20171222Beach Direct.pdf

Kelsey Jae Nunez,lSB No.7899
KELSEY JAE NUNEZ LLC
920 N. Clover Dr.
Boise,ID 83703
Telephone: [phone]
kel sey @ kel seyj aenun ez.com
Attorney for Sierra Club
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION TO
ESTABLISH NEW SCHEDULES FOR
RESIDENTIAL AND SMALL GENERAL
SERVICE CUSTOMERS WITH ON-SITE
GENERATION.
RECEIVED
?0t? 0[c 22 Ptf 3: L5
u i r r.1?# sscbunfrh iSr, o*
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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CASE NO. IPC-E-17-13
The Sierra Club
Direct Testimony of R. Thomas Beach
December 22,2017
Executive Summary
Idaho Power has asked the Commission to take important initial steps toward
changing the compensation for customers who install renewable distributed generation
(DG) under net energy metering (NEM). This includes placing residential and small
commercial customers who install renewable DG into customer classes distinct from
standard customers. The Sierra Club is concerned that Idaho Power seeks approval of
this ratemaking step without actually establishing that there is a significant economic
problem with net metering that needs to be addressed at this time.
If the Commission wishes to review the economics of NEM in Idaho, the
Commission should only grant Idaho Power's request to establish a stakeholder process
to assess the benefits and costs of all types of distributed energy resources (DERs),
including those that involve net metering. All DERs should be evaluated using the same
best practices that the electric industry has used for many years to assess the cost-
effectiveness of long-term energy efficiency and demand response resources. If this
evaluation determines that the benehts of net metered DERs exceed the costs, then the
Commission does not need to change the rates applicable to those DERs. If the
Commission concludes the opposite, it can proceed to a rate case to consider adjusting
the rates (or other compensation) applicable to DERs to restore an equitable balance of
benefits and costs. Ratemaking changes that affect the balance of benefits and burdens
associated with DERs - such as the creation of separate customer classes - should be
evaluated in a rate case, and only after the Commission has completed the benefit / cost
assessment.
This testimony also discusses certain key attributes of net metered customers that
Idaho Power's testimony does not characterize correctly. DG customers do not make "bi-
directional use" of the grid for both importing and exporting power. When a solar
customer exports power to the utility, it is the utility that uses the grid to deliver those
exports to neighboring customers (and the utility is fully compensated by the neighbors
for that service). Exported power represents a service - generation - that the solar
customer provides to the utilitv, not the other way around. Thus, a DG customer actually
uses the distribution system less than a regular non-DG customer of comparable size, and
provides the utility with significant benefits by reducing peak loads on the distribution
system. The utility also does not incur costs to "store" DG output, nor does it incur
significant costs to "standby" to serve the DG customer's loads that are greater than its
comparable costs to be ready to serve standard customers.
The Commission should establish a clear policy that existing NEM customers will
be allowed to remain under the rules and rate structure that applied when they originally
applied to interconnect with the utility for a 20-year period that represents the reasonable
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economic life of the DG system. Such a grandfathering policy has been adopted by most
states that have changed the rates, terms, and conditions applicable to net metered
customers. In the one state that did not follow this policy (Nevada), there was significant
customer backlash and political turmoil until existing NEM customers were
grandfathered for 20 years.
In sum, the key points of this testimony are the following:
1. Customers who install renewable DG have a legal right under PURPA to install
generation to serve their own loads behind the meter.
2. Rates for all customers, including those who install DERs, should be based on the
utility's cost to deliver power to the customer.
3. The exports that DG customers deliver to the grid are a generation service which
they provide to the utility, not a service which they receive from the utility.
4. DG customers should not be charged costs associated with the delivery of their
exported power to neighboring customers, because this delivery is a service which
the utility provides to the neighbors.
5. The key public policy issue with net metering is whether the bill credits for
exported power at the retail rate are the equitable credit for those exports.
6. DER customers should be grandfathered on the NEM rules and the rate design that
applied when they made the investment, for a2\-year period that represents the
useful life of that investment.
7. Rate design should evolve to send more accurate price signals to all types of DERs
- for example, through a greater use of time-sensitive rates - rather than trying to
design a different rate structure for each type of DER.
8. If the long-term benefits of DERs exceed the costs, other ratepayers will be
disadvantaged if DERs are moved into their own class.
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Table of Contents
EXECUTIVE SUMMARY OF RECOMMENDATIONS...I
I. INTRODUCTION...
II. IDAHO POWER',S REQUEST......J
III. EVALUATING THE BENEFITS AND COSTS OF NET METERING .,...4
A. Is There a Problem Today with Net Metered Renewable Resources in Idaho? ............4
B. Best Practices for Evaluating the Benefits and Costs of DERs.... ................7
C. Experience in Other States: Nevada, California, and Utah ......14
D. The DG Customer as "Prosumer" ........19
E. PURPA Considerations.......... ..............24
F. DERs Can Provide Distribution System Benefits ....................27
IV. PROVIDING CERTAINTY FOR DG CUSTOMERS....34
V. LIMITATIONS OF COST-OF-SERVICE ANALYSIS, AND THE PROPER ROLE OF
RATE CASES..... .........37
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1 I. INTRODUCTION
Please state your name, address, and business affiliation.
My name is R. Thomas Beach. I am principal consultant of the consulting firm
Crossborder Energy. My business address is 2560 Ninth Street, Suite 2134, Berkeley,
California 94710.
Please describe your experience and qualifications.
I have over 30 years of experience in utility analysis, resource planning, and rate design.
I began my career at the California Public Utilities Commission, working from 1981-
1984 on the initial implementation in California of the Public Utilities Regulatory
Policies Act (PURPA) of 1978. I then served for five years as an advisor to three CPUC
commissioners.
Since entering private practice as a consultant in 1989, I have served as an expert witness
in a wide range of utility proceedings before many state utility commissions. This
includes sponsoring testimony on PURPA-related issues in state regulatory proceedings
in Idaho, California, Montana, Nevada, North Carolina, Oregon, Utah, and Vermont.
With respect to benefit-cost issues concerning renewable distributed generation ("DG"), I
have sponsored testimony or studies on net energy metering ('NEM") or solar economics
in Idaho, Arkansas, Arizona, California, Colorado, Georgia, Minnesota, New Hampshire,
New Mexico, North Carolina, South Carolina, Texas, and Virginia. I also co-authored a
chapter on Distributed Generation Policy in America's Power Plan, a report on emerging
energy issues, which was released in 2013 and is designed to provide policymakers with
tools to address key questions concerning distributed generation (DG) and other
distributed energy resources (DERs).
Prior to this professional experience, I earned degrees in English and Physics from
Dartmouth College and a Masters in Mechanical Engineering from the University of
California, Berkeley.
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On whose behalf are you testiffing in this proceeding?
I am appearing on behalf of the Sierra Club (Sierra).
The Sierra Club is a national, non-profit environmental and conservation organization
dedicated to the protection of public health and the environment. Sierra Club is
participating in this case on behalf of itself and nearly 3,500 Sierra Club members who
live and purchase utility services in Idaho. Sierra Club's Idaho members have a direct
and substantial interest in this proceeding as a result of its potential impact on additional
solar deployment in Idaho and on the environmental, health, and economic benefits that
would result from the continued growth of this renewable generation resource for the
Idaho electric system.
Q: Have you previously testified or appeared as a witness before the Idaho Public
Utility Commission?
A: Yes, I have. I testified on behalf of the Idaho Conservation League (ICL) in Case No.
IPC-E-I2-27 concerning proposed changes to Idaho Power's net metering service. I also
testified on behalf of Sierra and ICL in Case No. IPC-E-15-01 concerning changes to the
terms of PURPA contracts in Idaho.
Do you have any exhibits?
No.
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I. IDAHO POWER'S REQUEST
Please summarize ldaho Power's request in this application.
ldaho Power has asked the Commission to authorize the following:
. closure of Schedule 84 to new service for Residential and Small General Service
(R&SGS) customers with on-site generation,
. establishment of two new customer classes applicable to R&SGS customers with
on-site generation that request to interconnect to ldaho Power's system on or after
January 1,2018, with no pricing changes at this time,
. amendment of the Company's applicable tariff schedules to require the installation
and operation of smart inverters for all new customer-owned generator
interconnections within 60 days following IEEE's adoption of an industry
standard definition of smart inverters, and
. sommencement of a generic docket at the conclusion of this case to establish a
compensation structure for customer-owned DERs that reflects both the benefits
and costs that DER interconnection brings to the electric system.l
Why does Idaho Power believe that these steps should be taken at this time?
The utility asserts that net metering is a "non-cost based policy" and therefore not an
equitable way to compensate net-metered customers for the renewable generation that
they provide to the Idaho Power system.2 Idaho Power alleges that there is an undue
"cost shift" from the installation of renewable DG by small customers in its service
territory.3 Idaho Power wants to place net metered customers into separate customer
classes in order to "position the company to study this segment of customers, providing
the data necessary to understand how this customer segment utilizes the company's
system."4 The utility also indicates that this step would inform prospective net metering
customers that their rates may change in the future.s
Idaho Power Application, at pp. 15-16, summarizing pp. 5-14.
Ibid., atp. 4.
Idaho Power testimony (Tatum), at pp. 5-6.
Ibid., atp.19.
Ibid., at p. 18.
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II. EVALUATING THE BENEFITS AND COSTS OF NET METERING
A. Is There a Problem Today with Net Metered Renewable Resources in ldaho?
What is your principal concern with Idaho Power's request in this application?
My primary concern is that the utility is asking the Commission to take important initial
steps toward changing the compensation for customers who install renewable DG under
net metering, without actually establishing that there is an economic issue with net
metering that needs to be addressed at this time. Before beginning surgery on a patient, a
responsible doctor first should determine whether the patient is actually ill.
