20180126Kobor Rebuttal.pdf

BEFORE THE IDAHO PUBLIC UTILITIES
IN THE MATTER OF THE APPLICATION OF
IDAHO POWER COMPANY FOR AUTHORITY
TO ESTABLISH NEW SCHEDULES FOR
RESIDENTIAL AND SMALL GENERAL
SERVICE CUSTOMERS WITH ON-SITE
GENERATION.
RECEIVED
coMMISfdEInru as PH 12, oT
lL},.liu ruBI-lc'lT ll-i'i l:.:l; coFlr,{lssl0N
CASE NO. IPC.E-17-13
REBUTTAL TESTIMONY
OF BRIANA KOBOR ON BEHALF OF VOTE SOLAR
JANUARY 26,2018
Table of Contents
I INTRODUCTION I
2 STAFFAND INTERVENORS AGREE ON TWO FUNDAMENTAL ISSUES .,,.,....7
2.1 CusroupRs sHouLD BEABLE To REDUCE BEHTND-THE-METER coNSUMprroN wrrHour
DISCRIMTNATION 8
2.2 THp CouursstoN sHouLD Nor MAKEANy cHANGE ro Scueoulp 84 uNrr FURTHER
STUDY ....9
3 RESPONSE TO THE DIRECT TESTIMONY OF STAFF t2
3 . I STAFF, S ANALYSIS SUPPORTING THE CONCLUSIoN THAT THERE IS No EVIDENCE To
JUSTIFYA SEPARATE RATE CLASS T.On NEM CUSToMERS ........ t2
3.2 SrAFF's eUALITATTvE REVTEw oF cosr-cAUSATIoN svNEM cusroMERS....r3
3.3 CousroERarroN oF SraFF's TLLUSTRATTvE pRoposAL To MoDrFy Scusour-s 84..........20
4 RESPONSE TO THE DIRECT TESTIMONY OF THB IDAHO IRRIGATION
PUMPERS ASSOCIATION 31
5 SUMMARY OF RECOMMENDATIONS 35
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a.
A.
1 Introduction
Please state your name and business address.
My name is Briana Kobor. My business address is 986 E Princeton Avenue, Salt
Lake City, UT 84105.
On whose behalf are you submitting this rebuttal testimony?
I am submitting this rebuttaltestimony on behalf of Vote Solar.
Did you submit direct testimony in this proceeding?
Yes. My direct testimony includes an introduction to Vote Solar and a summary of
my qualifications in addition to my substantive testimony and recommendations.
What is the purpose of your rebuttal testimony in this proceeding?
This rebuttal testimony responds to the direct testimony filed by intervenors and
the Idaho Public Utilities Commission ("the Commission") Staff ("Staff') on
December 22,2017.
Please describe how your rebuttal testimony is organized.
Following this brief introduction, the second section of my rebuttal testimony
identifies two significant areas of agreement among intervenors to this case. The
third section responds to the direct testimony of Staff. The fourth section responds
to the direct testimony of the ldaho Irrigation Pumper's Association ("llPA").
Finally, the fifth section summarizes recommendations I make in this rebuttal
testimony, in addition to the recommendations I outlined in my direct testimony.
Please summarize your findings.
After reviewing the December 22,2017 filings, I find that Staff and intervenors in
this docket largely agree on two significant issues: (l ) customers should be able to
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reduce behind-the-meter consumption without discrimination; and (2) Idaho
Power Company's ("ldaho Power" or "the Company") request to place net energy
metering ("NEM") customers in a separate rate class should be rejected in this
docket, and the Company, parties, and the Commission need further study priorto
any modifications to Schedule 84.
In addition, I supporl Staff s conclusions that the Company has not provided
evidence in this case to justify the creation of a separate rate class for solar
customers. However, while I do not understand Staff to be suggesting that the
Commission adopt any of its cost allocation examples in this docket, I do disagree
with some of Staff s assumptions in developing portions of its testimony.
Specifically, Stafls NEM customer subgroup non-coincident peak ("NCP")
measurement is not supported by the cost-causation basis Staffpurports to apply.
Rather than measuring NCP at the NEM-specific group peak, it is more
appropriate and more supported by cost-causation principles to allocate
distribution costs based on NEM customer demand at the time of the overall
residentialNCP due to the fact that NEM and non-NEM customers share
distribution equipment and costs are driven by the cumulative peak loads on that
equipment in the cost-of-service study. NCP is used in cost-of-service studies to
allocate costs of distribution equiprnent to large and diverse classes because it
often approximates the cost-causing peaks on the distribution equipment
dedicated to serving the large class. However, when equipment serves multiple
classes, or subgroups, the connection between peaks on the distribution equipment
and individual class or subgroup peaks no longer holds, and the connection
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between NCP and costs no longer exists. Since the Company serves NEM
customers from the same distribution system equipment as the larger non-NEM
residential class, the residential class'NCP as a whole approximates the cost-
causing peaks on the equipment and should be used to allocate those costs. There
is no connection, and certainly none in the record, between the NEM-subgroup
NCP and cost-causing peak loads on distribution system equipment.
I also found several apparent errors in Staff s calculated comparison of 2015
Demand Side Management ("DSM") avoided costs with the retail rate. When I
correct those errors, I conclude that Staff s direct testimony overestimated the
alleged over-payment to NEM customers. When corrected, the alleged $ 100.63
per customer per year over-payment is reduced to only $85 per customer per
year.l
I understand that Staff does not propose any modifications to Schedule 84 and
presents a calculation of hourly net billing with excess generation credited at an
avoided cost for illustrative purposes only. I agree with Staffthat no modification
of Schedule 84 should be made now, and find that any consideration of the merits
of Stafls illustrative proposal to be premature.
Staff s illustrative "placeholder" analysis purporting to demonstrate that NEM
customers are overcompensated for exported generation under Schedule 84 is
incornplete. That conclusion can only be accurately made after an analysis of the
long-term benefits and costs associated with distributed generation, which Staff
I Even with these corrections, I still find Staff s calculation incomplete for the reasons
described further in this testimony.
