizes which cost-
effectiveness tests can be applied to the benefits
and costs included in the BCA Order by the NYC
PSC.
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2.3 COST EFFECTIVENESS TESTS
SUMMARY OF COST EFFECTIVENESS TESTS
Benefit/Cost SCT UCT RIM
Benefit
Net Avoided CO2 ✓
Net Avoided SO2 and NOx ✓
Avoided Water Impacts ✓
Avoided Land Impacts ✓
Net Non-Energy Benefits ✓ ✓ ✓
Cost
Program Administration Costs ✓ ✓ ✓
Added Ancillary Service Costs ✓ ✓ ✓
Incremental T&D and DSP Costs ✓ ✓ ✓
Participant DER Costs ✓
Lost Utility Revenue ✓
Shareholder Incentives ✓ ✓
Net Non-Energy Costs ✓ ✓ ✓
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2.3 COST EFFECTIVENESS TESTS
BENEFIT AND COST CATEGORIES
There are four types of benefits and four types of costs considered in the BCA
framework.
Benefits
1. Bulk System: Larger system
responsible for the generation,
transmission and control of
electricity passed on the local
distribution system
2. Distribution System: System
responsible for the local
distribution of electricity
3. Reliability/Resiliency: Efforts
made to reduce duration and
frequency of outages
4. Externalities: Consideration of
social values for incorporation in
the SCT
Costs
1. Program Administration:
Includes the cost of state
incentives, measurement and
verification, and other program
administration costs to start-up
and maintain a specific program
2. Utility-Related: Those incurred
by the utility such as incremental
T&D, DSP, lost revenues and
shareholder incentives
3. Participant-related: Those
incurred to achieve project or
program objectives
4. Societal: External costs for
incorporation in the SCT
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2.4 DISTRIBUTED ENERGY RESOURCES
CHARACTERIZATION OF DERS
• The BCA Handbook characterizes DER profiles, and uses several examples to illustrate the
type of information necessary to assess benefits and costs
• The table below provides the DER category, the DER example technology, resource, and
attributes of the technology. This is followed by an example for Solar PV
DER
Category
DER
Example
Technology
Resource Attributes
Intermittent Solar PV Photovoltaic
(PV)
PV is an intermittent resource with energy output determined by solar irradiance. The directional
orientation and vertical angle of PV panels are important considerations for determining energy
output and thus the
corresponding coincidence factors with system-wide or local power delivery. PV energy output may
also degrade over time.
Baseload CHP Combined
Heat and
Power
(CHP)
CHP is a resource typically sized to meet a customer’s thermal energy requirements, but which also
provides electrical energy. The particular customer’s characteristics determine the ability of CHP to
contribute to various benefit and cost categories.
Dispatchable Controllable
Thermostat
Demand
Response
DR reduces energy demand for a particular service (use) during specific hours of the day—typically
peak demand hours—without reducing the service to an unacceptable level. DR is typically
available only for limited hours in a year (e.g., <100 hrs). The operational objective of the DR
determines how it may contribute to various benefit and cost categories.
Load
Reduction
Energy
Efficient
Lighting
Energy
Efficiency
EE reduces the energy consumption for delivery of a particular service (use)
without degrading or reducing the level of service delivered.
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2.4 DISTRIBUTED ENERGY RESOURCES
CHARACTERIZATION OF DERS CONT’D
PV CHP DR EE Key Parameter
Benefits
Avoided Generation Capacity Costs SystemCoincidenceFactor
Avoided LBMP ∆Energy (time-differentiated)
Avoided Transmission Capacity Infrastructure TransCoincidentFactor
Avoided Transmission Losses Limited or no applicability
Avoided Ancillary Services Limited or no applicability
Wholesale Market Price Impacts ∆Energy (annual), ∆AGCC
Avoided Distribution Capacity Infrastructure DistCoincidenceFactor
Avoided O&M Limited or no applicability
Avoided Distribution Losses Limited or no applicability
Net Avoided Restoration Costs Limited or no applicability
Generally applicable
May be applicable
Limited to no applicability
The following table summarizes the applicability for DER to contribute to each
benefit and cost. The last column provides the key parameter for quantifying how
DER may contribute to each benefit.¹
PV=Photovoltaic CHP=Combined Heat and Power DR=Demand Response EE-Energy Efficiency ¹Key Parameter Descriptions provided after table
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2.4 DISTRIBUTED ENERGY RESOURCES
CHARACTERIZATION OF DERS CONT’D
PV CHP DR EE Key Parameter
Net Avoided Outage Costs Limited or no applicability
Net Avoided CO2 CO2Intensity (limited to CHP)
Net Avoided SO2 and NO2PollutantIntensity (limited to CHP)
Avoided Water Impacts Limited or no applicability
Avoided Land Impacts Limited or no applicability
Net Non-Energy Benefits Limited or no applicability
Costs
Program Administration Costs
Added Ancillary Service Costs
Incremental T&D and DSP Costs
Participant DER Cost
Lost Utility Revenue
Shareholder Incentives
Net Non-Energy Costs
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2.4 DISTRIBUTED ENERGY RESOURCES
CHARACTERIZATION OF DERS CONT’D
Key
Parameter
Description
Bulk System
Coincidence
Factor
Necessary to calculate the Avoided Generation Capacity Costs benefit. It captures a project’s or program’s contribution to
reducing bulk system peak demand relative to its expected maximum demand reduction capability.