Further, the proposal to create separate customer classes for customers who install
renewable DG - with the strong presumption that future rates will be different for NEM
vs. regular customers - suggests that Idaho Power regards net metering as exclusively a
ratemaking issue, and may seek to evaluate NEM using only a cost-of-service analysis
similar to the approach that the utility uses to set rates. Indeed, the annual net metering
reports that Idaho Power submit to the Commission use such an analysis to calculate an
alleged "cost shift" from NEM customers.
Q: Is net metering solely or even principally a ratemaking issue?
A: No. Net metering is principally a long-tern resource planning and compensation issue.
Net metering is the means used in Idaho and over 40 other states to compensate
customers who install renewable DG, using their private capital on their private premises,
and who then export excess generation to the grid.6 DG facilities that quali$ for NEM
are long-lived renewable generation resources. The solar panels that a small customer
installs on the roof of their home are warrantied to produce power for 20-25 years, and
u Today, 47 states offer some type of net metering. See
http://prosrams.dsireusa.ors/system/prosram/maps. This includes Arizona, California, Nevada, New
Hampshire, and Hawaii, states which have large numbers of existing DG customers on traditional net
metering, but which recently have adopted revised compensation rules for new DG customers that make
changes in the compensation for excess generation exported to the grid.
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will do so reliably for long beyond the test year for the next rate case. They are a
demand-side resource that will reduce a customer's long-term consumption from the grid,
just as an energy efficiency measure (such as a more efficient appliance) will result in a
long-term reduction in a customer's energy usage for the measure's life. In addition, the
solar panels will produce excess generation that the utility can use to serve other nearby
loads. The output of renewable DG, when brought to scale, can provide a major new
source of clean electricity for the electric system.T This is power that, due to its location,
is already delivered to load. Thus, renewable DG can displace the need not only for
additional central station generation but also for upgrades to the transmission and
distribution (T&D) wires that would be needed to deliver that avoided central station
generation to loads.
Q: Are the issues concerning net metering solely related to customers who install solar
panels?
A; No. Idaho Power's application focuses on solar DG, although the utility does refer to
distributed energy resources (DERs) more broadly.s Although solar DG is the
predominant net metered resource today, DER technologies also include:e
. Wind
. Small hydro
' Biomass
. Fuel cells
. Combined heat and power (CHP)
. Storage, both battery and thermal
. Electric vehicles (EVs)
. Energy efficiency (EE)
. Demand response (DR)
' For example, in the last decade, California has added about l5 GW of new solar capacity. l0 GW of
this capacity is from wholesale, utility-scale projects; 5 GW is from net-metered, behind-the-meter solar
facilities on customers' premises. On several of the Hawaiian islands, solar DG penetration is
approaching 20o% of customers with solar DG systems, representing more capacity than the utility-scale
solar plants in Hawaii.8 Idaho Power testimony (Tatum), at pp. 6, 8 and 14.
' CHP facilities are not eligible for net metering in Idaho, and the treatment of storage is unclear.
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Further, DER technologies can be combined in many different ways. The benefits and
costs of a solar installation with on-site battery storage will be significantly different than
a solar-only installation. DER generation technologies can be combined with new EV
loads and with EE and DR measures and programs, all of which will alter the size and
time profile of the load that a customer places on the utility system. DERs such as
electric vehicles (EVs) will increase the customer's load as well as shift the customer's
load profile.
Idaho Power has asked the Commission to open a generic docket to establish a
compensation structure for customer-owned DERs that reflects both the benefits
and costs of DERs. Should this be the first step that the Commission takes, before
making ratemaking choices such as the creation of separate customer classes?
Yes; however, the docket should be specific to Idaho Power, for reasons that I discuss
below. The Commission should establish a framework and methodology for assessing
the benefits and costs of all types of DERs on the Idaho Power system, including those
that involve net metering. All DERs should be evaluated using the same industry best
practices that are commonly used to assess the cost-effectiveness of any type of resource,
either demand-side DERs or utility-scale, supply-side resources. There are two possible
outcomes to this assessment:
1. If this evaluation determines that the benefits exceed the costs for various types
of net metered DERs, then the Commission does not need to change the rates
applicable to customers who install those DERs. With this outcome, it will
benefit all ratepayers if DER customers continue to be served from the same
customer class as other, non-DER customers.
2. If there is evidence of that the costs exceed the benefits for a type of DER, such
that there is an undue cost shift, the Commission then can then proceed to
consider adjusting the rates (or other compensation) applicable to that DER to
restore a more equitable balance of benefits and costs.
Thus, ratemaking changes that affect the balance of benefits and burdens associated with
NEM - such as the creation of separate customer classes - should occur only after the
Commission has completed the benefit/cost assessment.
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A:
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a Why should this docket be specific to Idaho Power, rather than a generic
proceeding?
There are several reasons. First, each utility in Idaho has its own set of resources, and
each has a distinct cost structure and rates. As a result, the benefits and costs of DERs
will be unique to each utility. Second, generic dockets with multiple utilities are more
complicated to process, more difficult to schedule, and more burdensome for intervening
parties who have to focus on multiple utilities at the same time. Establishing a docket
specific to Idaho Power would streamline the process of developing a benefit / cost
methodology and avoid unnecessary complication and delay. Finally, once the benefit /
cost methodology is selected, the appropriate venue for applying the methodology and
determining the rate design and compensation for DERs will be in a rate case, which of
course will be specific to each utility.
B. Best Practices for Evaluating the Benefits and Costs of DERs
Are there best practices for designing benefit-cost analyses of behind-the-meter
DERs that should inform how the Commission undertakes this analysis?
Yes, there are. If the Commission grants Idaho Power's request to initiate a docket to
establish a compensation structure for customer-owned DERs that reflects both the
benefits and costs of DERs, the Commission should specifu the use of the best practice
benefit/cost methodology that the U.S. utility industry uses to perform such assessments
for demand-side resources.
In this regard, the first and perhaps most important observation is that the issues raised by
the growth of demand-side DG and other DERs are not new. Solar DG is also not the
first type of DER that has raised issues of impacts on the utilities, on non-participating
ratepayers, and on society as a whole. The same issues arose when utilities and state
regulators began to manage demand growth through EE and DR programs. To provide a
framework to analyze these issues in a comprehensive fashion, the utility industry in the
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U.S. developed a set of standard cost-effectiveness tests for demand-side p.og.ams.'o
These tests examine the cost-effectiveness of demand-side programs from a variety of
perspectives, including from the viewpoints of the program participant, other ratepayers,
the utility, and society as a whole.
A central goal of this standard practice is to apply to DERs the same cost-effectiveness
standards that a commission will use to assess the long-term merits of a new supply-side
addition that the utility has asked to add to its rate base. This framework for evaluating
demand-side resources is widely accepted, and state regulators have years of experience
overseeing this type of cost-effectiveness analysis, with each state customizing how each
test is applied and the weight which policymakers place on the various test results. States
are now adapting this suite of cost-effectiveness tests to analyses of DERs more broadly,
as state legislatures and commissions recognize that evaluating the costs and benefits of
all demand-side resources - EE, DR, DG, and other types of DERs - using the same cost-
effectiveness framework will help to ensure that all of these resource options are
evaluated in a fair and consistent manner.
Each of the principal demand-side cost-effectiveness tests uses a set of costs and benefits
appropriate to the perspective under consideration. These are summarized in Table I
below. "*" denotes a benefit; o'-" a cost.
r0 See the California Standard Practice Manual: Economic Analysis of Demand-Side Programs and
Projects (October 2001), available at http://www.energy.ca.eov/gleenbuildine/documents/background/07-
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I CPIIC STANDARD A(-TI'tr IMANIIAI PDtr
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Table l: Demand-side Cost/Benefit Tests
The key goal for regulators is to implement demand-side programs that produce
balanced, reasonable results when the programs are tested from each of these
perspectives. A program will need to pass the Participant Test (PCT) if it is to attract
customers by offering them an economic benefit for their participation - thus, their bill
savings and tax benefits should be comparable to the cost of participating. The program
also should be a net benefit as a resource to the utility system or society more broadly -
thus, the Total Resource Cost (TRC) and Societal Tests compare the costs of the progfttm
to its benefits, which are principally the costs which the utility can avoid from the
reduction in demand for electricity.rr The Ratepayer Impact Measure (RIM) test gauges
the impact on other, non-participating ratepayers: if the utility's lost revenues and
program costs are greater than its avoided cost benefits, then rates may rise for non-
rr The Societal Test is a version of the TRC Test which adds the broader benefits of DERs to all citizens
as a social whole, and includes benefits that may not be reflected in utility rates.
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Capital and O&M Costs of
the DG Resource
Customer Bill Savings or
Utility Lost Revenues +
Benefits (Avoided Costs)
-- Energy
-- Hedging/market mitigation
-- Generating Capacity
-- T&D Capaciry
-- Line losses
-- Reliability'Resiliency/Risk
-- Environmental/ RPS
++
Federal Tax Benefits ++
Program Administration,
lnterconnection & lntegration
Costs
Perspective (Test)DG Customer
(Participant)
Other
Ratepayers
(RrM)
Total Resource
Cost to Utility or
Society (IRC or
Societal)
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participating ratepayers in order to recover those costs. This can present an issue of
equity among ratepayers. The RIM test sometimes is called the o'no regrets" test because,
if a program passes the RIM test, then all parties are likely to benefit from the program.
However, it is a test that measures equity among ratepayers, not whether the program
provides an overall net benefit as a resource (which is measured by the TRC and Societal
tests).
Q: Does Idaho use these a set of these tests for evaluating established DERs such as EE
and DR programs?