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has not yet conducted. In fact, to the extent evidence exists, as provided in Sierra
Club's direct testimony, the evidence indicates that benefits may exceed costs.
Until determining the long-term benefits and costs associated with NEM in a
future docket, the Commission does not have the requisite information with which
to evaluate whether or not NEM customers are overcompensated or whether any
change is needed to Schedule 84.
In addition, even if the Commission were to determine that Schedule 84 should be
modified after having a complete record on benefits and costs, Staff s illustrative
hourly net billing structure is only one of many possible responses, each of which
comes with potential administrative costs and complications. Implementation of
hourly net billing would be a complex change with many potential embedded
policy considerations that have not been and cannot practically be considered in
this docket. Indeed, Staff appears to have significantly modified the structure of
its net billing proposal in Dr. Morrison's second revised direct testimony, but has
not addressed this change in the testimony. This change in Staff s methodology
and the fundamental policy choices underlying it underscores why the current
docket is ill-suited to make any changes to Schedule 84. A comprehensive
evaluation of Stafls proposal, in addition to the full menu of potential
modifications based on the benefits and costs of each potential modification and
the many embedded policy considerations, cannot practically be considered in this
docket.
Additionally, Staff notes that NEM customers probably have a lower cost-of-
service than other customers, but Staffdoes not quantify the amount of the lower
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cost. I note the $85 per NEM customer "over-payment" for exported electricity
that Staff s framework alleges is less than the roughly $175 that NEM custorners
are over-paying in relation to the cost of serve them, on average, as estimated in
my direct testimony. This implies that even if one were to accept Staff s
placeholder analysis of the alleged "over-payment" for excess generation, the
NEM program, as a whole, may still provide a net benefit to non-participating
customers.
In addition, the overall small scope of the issue should not be overlooked. The
rate impact on non-participating customers is defined by Staff as de minimis.2 |
calculate that even if one accepts Stafls framework-which does not include that
NEM customers are currently paying more than their cost to serve under current
rates-the costs at issue from the alleged over-payment for NEM exports for an
average non-participating residential customer are only $0.015/month or
$0.18/year. This is not only small in absolute terms; it is small compared to many
actual cross subsidies that inherently exist in a diverse customer class like
residential customers.
As a result, I find that the Commission should give this issue due consideration,
including full consideration of the benefits and costs of Staff s illustrative
proposal as well as a range of alternatives to it, in a separate docket. However, if
the Commission were to ultimately adopt a policy similar to Staff s illustrative
hourly netting and avoided cost export rate, I recommend that the Commission
implement a cleaq forward-looking grandfathering policy that provides protection
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2 Donohue Di. l3:3-8 (Dec.22,2017).
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to existing customer investments and ensures that customers investing in new
distributed generation know the basic terms of their compensation when they
submit their application. In the case that Schedule 84 is modified, the Commission
should adopt a Grandfathering Deadline effective 60 days following the effective
date of an order that implements the new compensation method.
Finally, while I agree with IIPA that the Company's proposal to separate NEM
customers into a new rate class is premature, I also find that IIPA's direct
testimony confuses the difference between the services provided by Idaho Power
to its NEM customers and the services NEM customers provide to Idaho Power.
llPA's direct testimony also contains a number of recommendations with which I
disagree. These issues are described in detail in the body of this rebuttal
testimony.
Please summarize any additional recommendations you make in this rebuttal
testimony.
In addition to the recommendations I made in my direct testimony, I also
recommend the following in response to direct testimony filed by Staff and
intervenors to this case:
. The Commission should recognize the right of all customers to reduce behind-
the-meter consumption through any choices and technologies, without
discrimination, and any future discussion of modification to distributed
generation rates should focus on the compensation customer-generators
receive for exported electricity under Schedule 84.
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The Commission should find that it is premature to consider Staff s
illustrative analysis of hourly net billing at avoided costs and should defer
consideration ofany changes to Schedule 84 until after a separate docket
determines the benefits and costs of net metering. Only jf the Commission
decides to modify Schedule 84 after a future benefit cost analysis, should the
Commission focus on which of the full menu of potential modifications is
appropriate based on the benefits and costs of each potential modification.
Staffls "placeholder" is only one possible option, and has limitations not
addressed in this docket.
The Commission should instruct the parties that-to the extent the cost of
serving NEM customers is determined-distribution costs should be allocated
based on the broader class NCP because it more closely matches cost-
causation peaks than the NEM-subgroup NCP, which does not correspond to
cost-causing peaks.
2 Staff and intervenors agree on two fundamental issues
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Based on your review of the direct testimony filed by Staff and intervenors in
this docket, were you atrle to identify any significant areas of agreement?
Yes. After reviewing the direct testimony filed by Staff and intervenors on
December 22,2017, I was able to identify areas of agreement on two significant
issues: (l) customers should be able to reduce behind-the-meter consumption
without discrimination; and (2) the Company's request to place NEM customers
in a separate rate class should be re.iected, and there is a need for further study
prior to any modifications to Schedule 84.
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2.1 Customers should be able to reduce behind-the-meter consumption without
discrimination
a.Did you take a position in.your direct testimony on whether or not customers
should be able to reduce behind-the-meter consumption without
discrimination?
Yes. My direct testimony recommends that the Commission recognize customers'
rights (1) to choose the amount of energy to purchase from the grid, (2) to reduce
consumption of grid-supplied electricity by any combination of conservation,
efficiency, and self-production the customer chooses to implement on his or her
side of the meter, and (3) to lower utility bills and save money by reducing
consumption of grid-supplied electricity. As I note in my direct testimony, these
personal freedoms include the right to install solar generation equipment at the
customer's site and to safely interconnect to the utility grid without
discrimination.3
Did other parties to this proceeding take a position on this issue in their
direct testimonies?
Yes. Numerous parties including Staff,4 Idaho Clean Energy Association
("lCEA"),s Idaho Conservation League ("lCL"),6 Sierra Club,7 and Snake River
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3 Kobor Di. 50:20-51 :3 (Dec. 22,2017).
a Donohue Di.4:l l-18.
s King Di. 17:8-20 (Dec.22,2017).
