innovation advisory committee support meeting... · • navigant was engaged by the ontario energy...

/ ©2018 NAVIGANT CONSULTING LTD. ALL RIGHTS RESERVED1

NET METERING POLICY AND THE

ROLE OF VALUE OF SOLAR STUDIES

&

NY BENEFIT COST ANALYSIS

HANDBOOK

APRIL 13, 2018

INNOVATION ADVISORY

COMMITTEE SUPPORT


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

/ ©2018 NAVIGANT CONSULTING LTD. ALL RIGHTS RESERVED3 / ©2018 NAVIGANT CONSULTING LTD. ALL RIGHTS RESERVED3

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


1.0

NET METERING

POLICY AND THE

ROLE OF VALUE

OF SOLAR

STUDIES


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

/ ©2018 NAVIGANT CONSULTING LTD. ALL RIGHTS RESERVED6 / ©2015 NAVIGANT CONSULTING, INC. ALL RIGHTS RESERVED6

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



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.



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.

http://www.dsireusa.org/



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

https://nccleantech.ncsu.edu/wp-content/uploads/Q42016_ExecSummary_v.3.pdf



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

https://nccleantech.ncsu.edu/wp-content/uploads/Q4-17_SolarExecSummary_Final.pdf



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.



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.



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.



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

http://www.dsireusa.org/

http://www.utilitydive.com/news/arizona-public-service-solar-industry-reach-critical-rate-case-settlement/437186/

https://www.greentechmedia.com/articles/read/how-to-find-compromise-on-net-metering

https://www.greentechmedia.com/articles/read/new-york-resets-distributed-energy-rates-maintains-residential-net-metering

http://puc.nv.gov/uploadedFiles/pucnvgov/Content/About/Media_Outreach/Announcements/Announcements/E3 PUCN NEM Report 2014.pdf

https://www.lw.com/thoughtLeadership/new-york-transitioning-away-net-energy-metering-distribution-resources

https://www.greentechmedia.com/articles/read/Californias-Net-Metering-2.0-Decision-Rooftop-Solar-to-Keep-Retail-Payme

http://news.energysage.com/net-metering-2-0-in-california-everything-you-need-to-know/

http://www.cpuc.ca.gov/General.aspx?id=3800

https://www.pv-tech.org/news/recognising-solars-value-key-to-nem-3.0


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).



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.



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.



BENEFIT CATEGORIES CONT’D


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.



COST CATEGORIES


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.


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)



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



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



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


2.0

NY BENEFIT

COST ANALYSIS

HANDBOOK


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


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.


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


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.


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


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.



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 ✓ ✓ ✓



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


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.



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




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




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.


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


BENJAMIN GRUNFELDManaging Director

416.777.2444

[email protected]

AMANDA ACKERMANManaging Consultant

416.268.4744

[email protected]

navigant.com

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