A: Yes. Under the terms of the Memorandum of Understanding for Prudency Determination
of DSM Programs, Idaho Power uses three primary cost-effectiveness tests: the TRC,
which "reflects the total benefits and costs to all customers (participants and non-
participants) in the utility service territory," the utility cost test (UCT), which "calculates
the costs and benefits of the program from the perspective of ... the utility implementing
the program;" and the PCT, which "assesses the costs and benefits from the perspective
of the customer installing the measure."l2 The RIM test "examines the potential impact
the energy efficiency program has on rates overall" including impacts to customers who
do not participate in the demand-side management (DSM) or net metering programs.l3
Because this is the strictest of the tests, Idaho Power is "not required to use the non-
participant ("no losers") RIM test."l4
A:
Why would you apply a method developed for evaluating DSM programs to
evaluate NEM costs and benefits, when a NEM customer can go beyond reducing
their own consumption and deliver excess enerry to Idaho Power's system?
In practice a NEM customer is most similar to an energy efficient customer and is
fundamentally different than an independent power producer who seeks to sell all of their
output to a utility in a wholesale transaction. NEM systems typically are limited to
" Ord", No 32331at 9 - 10, IPC-E-I1-05.
13 National Action Plan for Energy Efficiency, (Jnderstanding Cost-Effectiveness of Energt Efficiency
Programs: Best Practices, Technical Methods, and Emerging Issues for Policy-Makers at 3-6 (November
2008).
'o Ordu No 28894 at7,1PC-E-01-13. A RIM score above one indicates rates are likely to decrease due
to the net metering program, as has been the case with Idaho Power's net metering program.
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having an annual output that is no greater than the customer's on-site load. The utility
continues to provide delivered power to serve a significant portion of the customer's load.
The Commission has stated that the "primary thrust of net metering," like other demand-
side programs, "is to provide customers the opportunity to offset their own load and
energy requirements."l5 A significant portion, often over 50%, of the output of a net
metered DG system serves the customer's on-site load without ever touching the grid,16
as illustrated in Figure 1. In this respect, the DG customer looks to the utility like an
energy efficiency (EE) or demand-side management (DSM) resource. Because of the
required focus on serving on-site load, NEM should be evaluated in a manner that is
consistent with how other demand-side resources are assessed.
Figure l: The Three States of Net Metering
Load on
z thr Grid
=:
Eo
E
sobr output
Export"d
Gcnaration
7 2 3 4 5 6 7 & 9 10 11 12 13 14 15 16 17 1a 19 20 27 22 23 24
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Customer Load by Hour of the Day
15 Order No. 28951 at ll.16 The exact percentage used on-site will depend on the size of the solar DG system compared to the
customer's load, and on the customer's load profile through the day. For the typical residential customer
(such as shown in Figure l), 50% or more of the DG output is used on-site, with the rest exported to the
grid.
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Energy
Efliciency R,rtall CustomerRetail Customer
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Traditional DSM programs pay customers an incentive to reduce on-site loads. For NEM
customers, the "incentive" is crediting, at the energy portion of the retail rate, the portion
of the NEM customer's output that is exported to the grid, instead of paying a wholesale
power price. This incentive is conceptually no different than a rebate, which is paid to a
customer when the customer buys an energy-efficient air conditioner or agrees to manage
his irrigation pumping loads. Those DSM programs are analyzed to ensure that the costs
and benefits are balanced such that society as a whole benefits and other ratepayers are
not unduly burdened. Similarly, any analysis of the benefits and costs of Idaho Power's
NEM program going forward should focus on whether NEM provides fair value as a
long-term resource, by assessing whether the cost of NEM credits at the retail energy rate
are offset by the benefits to other ratepayers from the reduced demand and the new
source of power that the NEM customer brings to the grid.
Q: Have you used this approach to calculate the benefits and costs of net metered solar
DG on Idaho Power's system?
A: Yes, in part, and I provided this analysis to the Commission in my testimony in Case No.
IPC-E-12-27. This analysis was a standard RIM test measuring the impacts of NEM on
non-participating ratepayers. As noted above, my recommendation is that any evaluation
of NEM should include all of the relevant tests and perspectives, not just a RIM analysis.
My analysis compared the retail rate credits paid to solar net metered customers (the
primary costs of net metering) to the costs which Idaho Power avoided by not having to
procure and deliver alternative power supplies to net metered customers (the benefits of
net metering). These benefits were based primarily on avoided cost data from the
Company's 2011 and 2013 IRPs. Table 2 summarizes the costs and benefits that I
calculated. My analysis concluded that, for Idaho Power's non-participating ratepayers,
the benehts of net metering significantly exceeded the costs, by a factor of 1.6 to 1.9. In
other words, my analysis showed that crediting NEM generation at the retail rate for
either the Residential or Small Commercial class actually undervalued this new
generation source. Notably, my analysis included only generation and transmission
benefits, without considering avoided distribution costs (other than avoided line losses) or
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other benefits that can be quantified (such as lower market prices or the reduction in fuel
price volatility).
Table 2: Summory of ldaho Power NEM Costs ond Benefits
2}-yeor Levelized 5 per MWh
Costs
Lost Utility Revenues Sar
lntegration Costs s4
Total Costs s8s
Benefits
Energy
2011 rRP se2
2013 IRP (estimated)So+
Capacity - both lRPs S+o
Transmission - both lRPs s32
Total Benefits - 2011 IRP S re+
Total Benefits - 2013 IRP s 136
Benefit / Cost Ratio
2011 rRP 1.9
2013 rRP 1.6
Have you updated this analysis based on Idaho Power's 2017 IRP?
I have not done a final analysis, in recognition that the scope of this case does not include
the quantification of NEM's benefits and costs. My initial analysis of an updated RIM
Test indicates that, although the energy and capacity benefits of solar DG are lower today
than they were in 2013, these reductions are more than offset when one quantifies the
distribution and other benefits of solar DG that I did not quantiff in my 2013 testimony.
In addition, the Commission should be aware that there is a much broader array of DER
technologies on the market or on the horizon today than in 2017.
Please summarize the key attributes of the methodology that the Commission should
specify to assess the benefits and costs of net metered DG resources.
There are three key attributes:
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1. Analyze the benefits and costs from the multiple perspectives of the key
stakeholders. As discussed above, it is important that the Commission assess the
benefits and costs of net metering from the perspectives of each of the major
stakeholders - the utility system as a whole, participating NEM customers, and other
ratepayers - so that the regulator can balance all of these important interests.
Examining all of these perspectives is critical if public policy is to support customer
choice and equitable competition between DG providers and the monopoly utility.
2. Consider a comprehensive list of benefits and costs. The location, diversity, and
technologies of DG resources will require the analysis of a broader set of benefits and
costs than, for example, traditional QF facilities installed under PURPA. Renewable
DG projects produce power in many small (less than I MW) installations that are
widely distributed across the utility system. The power is produced and consumed on
the distribution system;17 indeed, each net-metered DG project is generally associated
with a load at least as large as the DG project's output,rs which will limit the amount
of power than is exported to the grid. An important attribute of DG exports is their
ability to serve loads without the use of the transmission system. Accordingly, an
analysis of DG benefits should consider the avoided costs for line losses and for
transmission and distribution capacity. Renewable DG also will avoid the costs
associated with environmental compliance at marginal fossil-fueled power plants. On
the cost side, the analysis should consider whether solar or wind DG will result in
new costs to integrate these variable resources.
3. Analyze the benefits and costs in a long-term, lifecycle time frame. The benefits
and costs of DG should be calculated over a time frame that corresponds to the useful
life of a DG system, which, for solar DG, is 20 to 30 years. This treats solar DG on
the same basis as other utility resources, both demand- and supply-side. When a
utility assesses the merits of adding a new power plant, or a new EE program, the
company will look at the costs to build and operate the plant or the program over its
useful life, compared to the costs avoided by not operating or building other resource
options. The same time frame should be used to assess the benefits and costs of DG.
C. Experience in Other States: Nevada, California, and Utah
Q:Can you provide examples of other state commissions which have developed
analyses of NEM using the approach that you recommend?
t7 It is possible that, at high penetrations, DG output to a distribution circuit could exceed the minimum
load on the circuit, as has occurred at some locations in Hawaii. Such penetrations from NEM customers,
the focus ofthis docket, are not expected to be reached in Idaho for many years.18 Idaho Power's current Schedule 84 defines net metering as a service "for Customers to install
Generation Facilities to interconnect to the Company's system to offset all or a portion of their electrical
usaqe." Schedule 84 limits the size of NEM facilities for R&SGS customers to no more than 25 kW and
for customers other than R&SGS to no more than 100 kW.
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A Yes. The Public Utilities Commission of Nevada ("PUCN") adopted this multi-
perspective approach in the net metering study which it released on July 1,2014. The
consulting firm Energy and Environmental Economics (E3) performed the analytic work
for this study, and I served on a Stakeholder Committee that the PUCN convened to
provide input on the study methodology and analysis. Figure 2 below shows the costs
and benefits of net-metering for solar PV systems in Nevada going forward, in the years
2014-2016, from each ofthe key stakeholders' perspectives.