6 Otto Di. 8:6-9 (Dec.22,2017).
7 Beach Di. ii (Dec. 22,2017).
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AllianceAllW Energy Coalition ("SRAfi!WEC";8 all took similar positions. In
support of their position, Staff stated:
Because it allows customers to offset their own consumption in the same
way that customers have always been able to offset their own electric
consumption through reduced usage, energy efficiency, natural gas and
wood space heat, and all other methods. The Company does not concern
itself with what happens on the customer's side of the meter for any other
customers, and I do not believe it appropriate in this case either.e
Similarly, ICL states: "All customers have a right to reduce energy consumption
behind the meter. Because reducing individual consumption is no different from
any other member of the customer class, policy consideration for distributed
energy systems should focus on excess energy only."l0
Do you have any recommendations based on this information?
Vote Solar agrees with the positions of Staff, ICEA, lCL, Sierra Club, and
SRAA{WEC on this issue. I recommend that the Commission's decision in this
case acknowledge the right of all customers to reduce behind-the-meter
consumption without discrimination and indicate that future discussions regarding
rate changes should focus on the compensation customer-generators receive under
Schedule 84.
The Commission should not make anv chanse to Schedule 84 until further
studv
Did you take a position in your direct testimony on whether the Commission
should reject the Company's request to place NEM customers in a separate
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8 Levin Di. 25:12-1 4 (Dec. 22, 2017).
e Donohue Di.4:l l-18.
ro otro Di. 8:6-9.
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rate class and whether further study is needed before considering any
modification of Schedule 84?
Yes. My direct testimony recommends that the Commission reject the Company's
proposal to place NEM customers in a separate rate class and suggests that the
Commission open a new docket to examine the long-term benefits and costs
associated with distributed generation in Idaho Power's service territory and to
use the results of such a docket to evaluate whether or not any changes are
necessary to the retail rate NEM program.ll
Did other parties to this proceeding take a position on this issue in their
direct testimonies?
Yes. Staff and every intervenor who filed direct testimony on December 22,2017,
recommend rejecting Idaho Power's proposed separate rate class, and instead,
recommend various methods to further evaluate distributed generation prior to
implementing any change to rates for NEM customers.
Do you have any additional response to the positions of other parties on this
issue?
Yes. I agree with Mr. R. Thomas Beach's direct testimony on behalf of Sierra
Club regarding best practices for evaluating the benefits and costs of distributed
energy resources.l2 Mr. Beach presents results from a recent Ratepayer Impact
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Measure ("RIM") test he conducted that included only a subset of the full benefits
and costs categories that the Commission should consider in a future analysis.l3
While I agree with Mr. Beach's use of the RIM test for the conclusions he draws
from it, I note that the more comprehensive cost tests Idaho employs for DSM
programs, such as the Total Resource Cost ("TRC") test, should also be
conducted. The RIM test offers a single, narrowly-focused assessment of benefits
and costs from the non-participating ratepayer perspective, but leaves out many
important considerations. The Regulatory Assistance Project highlights sorne of
the problems with the RIM in discussing its use for energy efficiency programs:
Very few, if any, states use the RIM test as the primary determinant of
cost-effectiveness for their energy efficiency programs, in part because it
can easily foster counterproductive outcomes. For example, a program to
install less efficient air conditioners would increase electricity
consumption, thereby reducing utility fixed costs per kWh and reducing
overall rates as a result. Accordingly, such an energy inefficiencv program
would pass the RIM test.la
It will be important that the Commission examine distributed generation from the
broader perspective of all customers in a future value of net metering docket.
Unlike the RIM test, the TRC and the Societal Cost tests consider benefits and
costs to all customers. The TRC test is limited to energy benefits and costs, while
the Societal Cost test includes non-energy benefits from a societal perspective.
Therefore, using the TRC and Societal Cost tests, in addition to the RIM test, is a
t3 Id. at I 3, Table 2. Mr. Beach also indicates that an update of this analysis, in a future
docket looking specifically at the benefits and costs of NEM, would likely demonstrate
additional net benefits when all categories are includqd.Id. 13:8-l l.
14 Jim Lazar and Ken Colburn, Recognizing the Full Value of Energt Efficiency,
Regulatory Assistance Project (Sept. 2013), at p. I 7, 17 n.27,
http:r'lr." lvi,v.rapon line.orgi u,p-coutentr'uploaclsr'20 I 6i 05irap-lazarcolburn - la-vercakcl:rapcr-
20 I i-scpt-9.pelJ. (emphasis added).
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balanced, multi-perspective approach. As I noted in my direct testimony, I expect
that a good faith undertaking to capture the full range of benefits of distributed
solar generation may result in a valuation of distributed generation above the
retail rate.ls
3 Response to the Direct Testimonv of Staff
How do you respond to the direct testimony filed by Staff?
I respond to three issues raised by Stafls direct testimony: (l) Staff s analysis
supporting the conclusion that there is no evidence to justify a separate rate class
for NEM customers; (2) Staff s qualitative review of cost-causation by NEM
customers; and (3) Stafls illustrative example of one possible modification to
Schedule 84.
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12 3.1 Staff s analysis supporting the conclusion that there is no evidence to iusjfra
l3 separate rate class for NEM customers
a. What is your response to Staffls direct testimony that there is no evidence to
justify a separate rate class for NEM customers?
A. I agree with Staff s conclusion that there is no evidence to support segregating
NEM customers into a separate rate class. In support of this conclusion, Dr.
Michael Morrison examined load data from NEM and non-NEM residential
customers and found "there are no meaningful differences between net metering
and non-net metering customers in the quantities of electricity used, differences in
conditions of service, time, nature, and pattern of use."l6 I reviewed Dr.
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r6 Morrison Di. 4:25-5:4 (Dec.22,2017).
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Morrison's direct testimony on the average consumption patterns of NEM and
non-NEM customers and agree with his conclusions on this issue.
Staff s qualitative review of cost-causation by NEM customers
Did Staff conduct any cost-based analysis of NEM customer consumption?