Transmission
Coincident
Factor
Necessary to calculate the Avoided Transmission Capacity Infrastructure benefit. It quantifies a project’s contribution to reducing
a transmission system element’s peak demand relative to the project’s expected maximum demand reduction capability. This
would be evaluated on localized basis in most cases, but in some instances an assessment of coincidence with a system
coincidence factor would be appropriate.
Distribution
Coincidence
Factor
Distribution coincidence factor is required to calculate the Avoided Distribution Capacity Infrastructure benefit. It captures the
contribution to the distribution element’s peak relative to the project’s expected maximum demand reduction capability. This
would be evaluated on a localized basis in most cases, but in some instances an assessment of coincidence with a system
coincidence factor would be appropriate.
CO2 Intensity CO2 intensity is required to calculate the Net Avoided CO2 benefit. This parameter is dependent on the type of DER being
evaluated – emission-free or emission-generating. It is the average CO2 emission rate of customer-sited pollutant-emitting
generation. This is a project-specific input based on the type of onsite generation.
Pollutant
Intensity
Pollutant intensity is required to calculate the Net Avoided SO2 and NOX benefit. This parameter is dependent on the type of
DER being evaluated – emission-free or emission-generating. It is the average SO2 and/or NOX emission rate of customer sited
pollutant-emitting generation. This is a project-specific input based on the type of onsite generation.
∆Energy
(time-
differentiated
This parameter measures the change in bulk system energy consumed as a result of specific DER project implementation. This
value is reliant on project-specific details including location. The ∆Energy is dependent on the type of DER (e.g., intermittent vs.
baseload), and how the DER would be operated (e.g., load reduction vs. energy conservation vs. backup generation). Thus, the
∆Energy is time-differentiated. It may be appropriate to use an annual average value for some DER, while for others it may be
more appropriate to use an average on-peak hours of operation, or even hourly operation. In each case the corresponding
LBMP data would be required to value the benefit. The examples provided herein discuss potential approaches to consider
time-differentiation by DER type.
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2.5 BENEFIT PARAMETERS EXAMPLE
SOLAR PV
• In The New York State Electric and Gas Corporation (NYSEG) and Rochester Gas & Electric
(RG&E) Handbook, a solar PV example is provided
• The assumptions used in this example are from E3’s NEM Study for New York (“E3 Report”)¹
¹ The Benefits and Costs of Net Energy Metering in New York. Prepared for: New York State Energy Research and Development Authority and New
York State Department of Public Service, December 11, 2015
System
4 kW-AC residential rooftop system connected to a local distribution system through the customer’s meter
Benefit Parameters
Parameter Value
SystemCoincidenceFactor 36%
TransCoincidenceFactor 8%
DistCoincidenceFactor 7%
∆Energy (time-differentiated) Hourly
Solar PVIntermittent DER
SystemCoincidenceFactor: This value represents the ‘effective’ percent of the nameplate
capacity, 4 kW-AC, that reduces the system peak demand, resulting in an avoided generation
capacity benefit. The 36% calculated from results of the E3 Report aligns with the coincidence
values presented in the NYISO ICAP manual, which provides a range from 26%-43%
depending on system azimuth and tilt angle.60 It is acceptable to use the summer average
because in this BCA, the AGCC is calculated based on the summer impact on-peak load
TransCoincidenceFactor: The transmission coincidence factor included is for the New York
average sub-transmission coincidence factor. This value would be highly project specific, as it
depends on the generation profile of the system, and the load profile for the site-specific area
on the sub-transmission system
DistCoincidenceFactor: The distribution coincidence factor is lowest. Residential distribution feeders and substations often peak during
early evening hours when solar output is low.61 This value would be highly project-specific, as it depends on the generation profile of the
system, and the load profile for the site-specific area on the distribution system.
∆Energy (time-differentiated): As discussed above solar output would be higher during daylight hours and summer months. As hourly
solar profiles are available from SAM, it would be appropriate to compare the projected energy output with hourly LBMPs
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BENJAMIN GRUNFELDManaging Director
416.777.2444
AMANDA ACKERMANManaging Consultant
416.268.4744
navigant.com
CONTACTS