Figure 2z Public Utilities Commission of Nevada NEM Benefit-Cost Results
so.3s
Cost Benefit Cost Benefit Cost Eenefit Cost Benefit Cost Benefit
ParticpantCost Ratepayerlmpact Pro3ram TotalRcsource SocietalCostTestTest Measurc Administrator Cost Tcst
(UtilM Cost Test
s3J
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I Pre-lncentive Capital Cost
r utility Avoided costs
I Federal lncentives
r NEM Program Costs
M lnteBration Costs
: NEM Customer BillSavings
M Utility lncentives
r RPS Value
r Criteria Pollutant (Social Cost)
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Notably, the Nevada study showed that NEM was cost-effective for non-participating
ratepayers (i.e., the benefits in the RIM test exceeded the costs), while the costs were
somewhat higher than the benefits for participants (i.e., for solar customers). As with any
such set ofcost-effectiveness tests, it is not reasonable or practical to expect each ofthese
tests to achieve a precise 1.0 benefit/cost ratio. Instead, the goal should be to achieve a
reasonable, equitable balance of benefits and costs for all concerned - solar customers,
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other ratepayers, and the utility system as a whole. In my judgment, the Nevada study
demonstrated that, in2}T4,NEM at the full retail rate, without any further rate design
modifications, achieved that desired "rough justice" balance of interests in Nevada.
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Avoided energy costs
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Fuel hedging
Utility integration and interconnection costs
Utility administration costs
Environmental costs
Q:
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What was the result of the PUCN decision?
The reduction in the export rate and the increased fixed charge reduced the bill savings
available to NEM customers in Nevada by 40% or more. DG was no longer economic
for new systems, and existing customers who expected modest savings from their solar
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Q: Did the Nevada Commission subsequently move away from the use of a long-term
benefit-cost approach to analyze NEM in that state?
A: Yes, it did. In 2015, in response to new legislation, the PUCN reviewed a study from NV
Energy that was limited to the short-term cost of service for residential and small
commercial customers who install solar DG. The PUCN issued a decision in December
2015 which accepted the results of that study, and, based on that evidence, found that
there was a significant cost shift from non-participating ratepayers to solar DG
customers. As a result, the PUCN ended NEM in Nevada, increased the fixed monthly
customer charge for DG customers, and reduced the export rate credited to DG systems
from the full retail rate (about I 1 cents per kWh for residential customers) to an energy-
only wholesale rate of 2.6 cents per kwh. The PUCN took this action even though its
order found that there are the following 11 components to the value of DG (based on an
adopted stipulation on NEM issues from South Carolina), and that it was only able to
quantifu the first two components of DG value in the adopted 2.6 cents per kWh export
rate:
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investments faced substantial added costs for electric service. Even though the PUCN
subsequently decided to phase-in the new DG rates over a l2-year period, the elimination
of NEM and, in particular, the reduction in the export rate, decimated the rooftop solar
market in Nevada, resulting in more than 1,000 documented layoffs at solar companies.
The controversy was particularly heated because the PUCN applied the new rates to
existing solar customers as well as to prospective ones. The changes sparked significant
public outcry, a ballot initiative, and lawsuits from unhappy customers whose
investments in renewable DG had been severely and unexpectedly rendered uneconomic.
ln20l6,the PUCN reversed course, asked E3 to re-evaluate the benefits and costs of
solar DG, and subsequently adopted a limited reopening of full retail net metering in
northern Nevada.le In the order re-instating net metering, the new chair of the PUCN
wrote:
The landscape on these issues continues to grow. Abraham Lincoln once
said that 'Bad promises are better broken than kept.' The PUCN's prior
decisions on NEM, in several respects, may be best viewed as a promise
better left unkept. The PUCN is free to apply a new approach.20
The PUCN also reversed course on the treatment of existing NEM customers, adopting a
grandfathering policy that will allow them to net meter at full retail rates for a 20-year
period.2l
Pursuant to 2017 legislation (AB 405), the compensation for the exports from new solar
DG customers in Nevada has been set at a small (5%) discount to the retail rate, with the
discount increasing in steps for every 80 MW of DG that is installed. The compensation
structure for exports is guaranteed for 20 years for new DG customers. The legislation
also includes consumer protection provisions and a Solar Bill of Rights specifring that
every Nevada customer has the right to generate and store solar energy and providing that
le See https://www.sreentechmedia.com/articles/read/nevada-resulators-retore-retail-rate-net-metering-
in-s ierra-pac i fi c-territo.20 See PUCN Order in Dockets Nos. 16-06006 et al. issued December 20,2016, at p. 39. Available at
http ://pucweb I .state.nv. us/PDF/AXI maees/Aeendas/2 5- I 6/680 I .pdf.2t See https://www.greentechmedia.com/articles/read/nevada-resulators-restore-net-meterins-for-
existing-solar-customers#es.aExnC D4.
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each solar customer will be in the same class and have the same rate options as non-solar
customers.22
Q: Did the California Public Utilities Commission recently review the benefits and costs
of net metered DG?
A: Yes. In 2015, the investor-owned utilities in California were approaching that state's 5oZ
cap on NEM systems. The California Commission asked parties to analyze their
proposals for a NEM successor tariff using a common "Public Tool" spreadsheet program
similar to the Nevada NEM benefit-cost model. Like the Nevada model, the California
Public Tool analysed a proposed tariff from multiple perspectives, using all of the SPM's
cost-effectiveness tests and looking at the long-term, life-cycle costs and benefits. The
CPUC received detailed analyses of NEM benefits and costs using the Public Tool from a
variety of parties. In January 2016, the California commission decided to extend NEM in
Califomia until a further review in20l9, with certain changes such as requiring NEM
customers to be on time-of-use ("TOU") rates, removing certain public benefit charges
from export rates, and requiring NEM customers to pay interconnection costs.2' The
CPUC's order does not rely on the Public Tool analyses, because important information
related to both costs (rate design changes) and benefits (locational benefits on the
distribution grid and societal benefits) remain under development in other CPUC
proceedings. However, the CPUC made clear that it intends to continue to refine and to
use this SPM-based, long-term benefit-cost approach in its future evaluations of NEM
and DG.
Q:The Utah commission recently approved a settlement with a process for reviewing
the benefits and costs of NEM in that state.2a Please comment on the Utah
stipulation.
22 The PUCN implemented the provisions of AB 405 on September 1,2017 in its Order Granting in
Part and Denying in Part Joint Application by NV Energ on Assembly Bill 405 in PUCN Docket No. l7-
07026.23 See CPUC Decision No. l6-01-044 (January 28,2016), in Docket R. 14-07-002.24 See the Settlement filed August28,2017 in Public Service Commission of Utah DocketNo. No. l4-
035-1 1 4.
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In Utah, Rocky Mountain Power (RMP) and a range of parties, including solar advocates,
reached a settlement under which RMP withdrew a proposal to increase fixed charges
and to implement a demand charge for residential customers who install DG. The utility
had justified this proposal with a cost-of-service analysis. The settlement provides for a
transition period during which there will be a defined export rate comparable to current
retail rates for new NEM customers. For delivered power during the transition period,
new NEM customers will continue to take service under their standard, otherwise-
applicable rate, and will remain in their present rate class.2t The future rates applicable to
these new DG customers will be adjudicated in future general rate cases.26 Export rates
after the transition period will be determined in a future proceeding in which parties can
submit testimony on reasonably quantifiable costs and benefits or other considerations.2'
The settlement includes a grandfathering period for existing NEM customers through
December 31,2035, with existing NEM customers allowed to remain in their current rate
class and subject to the rates adopted for that entire class.28
D. The DG Customer as "Prosumer"
The framework you have proposed and illustrated draws on benefit/cost analyses
used for other types of demand-side programs. But isn't there a crucial difference
between DG and other demand-side resources: DG is generation that at times can
supply power to the grid, whereas EE and DR only reduce the demand for power?
This difference exists, is important, and should be considered. DG located behind the
meter will both reduce the demand for power from the utility, and, at times, will supply
power to the utility. On-site storage units can supply stored energy to the grid at a
different time than when the power was produced. When a DG system or storage unit
produces more power than the on-site load requires, the excess is exported to the grid,
and the DG owner is no longer a consumer, but becomes a supplier (i.e. a generator).
at Section 25.
at Section 27.
at Section 30.
at Sections 12 and 13
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Some have applied a new label - "prosumers" - to DER customers in recognition of this
dual role.
A:
Does the fact that DG customers also export power mean that they make "bi-
directional" use of the grid, i.e. they use the grid more than a standard, non-DG
customer, as the Company's Mr. Angell argues?2e
No. Mr. Angell claims that "[a] net zero customer utilizes all aspects of Idaho Power's
grid during the hours they are consuming energy (including the generation, transmission,
and distribution systems) and utilizes the distribution system during the hours they are
exporting energy to the grid." This view confuses who is providing a service to whom
when the DG customer exports power.
The fundamental flaw in Mr. Angell's argument is the assumption that, when a solar
customer exports power to the grid, it is the solar customer who is taking service from the
utility. Clearly, the opposite is true: when a solar customer exports power to the utility,
it is the solar customer that is providing a service - generation - to the utility. Once the
exported power passes the DG customer's meter, the utilitv takes title to the exported
power. It is the utilitv that delivers the exported DG power to the DG customer's
neighbors. It is the utilitv that is compensated by the neighbors for the service that the
utility provides in delivering the DG exports to them.3o Thus, it is the utility and the
neighboring customer that use the distribution system to deliver the DG exports. The
DG customer is in no way responsible for the delivery of their exported power, has no
control over who receives their exports, and receives no compensation for the delivery of
the exports. DG exports are a service - generation - that the DG customer provides to
the utility at the DG customer's meter, and it is a service that ends at that meter when the
" Idaho Power testimony (Angell), at pp. 10-14.
30 Indeed, the utility charges and receives its full delivery rate from the neighbors when the neighbors'
meters roll forward and consume the DG exports, even though the utility needs to use only a small portion
of its distribution system to make this delivery. lt is the utility's use of DG exports to serve other nearby
customers that makes available upstream capacity that the utility then can use to serve other customers
and satisfu growing loads elsewhere without upgrades. The utility's use of DG exports thus allows it to
avoid both generation and delivery costs.