Staff did not conduct any cost-based analysis of NEM customer consumption, but
did discuss the "consumption characteristics that cause the Company to incur
fixed costs."l7 Staff defines cost-causing consumption characteristics as
contribution to coincident peak ("CP"), group NCB and individual peaks.l8 In the
most recent cost-of-service study the Company conducted in latest general rate
case, the Company allocated costs to customers based in part on various measures
of CP (namely the 3CP/l2CP method) as well as class NCP.le It does not appear
that individual customer peaks were used as an allocator in the most recent study;
therefore, a comparison of this measure is not relevant to cost-causation.20 While
a comparison of only the relative magnitude of consumption at the time of system
CP and total class NCP (without also looking at the relative total consumption and
revenues paid by those customers) provides only a limited view of the cost
difference among groups of customers, it does provide some useful context.
When comparing NEM and non-NEM customer demand at the time of system
peak, Stafffound that NEM customers consumed less at the time of system
peak.2l Based on this finding, Staff noted:
t7 Id. at l6:17-18.
t8 Id. at 16:17-20.
re Larkin Di., Exhibit 30, pp.4-8, CaseNo. IPC-E-l l-08 (June 1,201l)
20 Id.
2r Morrison Di. l8:10-14.
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Power consumed at coincident peak is an important component of the
Coincident Peak factor used to allocate fixed generation and transmission
costs in Cost-of-Service studies. Had the Company performed a Cost-of-
Service Study, it would likely have allocated slightly less generation and
transmission plant cost to net metering customers. Given the large fraction
(94%) of residentialnet metering systems using solar generation, it isn't
surprising that summertime coincident peak consumption of net metering
customers is reduced.22
While I do not believe that this comparison tells the whole story of the
relationship between NEM customer demands as well as generation and
transmission costs,23 I generally agree with Staff that solar reduces contribution to
CP demand and therefore costs. Because solar generation operates at the time of
Idaho Power's system peak, solar generation contributes to meeting demand at the
hours in which it is most valuable for production and transmission-related costs.
This phenomenon is recognized in the analyses I conducted in my direct
testimony and should be fully recognized in any future cost-of-service study that
examines NEM customers.
Do you agree with Staff s use of NCP demand for distribution cost
allocation?
While I generally agree with Staff s characterization of class NCP demand as an
important cost-causing characteristic of a large class served by distribution
equipment dedicated primarily to that class, I disagree with the way in which Staff
has measured class NCP for the NEM customer subgroup. Dr. Morrison notes that
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22 Id. at l8:14-24.
23 The relationship between NEM customer demands as well as generation and
transmission costs must be examined in the context of a full cost-of-service study where
costs are allocated based on consistent allocation factors and compared with revenues
received to determine whether or not the studied class of customers is paying its fair
share of costs under current rates.
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"[a]s a group, net metering customers peak during the winter rather than during
the summer"24 and finds that NEM custonters'average NCP was greater than that
of non-NEM customers.2s While Dr. Morrison is simply comparing consumption
data-to the extent that such a comparison may be used to examine NEM
customers in a future cost-of-service study, the cost-related implications of this
comparison should be considered before applying the NCP for NEM customer
cost allocation.
While class NCP is a common and well-.iustified allocator for distribution-related
costs for alarge customer group-like the residential class as a whole-the reason
for using that allocator is important. Class NCP is used to approximate peak
loading on substations, main feeders, and other equipment serving primarily one
class. Specifically, residential class NCP is supposed to approximate the peak
loading on distribution equipment serving primarily residential customers and
because peak loading is the cost-causing activity, NCP approximates cost
responsibility for the equipment. This methodology works when distribution
equipment loads are driven by the primary customer class served by them. While
there are certainly exceptions, residential customers tend to be served by common
feeders, and likewise, commercial and industrial customers may be served by
different feeders than residential customers. This is expected, given how cities and
towns are typically organized and the fundamentally different types of customers
that comprise the residential and industrial classes.
2a Morrison Di. (Rev.) l9.5-6 (Jan. I I , 201 8).
2s Id. at 19:2-5.
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In contrast to the residential class as a whole, the NEM customer subgroup is not
served by dedicated feeders. Residential NEM customers are typically located
throughout residential areas and contribute to the local area loads in conjunction
with non-NEM customers located in the same area of the distribution system.
That is, distribution equipment cost-causation is the peak load on the equipment
serving both NEM and non-NEM customers; NEM customer cost causation is
those customers'contribution to the peak loads on the shared equipment, not the
peak of the NEM subgroup occurring at another time and day. If solar customers
are to be examined in a cost-of-service study, their distribution costs should be
allocated based on their load contribution at the time of peak loading on the
distribution equipment serving them, which is at the general residential NCB not
at the NCP unique to the NEM customer subgroup. The cost-causing peaks on the
distribution system equipment serving NEM customers will be at the period of
overall residential class peaks, not the time of the dispersed NEM-subgroup NCP.
According to Staff,, the NEM customer subgroup reached their collective peak on
December I 8, 2016, at the hour ending at 9:00 a.m., while the residential class
reached its peak on July 26,201 6, at the hour ending at 7:00 p.m.26 Staff
compared the average residential peak on July 26 to the average NEM customer
peak on December 18.27 As explained above, these are not comparable for cost
26 This definition of class NCP differs slightly from the residential class NCP defined by
the Company in Kobor Di., Exhibit No. 902, Response to Request No. 57b. Because this
section was developed in response to Staff s direct testimony, I adopt Staff s definition in
this section.
27 Morrison Di.l6:22-24; Morrison Di. (Rev.) 16:21-25.
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causation. In response to discovery on this topic, Staff explains the basis for
looking to NEM customers'NCP as follows:
In an idealized cost allocation scenario, the costs of distribution equipment
would be allocated based on each group's contribution to the peak loading
of each distribution plant component; however, because this would require
a separate analysis of each component, this is not always practical.
Outside of the idealized scenario discussed above, distribution plant is
often allocated based on each class' share ofnon-coincident peak.28
While I do not disagree with Staff s statement, generally, I disagree that the
premise leads to Stafls implicit conclusion that the NEM-related peak on a
December moming approximates peak loading on distribution equipment that is
shared by NEM and non-NEM customers alike or that it has comparable cost
causation to the residential peak on a July evening. Simply because "distribution
plant is often allocated based on each class'share of non-coincident peak"2e may
be true across a large class with equipment serving primarily that class, it does not
hold true when applied to a different peak by a subset of co-located customers
separated in a cost-of-service study but who are not served by different dedicated
equipment.
As I stated in my direct testimony, and consistent with the explanation above, the
NationalAssociation of Regulatory Utility Commissioners ("NARUC") Electric
Utility Cost Allocation Manual indicates that local loads are major factors in
sizing distribution equipment, and it is as a consequence of this fact that class
NCP is used to allocate the costs associated with these facilities.30 It is unlikely
28 Staffs Response to Vote Solar's First Set of Data Requests ("Staff to VS"), Response
to Request No. 5c (Jan. 16,2018). Attached hereto as Exhibit No. 903.
2e Id. luxhibit No. 903).
r0 Kobor Di. 6l :8-62:7 (citing NARUC, Electric Utility Cost Allocation Manual, pp.96-
e7 (tee2)).
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that the NEM customer peak on a December morning approximates local area
peak demand that drives distribution investment. Those customers are disbursed
across the utilities' system and served from equipment dominated by the loads of
non-NEM customers. It is the peak demand of non-NEM customers, who vastly
outnumber the NEM customers served from distribution equipment serving both
subgroups, that will drive local area peak demand that the NCP is intended to
approximate.
Notably, while Idaho Power's cost-of-service analyses erroneously allocated
distribution costs based on NEM customer exports in addition to consumption, the
Company does correctly allocate costs to loads at the time of the overall
residential class NCP, not the NEM-specific NCP occurring at a different time of
day and season.
If NCP is correctly measured for both NBM and non-NEM customers at the
time of the residential class NCR how does the distribution system cost-
causing usage compare?
According to Staff, when demand at the time of residential NCP (July 26,2016, at
the hour ending at 7:00 p.m.) is measured for NEM and non-NEM residential
customers, NEM customers consumed an average of 2.351 kW while non-NEM
customers consumed 2.992 kW.3l Thus, despite their larger than average total
consumption, at the time the distribution system serving NEM customers was
rnost constrained (because it was also serving non-NEM customers) NEM
customers had lower distribution system loads. This suggests that distribution
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costs of NEM customers are lower than non-NEM customers because distributed
generation helps to reduce the loading on local distribution facilities, thus
reducing the need for upgrades and wear and lowering system costs.
What does Staff conclude based on their comparisons of consumption data?
Staff concludes:
Had the Company performed a Cost-of-Service Study, it is difficult to
determine whether it would have allocated more or less distribution plant
to net metering customers than to non-net metering customers. I should
reiterate that these differences are quite small relative to the total
variability among Schedule I customers. Had the Company conducted a
Cost-of-Service study, it is likely that they would have determined the
differences in the overall costs of serving these two groups to be very
small.32
Do you agree with this conclusion?
While I agree with Staff that it is difficult to determine the level of costs that
would have been allocated to NEM customers versus non-NEM customers if a
cost-of-service study where to be conducted, the evidence from the consumption
data comparison illustrated above indicates that NEM customers should be
allocated less cost-of-service, on a per customer basis, as their consumption at the
time of the cost-causing peaks is lower than non-NE,M customers.
That said, I also agree with Staff s conclusion that a cost-of-service study would
likely demonstrate the difierences between costs related to NEM and non-NEM
customers are quite srnall relative to the total variability among Schedule I
customers. So, to surnrnarize: while NEM customers cost less to serve if separated
out in a cost-of-service study. the difference between NEM cost-of-service and
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non-NEM cost-of-service is likely no greater than the difference in cost-of-service
among many other potential subgroups within the larger customer classes.
3.3 Consideration of Staff s illustrative proposal to modify Schedule 84
a. Please summarize Staffs illustrative proposal to modify Schedule 84.
A. Ms. Stacey Donohue states
I also recommend that the Cornmission initiate a docket in which the
Company and interested parties can work together to determine the
compensation structure for excess generation based on the avoided cost of
the resource. When that process is complete, I recommend that the
Commission direct the Company to file a revised Schedule 84 reflecting
the agreed-upon avoided cost rate and the net-hourly metering.33
While Staff does not recomrnend modifying Schedule 84 in the present docket,
and explicitly recommends "a new docket be initiated to determine the avoided
cost value that most accurately reflects the value of this resource,"3a Staff goes on
to provide an illustrative proposal to modify Schedule 84 using 2015 hourly
avoided costs from the DSM program as a "placeholder."35
What support does Staff offer for its illustrative proposal to adopt hourly
netting and avoided cost credits in a future docket?
Dr. Morrison states:
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Net metering customers are being overcompensated for the energy that
they produce. The value of excess energy provided by net metering
customers is due, primarily, to the energy costs that it allows the Company
to avoid; however, net rnetering customers are effectively compensated at
full retail rates. As discussed earlier, Idaho Power's Schedule I and
Schedule 7 retail rates are substantially higher than the Company's energy
costs. 16
33 Donohue Di. 23:3- I 0.
34 Id. at l4:6-8.
3s ld. at I 5:9- I 0.
i6 Morrison Di. 9:20-l 0:3.
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Based on Dr. Morrison's analysis using "placeholder" costs, Staff characterizes
the difference between the "placeholder" costs and the retail rate as a "cost shift"
and a "current subsidy" and quantifies it at a level of $100.63 per net metering
customer per year.37 In other words, staff identifies the "cost shift" to NEM
customers to be the amount of an alleged. overvaluing of exported electricity from
NEM customers to the grid.
Do you agree with Staffs characterization of the difference between 2015
DSM avoided costs and retail rates as a "cost shift" and a "current subsidy"?
I do not for two reasons. First, Staff s conclusions based on this "placeholder"
analysis is not a o'cost shift" as typically defined. Second, the "cost shift"
calculation based on only one input is premature.
Please explain how Staff s presentation of the difference between the
"placeholder" costs and retail rates is a separate concept from a cost shift.