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utility accepts the DG exports into its distribution system. This is no different than the
generation service that any other third-party generator, of any size, provides to the utility
Accordingly, since the DG customer does not receive service from the utility system
when DG exports are delivered, the DG customer actually uses the distribution system
less than a regular non-DG customer of comparable size. It would be wrong to allocate
costs to DG customers associated with their exports and thus to charge them for the
distribution costs associated with delivering their exports. By doing so, the utility would
double-recover its costs to deliver the DG exports:
l. once from the neighboring customers to whom the utility actually delivers the
exports, and
2. again from the DG customer whose rate is wrongly and artificially increased by
the export-related delivery costs that the utility assigns to the DG class.
A:
In a recent proceeding concerning the rates for DG customers in Arizona, several of
the utility witnesses analogized net metering to a customer borrowing his neighbor's
car, then driving it both forward and backwards, such that the odometer reading
has not changed when the car is returned even though many miles of wear & tear
had been put on the car.3r Why is this analogy flawed?
This analogy fails to recognize that it is the DG customer that is providing a service when
it exports power. The correct analogy is that, when the DG customer imports power and
runs the meter forward, it is receiving a service from the utility which is analogous to you
borrowing your neighbor's car. When the DG customer exports power and runs the
meter backward, it is providing a service to the utility - with the correct analogy being
your neighbor borrowing your car. If your neighbor drives your car the same number of
miles that you drove his car, then both sides received equal value and no compensation
needs to be paid. The error that the utility witnesses made is to assume incorrectly that
when a DG customer exports power to the utility, the DG customer is somehow receiving
a service from the utility. The DG customer is not taking service from the utility - it is
3r See Arizona Corporation Commission (ACC) Docket No. E-01933 A-15-0322 (Phase 2 of the Tucson
Electric Power [TEP] rate case), TEP Rebuttal Testimony of Dallas Dukes, at p. 22; also, TEP Rebuttal
Testimony of Craig Jones, at p. 19. This testimony was served August 28,2017 .
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providing a service (generation) to the utility for which it is compensated by running the
meter backward.
So if a NEM customer ends up with a small, zero, or even negative bill at the end of
a month, does this mean that the NEM customer is not paying for the utility service
the customer is receiving?
Absolutely not. First, whenever the solar customer uses the utility system (by importing
power and rolling the meter forward), the solar customer pays fully for the use of the
utility system, at the same rate as any other customer. If the solar customer ends the
month with a small or zero bill from the utility, this is the result of crediting the customer
for the value of the power which the customer supplies to the utilitv (from exporting
power and running the meter backwards). These credits can offset the solar customer's
costs of utility service when the customer imports power and the meter runs forward.
However, these credits are not the result of the solar customer's use of the utility system;
instead, they are the means to account for the exported generation which the solar
customer has provided to the utility at the meter. Thus, the solar customer has paid fully
for all actual use which the customer has made of the utility system, even though the
customer's net bill at the end of the year may be small or even zero. The key public
the bill credits for
credit for those exports - and the upcoming benefit / cost study should be designed to
determine this - but this does not change the fact that the solar customer has paid fully
for his or her actual use of the utility system.
Does the utility incur costs to "stand by" to serve a solar customer when the solar
customer is exporting power to the grid?
No. The costs which the utility incurs to serve a solar customer are no different than
those it incurs to stand by to serve a regular utility customer whose usage for periods may
be very low - for example, in the middle of the day when the occupants of a house are
away at work and school - but who may suddenly impose a load on the system. As a
consumer, a solar customer looks like a customer who uses power in the morning,
evening, and at night, but who turns everything off in the middle of the day, as illustrated
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by the dashed "Load on the Grid" line in Figure 1. Such a customer may come home
unexpectedly in the middle of the day, turn on lights, a computer, and run an appliance,
and produce a sudden spike in usage. But these load fluctuations are something the
utility is well-prepared to serve on an aggregate basis, and the costs of such normal
"stand by" service are included in the utility's regular rates. Similarly, a solar customer
may suddenly impose a demand on the system if a cloud temporarily covers the sun in the
middle of the day. Again, however, this variability is manageable due to the small sizes,
large numbers, and geographic diversity of solar DG systems - for example, at the time
one PV system is being shaded, another will be coming back into full sunlight.32
A:
Doesn't the utility incur costs to store the excess kWh produced by NEM systems,
allowing the NEM customer to "bank" kWh which the customer uses later when the
meter is rolling forward?
No. Net metering does not involve the storage of electricity, or of energy in any form.
This idea is one of the common myths of net metering. Again, the NEM customer is both
a consumer and generator of electricity. When the NEM customer is a generator,
exporting power in excess of the onsite load, as a matter of physics that generation is
immediately consumed by nearby customers. In no way is the power stored for later use.
When the solar customer later consumes power from the grid - for example, after the sun
sets - the power used is generated and transmitted by the utility at that time. The fact that
NEM credits from exports are used to offset the costs of subsequent usage simply
represents an accounting transaction - offsetting a credit with a debit on the customer's
account by changing the direction that the meter is recording; it does not represent any
actual use ofthe grid to "store" or "bank" electrons or energy.
32 It is possible that, as solar penetration increases, the aggregate variability of all solar customers'
electric output may add to the variability of the power demand that the utility must serve, and impose
additional costs for regulation and operating reserves on the system operator. The costs of meeting this
added variability is one of the factors considered in solar integration studies. Generally, these studies
show that such costs are low at the current level of solar DG penetration. See, for example, Duke Energt
Photovoltaic Integration Study: Carolinas Service Areas (Battelle Northwest National Laboratory, March
2014), calculating that, with 673 MW of PV capacity on the Duke utility systems in2014, integration
costs are about $0.0015 per kWh. See Table 2.5 and Figure 2.51. lt is my understanding that Idaho
Power completed a Solar Integration Study in April2016 that calculated an integration cost of $0.56
per MWh, for projects beginning in 2018 at the Company's current solar penetration level of 301-400
MW.
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Q: But doesn't the DG customer, as a generator, derive some benefit and bear some
responsibility for the fact that the utility builds and maintains a T&D system that is
able to accept the DG customer's exported generation?
A: Yes. When a generator of any size - including DG - is seeking to connect to the T&D
system, it is the purpose of the interconnection process to ensure that the grid is able to
accept the new generator's exports to the grid. If a new generator seeks to interconnect to
the utility system in a location that does not have adequate capacity to accept the
incremental generation, then the generator must pay the system upgrade costs required to
provide adequate capacity. However, once they have interconnected, generators are not
required to pay for the delivery capacity that the utility then uses to deliver the
generators' output to the utility's customers. The ongoing delivery of power is a service
that the utility provides to its end use customers who consume power; it is not a service
that the utility provides to generators who produce power. The utility's interconnection
process determines whether the utility has adequate capacity to allow deliveries of
exports (and the generator must pay upfront for the necessary capacity if the utility does
not). Once it is determined that the utility has adequate capacity to accept the new
generation, the utility does not continue to charge the generator for delivery capacity on
an ongoing basis.
E. PURPAConsiderations
A:
Do most customers who install DG have status as "qualiffing facilities" (QFs) under
the Public Utilities Regulatory Policies Act of 1978 (PURPA)?
Yes. I am not a lawyer, but I have done a significant amount of work for QF clients, and
it is my understanding that renewable DG customers typically have legal status as "small
power producer" QFs under PURPA.33 As a result of DG customers' QF status, the
serving utility is required under this federal law to do the following:
33 For a customer installing a renewable DG facility with a net power production of I MW of less, it is
my understanding that the designation as a qualifuing small power production facility (and therefore a
QF) is automatic with no filing at the Federal Energy Regulatory Commission (FERC) required.
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. to interconnect with a customer's renewable DG system,. to allow a DG customer to use the output of his system to offset his on-site load,
and. to purchase excess power exported from such systems at a state-regulated price
that is based on the utility's avoided costs.3a
Q:
A:
These provisions of federal law are independent of whether a state has adopted net
metering. Thus, the adoption of NEM only impacts the accounting credits which the
customer-generator receives for power exports to the grid.
Does PURPA also have requirements concerning the sale of power from utilities to
QFs?
Yes. The rates for the sale of power from an electric utility to the QFs on its system must
comply with the FERC rules implementing PURPA. Generally, these rules specifr that
the rates for sales to QFs must be non-discriminatory. QFs have the right to purchase
supplementary power (defined as the power the QF needs beyond what the QF's own on-
site generator can supply) at rates which are just and reasonable, that do not discriminate
against QFs in comparison to the utility's other retail rates, and that are based on accurate
data and consistent system-wide costing principles.3s Significantly, the FERC rules
create a safe harbor against claims of discrimination to the extent that QFs pay the same
rates as similar customers:
Rates for sales which are based on accurate data and consistent
systemwide costing principles shall not be considered to discriminate
against ony qualifiingfacility to the extent thqt such rates apply to the
utility's other customers with similar load or other cost-related
characteristics.
The creation of separate DG/QF customer classes with distinct rates from other
residential and small commercial customers represents a move away from this safe
harbor. For example, residential customers who install DG (and thus who become QFs
and move into a possible new class of partial requirements, QF/DG customers) would no
34 The PURPA requirements can be found in 18 CFR $292.303.
" l8 CFR $292.305(a) and (b). Also see "What are the benefits of QF status?" on the FERC website:
http://www.ferc.eov/industries/electric/een-info/qual-fac/benefits.asp. Supplementary power is power
that the QF/DG customer regularly purchases from the utility in addition to its on-site production.
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longer be considered "similar" to, and may no longer pay the same rates as, other
residential customers.
Are there circumstances under which Idaho Power's proposed residential and small
commercial DG classes may be considered discriminatory under PURPA?