As commonly used, the term "cost shift" refers to a situation where one group of
customers pays less than the cost the utility incurs to serve them, based on
system-wide cost allocation principles, thereby leaving other customers in the
utility's service territory with the burden of paying those costs under rate of return
regulation. However, instead of focusing on the cost of service for grid-supplied
electricity to NEM customers, Stafffocuses on the compensation NEM customers
receive for the electricity they provide to the utility (exported electricity). This
credit value for electricity services provided to the Company is not an issue of
'ocost shift" (the cost of providing electricity to the NEM customer) but an alleged
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uneconomic costs in the Company's revenue requirement.
Have you identified any issues with Staff s calculation of the comparison
between 2015 DSM costs and the retail rate?
Yes. While reviewing Stafls workpapers provided in response to discovery, I
noticed that Staffused two avoided cost rates to value solar exports: one for all
exports in the summer months (June-August) and a second for the remaining non-
summer months.38 This approach appears inconsistent with the methodology Staff
described in response to discovery, which points to 201 5 DSM avoided costs from
the Company's 2013 Integrated Resource Plan ("lRP";.3e Unlike the two values
Staff used, the DSM Avoided Costs in the 2013 IRP have five different values,
which differ over two seasons (Summer and Non-Summer) and three hourly
periods (Peak, Mid-Peak, and Off-Peak). It is not clear how Staffderived the two
values it employed for summer and non-summer or why Staffdid not use the five
values provided in the 2013 IRP.
Because solar production varies throughout the day and year, and coincides with
higher cost periods, the two values applied by Staff do not accurately value solar
exports based on the proscribed DSM avoided costs. As a result, Staff undervalues
NEM exports and therefore overstates the difference between 2015 DSM costs
and the retail rate. I updated Stafls analysis to utilize the five periods actually
A
38 Staffto VS, Response to Request No. l, File "Net Metering Analysis_I71228," Sheet
"Residential," Cells "88883:C8883." This issue is also present in the revised workpapers
provided by Staff to parties on January 24,2018 in File "Net Metering
Analysis_l 80123.xlsx," Cells "B8883:C8883."
le Staffto VS, Response to Request No. 2 (Exhibit No. 903).
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provided in the 2013 IRP which Staffidentified in discovery as the applicable
avoided cost (2015 Summer On-Peak, Summer Mid-Peak, Summer Off-Peak,
Non-Summer Mid-Peak, and Non-summer Off-Peak). I also corrected two minor
Excel errors.40 The results are shown in Table I below, which corresponds to
Table I in Dr. Morrison's direct testimony.
Table 1: Vote Solar's Update to Dr. Morrison's Table I provided in Morrison's
Direct Testimony
After making these adjustments, the difference between what a NEM customer
pays with and without the Schedule 84 credit is $254.27 . Subtracting the
"placeholder" value of exports based on the DSM avoided costs (S169.36) leaves
a remaining difference of only $84.91. This is lower than the $100.63 presented in
40 Staff s original analysis of NEM customer usage contained in the workpapers provided
on January 16,2018, appears to have accidentally omitted some usage data in the months
of FebruaryandJuly. Inaddition,therewasaminorspreadsheeterrorrelatedtothe
calculation of residential usage by tier. While these issues appear to be largely corrected
in the Updated Workpapers that Staff provided on .lanuary 24,2018, one typo remains in
Staff s Updated Workpapers, which accounts for a rninor difference between Vote
Solar's bill calculation for "NEM with Schedule 84 Credit" and the calculation found in
Dr. Morrison's second revised direct testimony.
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AnnualAverage NEM Excluding
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NEM with
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NEM Staff
Proposal
kWh Consumed I 3,581 13,581 13,581
Excess kWh 3,644 3,644 3,644
Billed kWh I 3,581 9,937 13,581
Bill before Excess
Generation Credit
$ I ,265.08 sl,0l0.8l $ I ,265.08
Excess Generation Credit N/A N/A $ 169.36
Final Bill $ I ,265.08 $l ,010.81 $ I ,095.72
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Dr. Morison's direct testimonyal as well as the $137.25 presented in Dr.
Morrison's second revised direct testimony.a2' al
Are there any other changes in Dr. Morrison's second revised direct
testimony that impact the value of solar exports under Staff s proposal?
Yes. In the calculations underlying Staff s proposal in Dr. Morrison's second
revised direct testimony, it appears that monetized excess energy credits are not
allowed to offset the $5 customer charge and that custorners are not compensated
for the value of all of their exports in months where the credit for exports exceeds
the cost of deliveries.aa That is, despite being monetized, the credits for exported
electricity are not fully fungible because they cannot be used to offset the
customer charge, and any excess value during a month is forfeited, rather than
being applied as a credit to a subsequent month's bill. This methodology is a
change from Dr. Morrison's original direct testimony, in which monetized export
credits were allowed to offset the customer charge and the export credit values
were applied to the full volume of annual solar exports.
A portion of the alleged "cost shift" in Dr. Morrison's second revised direct
testimony ($ I 37.25) is therefore attributable solely to the change in methodology
between the original and second revised versions of testimony. Specifically, Dr.
A
ar Morrison Di. (Rev.) l2:5.
a2 Morrison Di. (2nd Rev.) l2:5 ([an.25,2018).
43 The sensitivity of the "cost shift" number in Staffls analysis to modifications to the
time periods and avoided cost values, as well as to spreadsheet errors, highlights how
sensitive the valuation of solar exports can be to minor changes in methodology and
inputs and further emphasizes the need to fully investigate the benefits and costs of
distributed generation through a dedicated docket.
aa Staffs Updated Workpapers, File "Net Metering Analysis_180123," Sheet
"Residential," Cells "F8883 :UX8895."
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Morrison's second revised directtestimony's $l16.80 value of Excess Generation
Credit excludes any value for exports in a month when the value exceeds the kWh
charge for deliveries that month. This new approach in Dr. Morrison's second
revised direct testimony is a non-trivial policy change from Stafls original
position but is not addressed in Dr. Morrison's second revised direct testimony.as
In my analysis in Table 1, I maintained Dr. Morrison's direct testimony
methodology and valued the full volume of solar exports. I do not adopt Stafl's
revised methodology from Dr. Morrison's second revised direct testimony
because it confiscates the value of monetized "avoided cost" energy credits at the
end of each month.