Yes. For example, as discussed above, if DG customers are charged costs to deliver the
generation that they export in addition to the delivery service which they take from the
utility, the resulting rates for DG customers could violate the non-discrimination
standards of PURPA. The cost-based rates for DG customers, like the rates for all other
customer classes, should be based on the service which the utility actually provides to
solar customers - in other words, on the delivered loads which DG customers take from
the Idaho Power system. Rates for DG customers that are set on any other basis may
violate requirements that the rates for sales to QFs (i.e. to DG customers) must not
discriminate against such customers. Establishing a separate customer class for DG
customers does not solve this problem for the utility. If no other partial requirements
customers of Idaho Power are charged or allocated costs based on the amount of power
that they export to the utility, then the utility cannot lawfully charge DG customers rates
that are calculated based on the power that the DG customers export to the utility.
How should Idaho Power set rates for DG customers?
Idaho Power should calculate the cost of service for all DER customers based on the
loads which the utility actually delivers to DG customers, just as the company does for all
other customers. Idaho Power's delivered loads include all solar customers' actual
demand on the system, including the effect of added demand when a solar system is out
of service or when it is cloudy. The delivered load data is the evidence-based, PURPA-
compliant foundation for allocating costs because it "reflects the probability that the [QF
customer] will or will not contribute to the need for and the use of utility capacity."36
'u 5"r 45 Fed. Reg. at 12228
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Q:
F. DERs Provide Distribution System Benefits.
Mr. Angell argues that increases in the installation of solar will reduce local
distribution infrastructure investment only in very limited circumstances. Please
respond.
Mr. Angell's conclusions are based on a study comparing solar output profiles to a single
selected distribution circuit in the Treasure Valley that serves primarily residential
customers.3' Ho*erer, I would draw different conclusions from this study than Mr.
Angell does:
. Figures 3 and 4 of the study actually show l0% reductions in circuit peak loads as a
result of the solar DERs. If load on the circuit is growing at2o/o per year, such
reductions in peak loads could defer an upgrade by at least four years.
Circuits serving a higher proportion of commercial loads would peak earlier in the
day, would be a beffer match for DG solar output, and could show even longer
deferrals.
a
a In the future, the pairing of solar plus storage, or solar plus demand response
technologies, has the potential to allow DER output to closely match distribution
substation or circuit needs, providing even greater distribution benefits than
illustrated in this study.
A:
Mr. Angell also asserts that any distribution benefits will be limited to the five-year
period in which Idaho Power plans distribution upgrades and expansions." Do you
agree with this point?
No,I do not. Many types of DERs have useful lives well beyond five years, and thus will
reduce peak loads on the distribution system for longer than five years. For example,
solar DG has a useful life of 20-30 years, today's commercial storage units are expected
to operate for l0 years, and energy efficiency measures can have lives in excess of 10
years. As a result, DERs can avoid future distribution upgrade costs that are not within
the shorter time horizons that utilities use for distribution planning. Similarly, new
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" Idaho Power testimony (Angell), atpp. 15-2038 lbid.,atpp. 18-19.
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independent wholesale generation (e.g. QFs) or customer-sited resources (e.g. DERs) that
are built today will impact the utility's future load and resource projections for the full
planning period in its next Integrated Resource Plan (IRP), and thus can defer or displace
generation resources that are not planned to be operational for many years.
Even within the shorter-term planning processes for distribution, utilities in many areas
of the U.S. increasingly are incorporating DERs as "non-wires altematives" that can be
less expensive than distribution upgrades. This represents a natural extension of the well-
accepted use of EE and DR resources to "manage" the growth of the demands for electric
energy and capacity, thus avoiding the need to build more generation and transmission
infrastructure.
A:
Have you conducted, or are you aware of, studies of the benefits of DG that have
looked at a broad range of load profiles across the distribution system and which
have found that DG can allow a utility to avoid significant long-term distribution
capacity costs?
Yes. The "Public Tool" benefit/cost model of renewable DG developed by Energy and
Environmental Economics (E3) for the California Public Utilities Commission ("CPUC")
includes a calculation of the benefits of DG in avoiding sub-transmission and distribution
capacity costs for the California utilities.3' This model begins with the utilities' long-run
marginal sub-transmission and distribution capacity costs, which are calculated through a
regression of at least 15 years of historical and forecasted T&D investments as a function
of peak demand. These avoided sub-transmission and distribution capacity costs then are
allocated to each hour of the year using a set of oopeak capacity allocation factors"
("PCAFs") based on hourly data on each utility's substation loads. The PCAFs are
hourly allocation factors that give a non-zero weight only to those substation loads that
are within l0% of the annual peak load at each substation, using this formula:
3e The CPUC's Public Tool model and the association documentation are available at
http://www.cpuc.ca.gov/general.aspx?id=3934. The marginal subtransmission and distribution costs are
shown in Lines 323-350 of the "Avoided Cost Calcs" tab; the PCAF allocation factors by TOU period are
listed in Lines 352-371 of the same tab.
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rc A F s (h) = Load s (h) -Thr e s hol d s k= 7 87 6 0 M ax [0, ( Load s k-Thr e s hol d s ) ]
where:
PCAF.(h) : peak capacity allocation factor for substation s in holur h,
Loadr(h) : the load for substation s in hour ft, and
Threshold, :90% of the substation s annual peak load.
All hours where the substation load is below 90o/o of the annual peak have a PCAF of
zero. The resulting hourly distributions of marginal sub-transmission and distribution
capacity costs are applied to the hourly output profile of solar DG resources to calculate
avoided sub-transmission and distribution costs. The resulting avoided sub-transmission
and distribution capacity costs are about $0.03 per kWh (not including avoided line
losses) for the three major California investor-owned electric utilities.
As another example from Colorado, we applied the same PCAF method to hourly
substation load data that we obtained from Public Service of Colorado (PSCo) for the 58
distribution substations at which a majority (55%) of the solar DG on the PSCo system
was installed. For each substation we developed the hourly PCAF allocation that
measures, in each hour, how close that substation is to its annual peak, for all hours with
loads within l|oh of the annual peak hour load. Figure 3 shows the resulting average
PCAF allocation for each hour of the day across all 58 substations, weighted by the
amount of solar DG installed at each substation. The figure also shows a typical south-
facing PV output profile for Boulder, Colorado. As the figure shows, the substation
peaks tend to occur later in the day, with the peak in the allocation around 7 p.^, due to
substations that largely serve residential load. We applied this allocation to the typical
hourly PV output profile for Boulder to determine the portion of PSCo's marginal
distribution capacity costs that DG can avoid. The result is that one kW of DG nameplate
capacity (south-facing) can avoid 0.23 kW of PSCo's marginal distribution capacity
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costs. This can be considered a measure of the "effective load carrying capacity"
(ELCC) of solar DG with respect to PSCo's distribution capacity costs.a0
Figure 3: PSCo Substation PCAF Distributton of Loads within l0% of Substation Peak
+Substation Load Distribution for Loads Within 10% of Substation Peak
PV Generation Profile
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Q:Do you have comparable data for substations on Idaho Power's system?
Yes. In discovery, the Company provided hourly loading data for 2016 for 12 substations
on its system for which it is undertaking upgrade projects. We derived an hourly PCAF
allocation based on the loads at these substations that are within l0% of the annual peak
hour load. This result is shown in the solid black line in Figure 4, which also shows the
hourly output profiles for south- and west-facing PV a"rrays in Boise. Based on our
analysis of this limited sample of substations, we obtained similar results to our PSCo
analysis. For these Idaho Power substations, one kW of DG nameplate capacity (south-
A:
40 Crossborder Energy, Benefits and Costs of Solar Distributed Generation for the Public Service
Company of Colorado: A Critique of PSCo's Distributed Solar Generation Study at 9-l I (December 2,
2013). This study was filed in Colorado Public Utilities Commission Docket No. l3A-0836E on behalf
of The Alliance for Solar Choice.
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facing) can avoid 0.22kW of marginal distribution capacity costs; one kW of west-facing
DG capacity avoids 0.31 kW of marginal distribution capacity costs.
Figure 4:
o%
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A:
Distribution Capacity Value of Solar PV
Based on Distribution PCAFs for 12 ldaho Powcr Substations
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--- South-facing PV
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PCAF-WId. Average for South-facing PV 122%l
How can DERs maximize the distribution benefits that they provide to the utility?
There are several ways to maximize these benefits. First, time-of-use (TOU) rates can be
designed that encourage DERS to reduce customers' loads and/or increase exports to the
grid during times when the local distribution circuit is expected to peak. For example,
looking at Figure 4, Idaho Power could design on-peak TOU hours and rates that focus
on late afternoon hours. This would encourage new DER customers to orient their solar
systems to the west, or to install on-site storage, so that DER output is maximized in the
hours when it is most effective at reducing peak distribution system loads.
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In addition, some distribution substations and circuits are closer to capacity than others,
and DERs installed on those constrained parts of the distribution system will provide
greater benefits than in other locations. In other words, there is significant variation in
marginal distribution costs by location, and constrained parts of the distribution system
will have marginal costs that are far higher than the system average. Figure 5 shows the
marginal distribution costs of the three large California electric utilities disaggregated by
distribution planning area (DPA).4' So-e DPAs have marginal distribution costs that are
significantly greater than other DPAs and larger than the overall system average. Studies
of other utilities in the U.S. also have demonstrated a wide range of marginal distribution
costs.a2 Table 3 shows similar disaggregated data for Pacific Gas & Electric (PG&E).43
PG&E's system average marginal primary distribution cost is $39.43 per kW-year (see
the bottom line of the table), but some of its divisions have much higher marginal
distribution costs. Thus, if DERs can be targeted to the parts of the system where they
are most needed, i.e. where marginal distribution costs are the highest, they can produce
significantly greater benefits than what are estimated using system-wide marginal
distribution costs.
4\ Energy & Environmental Economics, Worlahop Discussion: Caltfornia Locational Net Benefits
Analysis Update (September 20,2017 presentation in the New York REV process), at Slide 21 .42 lbid., at Slide 14.43 PG&E Testimony in CPUC Docket A. l6-06-013, Exhibit PG&E-9, Chapter 6, atp.6-2 (Table 6-1),
served December 2, 2016.
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2 Figure 5:
Distribution Avoided Costs by Planning Area ($/kW-year):
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Table 3: PG&E Marginal Distribution Costs by Division
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TABLE 6.1
MARGINAL DEMAND-RELATED PRIMARY AND
SECONDARY DISTRIBUTION CAPACITY COSTS
BY DIVISION AND SYSTEM AVERAGE
Line
Division
Primary
Distribution
$/PCAF KW
New Business
on Primary
Distribution
$/FLT KW
Secondary
Distribution
$/FLT KWNo.
1
2
3
4
5
6
7I
9
10
1',!
12
13
14
15
16
17
18
19
20
Central Coast
De Anza
Diablo
East Bay
Fresno
Humboldt
Kern
Los Padres
Mission
North Bay
North Valley
Peninsula
Sacramento
San Francisco
San Jose
Sierra
Sonoma
Stockton
Yosemite
System
$69.09
$35 65
$17.78
$19.99
$39.52
$73.97
$34.07
$56.49
$13.63
$29.42
$53.40
$31 79
$40.91
$40.41
$40.12
$30.65
s121.98
$33.36
$60 18
$39.43
$14.53
$19.66
$23.20
$18.07
$15.81
$14.20
$16.08
$14.41
$16.37
$14.62
s19.23
$14.02
$16 49
$19.69
$17.45
$20.07
$16.65
$'t 5.13
$15.63
$16.42
$1.04
$1.01
s1.56
$0.88
$'t.36
$'t.12
$1.23
$1.06
$0.97
$1.75
$'t.26
$1.06
$1.22
$1.52
$1.16
$1.25
$1.28
$1.34
$1.56
$1.25t
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III. PROVIDING CERTAINTY FOR DG CUSTOMERS
Idaho Power proposes that existing NEM customers should be able to stay under
current net metering rules (i.e. should be "grandfathered"), but only for a period to
be determined in a future rate proceeding.aa Please comment.
The utility suggests, but does not propose, that the period of grandfathering might be
based on the payback period for a residential solar facility in Boise, which the utility
calculates to be approximately 15 years.as From my review of the utility's 15-year
payback calculation,o6Idaho Power uses a simple payback calculation which
underestimates a realistic payback period by failing to discount the customer's future bill
savings. When the DG customer's time value of money is included in the bill savings
calculation by discounting future bill savings to recognize their present value, the realistic
payback period exceeds 20 years and thus is likely to require the full economic life of the
solar DG system.
oo Idaho Power testimony (Tatum), atpp.23-25.4s lbid.,atp.24.46 Provided in response to Vote Solar Request No. 48
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Q: What are your views on the grandfathering policy that the Commission should
adopt for existing NEM customers?
A: Grandfathering policy is very important, for both existing and new DER customers, given
the rapid changes occurring in the utility industry. DERs represent long-term economic
investments by utility customers in new clean energy infrastructure. Just as a utility will
not invest in new facilities unless it has a reasonable and certain opportunity to recover
those investments over the long term, with an adequate return, customers will be reluctant
to make long-term investments in DERs unless they have a reasonable understanding of
the economics and an acceptable level of certainty in those economics. Net metering has
been a successful policy nationally in large part because it is simple and understandable
for customers. Customers understand that the level of their rates will change under NEM,
and are familiar with how their utility rates have escalated in the past. A key to providing
the needed certainty for NEM customers is adopting a grandfathering policy that ensures
that DG customers can remain under the rules and rate structure that applied when they
originally made their investment, for the reasonable economic life of the system.
Q: What has been the experience with grandfathering policies in other states with
much higher penetrations of DERs?
A: Customers who have gone through the process to make the long-term investment to
install renewable DG or other types of DERs learn much about their energy use, about
utility rates, and about producing their own energy. Given their long-term investment,
they will remain engaged going forward. There is a long-term benefit to the utility and to
society from a more informed and engaged customer base, but only if these customers
remain connected to the grid.a1 As we have seen recently in Nevada, this positive
customer engagement can turn to customer "emagement" if the utility and regulators do
not accord the same respect and equitable treatment to customers' long-term investments
4't Emerging storage and energy management technologies may allow customers in the future to "cut the
cord" with their electric utility in the same way that consumers have moved away from the use of
traditional infrastructure for landline telephones and cable TV. Given the important long-term benefits
that renewable DG can provide to the grid if customer-generators remain connected and engaged, it is
critical for regulators and utilities to avoid alienating their most engaged and concemed customers.
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in clean energy infrastructure that is provided to the utility's investments and contracts.
As the experience in Nevada showed, what customers do not like is unexpected changes
in the fundamental structure of NEM that substantially undermines the economics that
they had depended on when they made the investment. Generally, regulators in states
with high-penetrations of solar DG have uniformly adopted grandfathering policies that
allow existing NEM customers to remain under the rules and rate structure that applied
when they originally made their investment, for the reasonable economic life of the
system, i.e. for at least 20 years. This includes grandfathering policies adopted in
Arizona,as California,ae Hawaii,so Ne* Hampshire,tt *d Nevada52 when each of these
states has made changes in the terms and conditions of NEM.
Q:What is your recommendation for the NEM grandfathering policy that the
Commission should adopt with respect to solar DG?
The Commission should establish a clear policy that existing NEM customers will be
allowed to remain under the rules and rate structures3 in effect when they originally
applied for interconnection with the utility, for a2}-year period beginning on that
application date. This grandfathering period is based on the reasonable economic life of
a solar DG system. Finally, the customers eligible for grandfathering should be those
who submit applications for interconnection on or before the date that falls 60 days after
the Commission's decision implementing the change to net metering. I oppose the
Company's proposal to make the date of eligibility for grandfathering retroactive to
48 See ACC Decision No. 75859, at pp 155-156.4e Califomia PUC Decision No. l4-03-O4l adopted aZ}-year transition period for existing NEM
customers, see pp. 2 and 38 (Ordering Paragraph No. I ). See
http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M089/K386/893861 3 I .PDF.s0 Hawaii PUC Order 33258 at pp. 164-165 determined that existing NEM customer' agreements will
continue. See
See New Hampshire Public Utilities Commission, Order No. 26,029 (June 23, 2017), at pp. 2 and 51.
See http://www.rqi.com/storv/money/business/2016/09/13/nv-enerey-solarcity-deal-erandfather-
residenti al-rooft op-solar-customers/903 06788/.53 Rate structure includes (l) the customer class for which the customer qualifies before installing the
DER and (2) the type of charge (energy [$ per kWh], demand [$ per kW], or fixed monthly [$ per
month]) used for each functional category of costs (customer, generation, transmission, distribution).
Rate structure does not mean the magnitude of the rate.
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January 1,20I8,s4 which means that customers now considering the installation of solar
would be forced to make a long-term investment decision without knowing the rules or
rate structures that will apply to them.
IV LIMITATIONS OF COST-OF-SERVICE ANALYSIS,
AND THE PROPER ROLE OF RATE CASES
a Idaho Power's annual net metering reports have used a cost-of-service analysis to
calculate an alleged "cost shift" from net metering. Please provide your view on
whether this analysis is accurate.
I have reviewed and support the critique of Idaho Power's NEM reports that Ms. Briana
Kobor is submitting on behalf of Vote Solar. In particular, for the reasons explained at
length above, the costs to serve net metered customers should be based on the service that
Idaho Power provides to them, which is measured by the delivered power that the utility
supplies, without including exported volumes (which are a service that the DG customer
provides to the utility). When this fundamental error is corrected, Idaho Power's
revenues per customer from serving DG customers appear to cover more of the utility's
cost of service than is covered by standard residential customers, by $ 145 to $ 175 per
customer per year. As Ms. Kobor notes, this analysis is only approximate and is not
based on a full cost-of-service study, because Idaho Power's present NEM analyses use
only incremental adjustments to a cost-of-service study that dates from its last rate case in
20tt.
A:
More broadly, cost-of-service analyses should not be used to evaluate the benefits and
costs of NEM or to determine whether net metering results in any type of "cost shift."
There are numerous reasons why cost-of-service analyses are inappropriate for these
purposes:
. Limited to a single test year. DERs are long-tern resources. Other resources
with long useful lives are not judged based on their impacts on ratepayers in a
single year. For example, a new utility generating plant or transmission line with
54 IdahoPowertestimony(Tatum), atpp.7 and25,proposingthatallcustomersthatrequestto
interconnect DG after this date will be placed in the new DG customer classes that the utility proposes.
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an economic life of 30-50 years is not judged based solely on its impact on the
fi rst-year revenue requirement.
The benefits of DERs are avoided costs; these are not the embedded,
historical costs used in COS studies. Avoided costs are, by definition,
counterfactual - they are costs that the utility never incurs because it procures a
service from another source. In the well-known formulation of avoided costs in
PURPA, "avoided costs mean the incremental costs to an electric utility of
electric energy or capacity or both which, but for the purchase from the qualifuing
facility or qualifuing facilities, such utility would generate itself or purchase from
another source."55 As a result, it is questionable whether avoided costs can be
measured accurately by the utility's embedded costs, which are not counterfactual
but are the historical costs which the utility actually has incurred. Basic
economics informs us that the more accurate way to measure avoided costs is to
calculate the utility's long-run marginal costs, which measure how the utility's
costs vary with the change in demand or supply that result from the addition of a
new long-tern resource such as DERs.