This change in Stafls methodology and the fundamental policy choices
underlying it (whether to fully monetize export credits and make the credits fully
fungible to offset charges) underscores why the current docket is ill-suited to
make any changes to Schedule 84. A comprehensive evaluation of Stafls
proposal, in addition to the full menu of potential modifications based on the
benefits and costs of each potential modification and the many embedded policy
considerations, cannot practically be considered in this docket. Moreover,
discussing any changes to Schedule 84 is, itself, premature.
Please explain why you find a conclusion regarding the need to modify
Schedule 84 to be premature.
Staff expressly states that no change should be made to Schedule 84 in the present
docket. I agree. Any consideration of the need for modification of Schedule 84,
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including Stafls illustrative "placeholder," in this docket is therefore premature.
Without the full benefit of facts from a complete analysis in a future proceeding,
consideration of hourly net billing or any other potential modification to Schedule
84 necessarily prejudges the facts and conclusions ofthat future proceeding. For
example, Dr. Morrison discusses the need to modify Schedule 84 and states:
"[t]he value of excess energy provided by net metering customers is due,
primarily, to the energy costs that it allows the Company to avoid; however, net
metering customers are effectively compensated at full retail rates."46 This
prejudges whatthe value of excess energy is, and reaches a premature conclusion
that an energy component is the "primary" value. A narrow focus on avoided
energy costs excludes the many value streams provided by the net excess energy
that NEM customers export to the grid such as generation, transmission, and
distribution capacity benefits, avoided line losses, grid security benefits, fuel
hedging benefits, and more. As demonstrated in the direct testimony of Mr. Beach
on behalf of Sierra Club, a more complete analysis may show that distributed
generation compensation at the retail rate undervalues rather than overvalues that
generation.aT
In fact, Staff acknowledges the need for a more thorough analysis that includes
the study of benefits and costs prior to determination of the resource value of
excess generation.as In her critique of the Company's proposal to study the
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benefits and costs of distributed generation only after implernenting rnajor
changes by separating rate classes, Ms. Donohue states:
Stakeholders were in favor of a study to determine the costs and benefits
of net metering, but the Company made no indication that it might conduct
the study after determining the need for separate rate classes. As a
participant in those meetings, it was clear that stakeholders were interested
in that study happening before a significant decision such as a rate class
determination or pricing change was proposed.ae
I find that the same critique could be applied to Staffoffering a "placeholder,"
even for illustrative purposes only, priorto conducting a full benefit-cost study as
stakeholders have consistently advocated.
Moreoveq in her response to the Company's proposal to separate customer
classes in the present docket to limit the issues in a future general rate case, Ms.
Donohue states: "Limiting or expanding a future proceeding is not the coirect
basis on which to determine creation of new customer classes. That decision
should be made based on evidence, not a desired process outcome."50 That is
correct.
While it appears that Staff is merely suggesting that a future proceeding include
the study of possible avoided costs rates for hourly net generation, the scope of
the future docket should not be limited to discussion of Staff s proposal. Rather,
the future docket should first address the preliminary question of whether to
modify Schedule 84 at all. The suggestion that Schedule 84 should be revised to
replace retail rate compensation with hourly netting at an avoided cost rate is one
possible modification that could be made to Schedule 84 in response to results
4e Id. at 19:18-25 (emphasis in original)
so Id. at2l:2-5.
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from a benefit-cost study, but this is not a change that should be prejudged absent
full information including the potential costs of such a proposal.
What are some of the costs of implementing hourly netting in Idaho Power's
service territory?
Replacing retail rate NEM with a net billing scheme will carry substantial
administrative costs such as a substantial increase to the quantity of billing data to
be managed, billing systems that may need to be updated, and the need to
calculate and to potentially re-calculate the export credit rate regularly. In
addition, as with any more complicated rate, the more complex compensation
structure will increase customer confusion, customer service calls, and time spent
educating customers. A recent study has shown that individual customers may
experience large variation in the proportion of their generated solar that is
exported to the grid, resulting in significant uncertainty as to the value of the
energy generated under hourly net billing.sl This will make the decision to invest
in distributed generation more complex and discourage some customers from the
investment; the confusion it causes will also likely increase calls to the Company
and the Commission with questions and complaints.
Even assuming Staffs suggestions that applying 2015 DSM avoided costs to
exports and the current retail rate credit demonstrates an over-payment to
NEM customers, do you still expect the benefits of implementing net billing
to outweigh the costs?
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5r Maddy Yozwiak, The Impact o.f Shorter Netting, Increased (Jncertainty.for Consumers,
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A.That is difficult to say as I do not have available information to quantify
administrative costs associated with program implementation, and without
information regarding the impact on the spectrum of NEM customers, it is
impossible to predict what the market impact may be. I can state, howeveq that
even under Staff s "placeholder" analysis, the total value of the alleged over-
payment is minimal.
After making corrections to Staff s calculation as described above, the alleged
over-payment is $85 based on the "placeholder" resource value of roughly
$0.046/kwh, which is roughly half of the average retail rate. This value is less
than the roughly $ I 75 per customer that I estimate NEM customers are currently
paying in excess of the costs to serve them.s2 Both of these values are
approximate, at best, because of the limitations inherent in trying to make these
calculations outside of a full general rate case. However, a comparison between
the two values indicates that NEM customers' over-payment of their fair share of
costs for the services provided to them by Idaho Power is more than double the
alleged over-payment for the excess generation they provide to the Company. This
implies that even if one were to accept Stafls "placeholder" analysis of the over-
payment for the exported electricity, the NEM program as a whole may still be
found to provide a net benefit to non-participating customers and therefore does
not justify any change to the current NEM program.
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Furthermore, Staff characterizes its own calculation of over-payments for excess
generation as de minimrs relative to class revenues.5l lndeed, with current
residential custorner adoption levels, the total alleged over-payment from
residential customers is only $84,485 per year under Staff s approach. This
represents a cost to the average non-participating customer of $0.01 5/month or
$0.18/year.s4 The cost shift from ruralto urban customers, ordual fuelto
electricity only customers, likely far exceeds the alleged NEM impact.