DERS produce certain direct, quantifiable benefits (avoided costs) for
ratepayers that are not included in embedded cost rates. These include
avoiding the risk of volatile natural gas prices. Another such benefit is avoiding
future compliance costs associated with reducing carbon dioxide emissions.s6
This is an avoided cost that can be reflected, when appropriate, in utility
Integrated Resource Plans and in the cost-effectiveness evaluations of other types
of demand-side resources.
Multiple perspectives. An embedded COS analysis focuses solely on whether
net metering is an equitable short-term allocation of existing costs among
different classes of ratepayers. It does not consider other important perspectives -
including the key long-term perspectives of whether DG is a reasonable long-term
investment for the DG customer, for the utility system, and for society as a whole.
It is the combination of all of these perspectives that constitutes the public interest
in net metering.
55 See l8 C.F.R. Part292.10l (bX6) (emphasis added).56 For example, Idaho Power's 2017 IRP, atp.l23,recognizes that "carbon-emission regulations in
some form are likely during the next 20 years." Idaho Power is also building the Boardman-Hemingway
transmission line to provide "access to the Pacific Northwest wholesale market and its attendant diverse
mix of low-cost energy resources and abundant zero-carbon energy." 2017 IRP, atp.l2l.
Beach, Tom - Dl
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a When and where should the Commission determine whether DER customers should
be placed into separate customer classes?
The first analysis should be a long-term benefit/cost analysis to determine whether DERs
are a cost-effective resource under current NEM policies. If they are, then there may be
no need for a near-term change in the compensation for DER customers. If there is a
need to adjust the rates applicable to DER customers to restore an equitable balance
among rate classes or types of customers, a rate case would be the correct forum in which
to make such changes. I support Mr. Tatum's statement that the Company expects to
request any modifications to the rates or compensation applicable to NEM customers in a
rate case.57 The Commission recognized in Order No. 32846 , atpage l2,that"dramatic
changes [in NEM] should not be examined in isolation but should be fully vetted in a
general rate case proceeding." That decision also found that the rate design changes
which Idaho Power proposed in that case for net metering customers should be addressed
in a rate case:
To the extent the Company wishes to increase the monthly customer
charge, or implement a BLC for the residential and small general service
customer classes, it shall raise that issue in a general rate case.s8
Where should the Commission determine whether to have separate rate classes for
DER technologies?
Rate cases also are the place to determine whether separate customer classes should be
created. Extensive load research data to characterize different customer classes is
produced as a matter of course in rate cases, data that may not be readily available in
other proceedings.
Rate cases also will be the correct forum to respond to the proliferation of the many types
of DERs technologies or potential combinations of DER technologies. Different DERs
or combinations of DERs can produce significantly different load profiles and annual
usage. For example, the pairing of solar with storage can shift the output of the DER
system to exactly the time period when this output is most valuable to the utility system,
A:
Beach, Tom - Dl
Sierra Club - 39
57 Idaho Power Testimony (Tatum), at p.22.58 See Order No. 32846, at p. 12.
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increasing the value of the DER output. A proliferation of rate classes for all of the types
and permutations of DER technologies would be confusing to customers and
cumbersome for the utility to administer. A better approach is to develop cost-based,
time-of-use (TOU) rates that signal more accurately to customers the cost consequences
of any possible changes to the profiles of the delivered loads that the utility serves. Such
a time-sensitive rate design, in conjunction with net metering, is the best and most cost-
based means to accommodate a wide range and combination of DER technologies.
A:
Is it possible, and even likely, that a detailed cost-of-service analysis conducted in a
rate case will show that DG customers are less expensive to serve than standard
customers?
Yes, and this is what is shown in Ms. Kobor's revised analysis of Idaho Power's costs to
serve existing NEM customers. The installation of solar DG can result in reductions in
the DG customer's delivered loads in system coincident peak hours in the summer
months that are 40Yo to 60%o of the DG system's nameplate, even though the annual
capacity factor for the DR array is much lower, about 20o/o. This results in a much lower
allocation of production and transmission costs, per kWh, to solar DG customers than to
standard customers. There also can be substantial reductions in DG customers' usage in
the hour of the class coincident peak, resulting in a reduced responsibility for distribution
costs. As an example from another state, in the Arizona Public Service (APS) rate case
litigated earlier this year, the parties debated whether solar DG customers are more or
less expensive to serve than standard non-DG customers, under a standard cost-of-service
analysis.se The solar parties showed that residential solar customers are less expensive to
serve, so long as such DG customers are allocated costs only for the power that the utility
delivers to them, and are not charged inappropriately for the costs of delivering solar
exports to other customers. That case was resolved through a settlement, approved by the
5e It is important to note that this rate case was conducted after the Arizona commission had established
a new Value of Solar methodology for compensating solar customers. See ACC Decision No. 75859.
That methodology is being implemented in subsequent individual utility rate cases, including this APS
rate case.
Beach, Tom - Dl
Sierra Club - 40
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Arizona commission, in which residential DG customers will be able to take service
under the same TOU rate available to other residential customers.60
If DER customers indeed are less expensive to serve, then it is beneficial for non-
participating ratepayers to keep DER and non-DER customers in the same class.
Does this conclude your direct testimony?
Yes, it does.
60 See ACC Decision No. 76295 (August 18,2Ol7) in Docket No. E-01345A-16-0036 (Arizona Public
Service rate case). The settlement agreement is Exhibit A to that decision. See Sections 17-19 of the
settlement, allowing residential DG customers to take service under the same TOU and demand-based
rates available to other residential customers. For new DG customers that elect the residential TOU rate,
there also was a small increase in a pre-existing monthly grid access charge.
Beach, Tom - Dl
Sierra Club - 41
CERTIFICATE OF SERVICE
I hereby certify that on this 22nd day of December, 2017, true and correct copies of the
above THE DIRECT TESTIMONY OF R. THOMAS BEACH were sent to the following
persons via the methods noted:
Hand delivered and emailed:
Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
472W. Washington St.
Boise, ID 83702
diane.holt@ puc.idaho.gov
(original plus nine copies)
Emailed:
Idaho Power Company
Lisa D. Nordstrom
Timothy E. Tatum
Connie Aschenbrenner
l22lW.Idaho St.
PO Box 70
Boise,Idaho 83707
lnordstrom @ idahooower.com
dockets @ idahooower.com
ttal.um @ idahooower.com
cashenbrenner @ idahopower.com
Commission Staff
Sean Costello
Deputy Attorney General
Idaho Public Utilities Commission
472W. Washington
Boise, Idaho 83702
sean.costello @ nuc. idaho. sov
Idahydro
C. Tom Arkoosh
Arkoosh Law Offices
802 W. Bannock Street, Suite 900
PO Box 2900
Boise,ID 83701
tom.arkoosh @ arkoosh.com
erin.cecil @ arkoosh.com
Idaho Irrigation Pumpers Association,
Inc.
Eric L. Olsen
ECHO HAWK & OLSEN, PLLC
505 Pershing Ave., Ste. 100
PO Box 6119
Pocatello,Idaho 83205
[e-mail]
Anthony Yankel
l27OO Lake Ave. Unit 2505
Lakewood, OH 44107
Email: tony @ yankel.net
Idaho Conservation League
Matthew A. Nykiel
PO Box 2309
102 S. Elclid{2}7
Sandpoint, ID 83864
mnvkiel @ idahoconservation.ors
Ben Otto
7l0N6thStreet
Boise, ID 83701
Ph: [phone] x 12
Fax: [phone]
botto @ idahoconservation.org
Auric Solar, LLC
Elias Bishop
2310 S. 1300 W.
West Valley City, UT 84119
Telephone: (801 ) 878-3363
elias.bishop @ auricsolar.com
Preston N. Carter
Deborah E. Nelson
Givens Pursley LLP
601 W. Bannock St. Boise, ID 83702
Drestoncarter@ sivensnurslev.com
den @ sivensourslev.com
City of Boise
Abigail R. Germaine
Deputy City Attorney
Boise City Attorney's Office
105 N. Capitol Blvd.
P0 Box 500
Boise, ID 83701-0500
agermai ne @ cityofboi se.org
Idaho Clean Energy Association
C. Tom Arkoosh
Arkoosh Law Offices
802 W. Bannock Street, Suite 900
PO Box 2900
Boise, ID 83701
tom.arkoosh @ arkoosh.com
erin.cecil @ arkoosh.com
David H. Arkoosh
Law Office of David Arkoosh
PO Box 2817
Boise,ID 83701
[e-mail]
Vote Solar
David Bender
Earthjustice
3916 Nakoma Road Madison, WI 53711
dbender @ earthj ustice.org
Briana Kober
Vote Solar
36022nd Street., Suite 730
Oakland, CA946I2
[e-mail]
Snake River Alliance and Northwest
Energy Coalition
John R. Hammond, Jr.
Fisher Pusch LLP
101 5. Capitol Blvd., Suite 701
P0 Box 1308
Boise,ID 83701
[e-mail]
Electronic service only:
Snake River Alliance
wwi I son @ snakeri veral I iance.org
NW Energy Coalition
[e-mail]
Intermountain Wind and Solar, LLC
Ryan B. Frazier
Brian W. Burnett
Kirton McConkie
50 East Temple, Suite 400
P0 Box 45120
Salt Lake City, UT 84111
[e-mail]
[e-mail]
I
Intermountain Wind and Solar, LLC
1952 West 2425 South
Woods Cross, UT 84087
dou s @ imwindandsolar.com
dale @ imwindandsolar.com
Y$\tu $Pn*a
Kelsey Jae Nunez
Attorney for Sierra Club