What do you recommend based on these findings?
Even if we accept the assumptions underlying the calculated impacts, the minimal
estimated impacts do not justify changes to ldaho's net metering policy at this
time. The Commission has time to conduct a thorough investigation regarding the
benefits and costs of distributed generation in Idaho prior to implementing any
change to rate class definitions or compensation under Schedule 84. As I stated on
direct, the reality remains that distributed generation penetration is still extremely
low in Idaho Power's service territory and is expected to remain low for decades
to come. The Commission should not accept any proposal to pre-define future
modification of Schedule 84. Rather, the Commission should evaluate Staff s
proposal for hourly net billing at an avoided cost rate only after conducting
s3 Donohue Di. l3:3-8.
5a For reference, if one adopts Staff s original calculation of a per customer over-payment
of $ 100.63/year as presented in their direct testimony, this would result in a total alleged
over-payment of $100,127 per year, which would impact the average non-participating
residential customer by $0.01 8/month or $0.22lyear. If one adopts the calculation in Dr.
Morrison's second revised direct testimony, the per customer over-payment of
$l37.25lyear would result in a total alleged overpayment of $136,564, which would
impact the average non-participating residential customer by $0.025/month or $0.29lyear.
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fufther study of the long-term benefits and costs associated with distributed
generation in a future docket.
a. In the event that the Commission approves hourly net billing at an avoided
cost rate in this proceeding, should existing customers be grandfathered?
A. Yes. While I do not support approval of any modifications to Schedule 84 in this
proceeding, should the Commission nonetheless approve such a proposal, I
recommend that the Commission implement a clear, forward-looking
grandfathering policy that will provide protection to existing customer
investments and ensure that customers investing in new distributed generation
know the basic terms of their compensation when they submit their application. In
the case that Schedule 84 is modified, the Commission should adopt a
Grandfathering Deadline effective 60 days following the effective date of an order
that implements the new compensation method. More detailed grandfathering
recommendations are provided in my direct testimony.ss
4 Resnonse to the Direct Testimony of the Idaho Irriqation Pumpers
Association
a. How do you respond to the direct testimony of IIPA?
A. I agree with Mr. Anthony J. Yankelthat the Company's proposal to separate NEM
customers into a new rate class is premature.56 However, I also find that his direct
testimony confuses the difference between the services provided by ldaho Power
s5 Kobor Di. 86:5-87:15.
56 Yankel Di. l2:18-21 (Dec. 22,2017).
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to its NEM customers and the services NEM customers provide to Idaho Power
and contains a number of recommendations with which I disagree.
Please describe how Mr. Yankel confuses the difference between the services
provided by Idaho Power to its NEM customers and the services NEM
customers provide to Idaho Power.
In discussing the minority of NEM customers who are "net zero customers," Mr.
Yankel states:
[T]he customer would only pay the customer charge, with no payment
made to reflect the fact that the generation, transmission, and distribution
facilities were all used to support the energy being brought to the customer
as well as distributing the excess energy that is made at other time. It is
intuitively obvious that such a customer is essentially paying nothing for
its use of the generation, transmission, and distribution system for every
hour during the month.sT
This characterization has two main problems. First, it looks to only a subset of
NEM customers: those who are net zero consumers. Second, it conflates the two
distinct streams of service, flowing in different directions, exchanged between a
NEM customer and the utility. During the hours in which a NEM customer
demands more energy than her distribution-generation system produces, she takes
delivery service from the utility and pays the retail rate for that service underthe
standard tariff. The fact that she may be "paying" by applying credits she earned
by providing electricity to the utility during other hours does not mean that the
electricity service she used was free.
During the hours in which a NEM customer generates more energy than is needed
behind-the-rneter, she provides exported energy to the utility grid at her meter and
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t4
l5
l6
l7
l8
19
20
2t
22
23
24
25
57 Id. at 6:l l-16.
2
J
4
5
6
7
8
9
l0
l1
t2
r3
t4
l5
t6
t7
l8
t9
20
2t
is credited for that service at the retail rate under Schedule 84. Contrary to Mr.
Yankel's statement, she does not use the generation, transmission, and distribution
system during the hours in which she exports energy. The NEM customer's
responsibility for exported energy ends at the point of her meter when ownership
of that energy is transferred to the utility. It is the utility that utilizes the grid to
bring that energy to nearby customers, and it is the nearby customers who
compensate the utility for the provision of that service.
Additionally, Mr. Yankel states: "The entire cost-of-service (cost and benefits)
needs to be addressed and then an appropriate rate design must be developed that
recovers costs (less benefits) in a manner that is understandable by all parties,
including the customers."58 This is incorrect to the extent Mr. Yankel suggests that
benefits associated with exported distributed generation belong in a utility cost-of-
service study, as exported generation is not a service provided by the utility. As I
recommended on direct, evaluation of rate design for distributed generation
should separately focus on (l) the cost to serve customer-generators for the
services that are provided to them by the utility; and (2) the appropriate
compensation for services that are provided by the customer-generator to the
Company.
Which of Mr. Yankel's recommendations do you disagree with?
I disagree with two of Mr. Yankel's recommendations: (l) his suggestion that a
subsequent proceeding should develop a unique allocation method for production
33
B. Kobor. Di-Reb
Vote Solar
a.
A.
58 Id. at7:10-12.
2
J
4
5
6
7
a.
demand and energy costs for NEM customers; and (2) that the subsequent
proceeding should take the form of a workshop.
Please explain the issue with Mr. Yankel's suggestion that a subsequent
proceeding should develop a unique allocation method for production
demand and energy costs for NEM customers.
Mr. Yankel appears to take issue with the fact that solar may not be generating
during specific winter peak hours and contends that:
The Workshop should develop a more granular differentiation of
production demand and energy costs for the Solar Net Metering
customers, because the number of customers generating excess are
significantly different between the various 9-months that the Company
defi ned as Non-Summer. 5e
There are two problems with this suggestion. First, the cost-of-service study in the
Company's latest general rate case included a production demand allocation
factor known as 3CP/I2CP. Under this method, customer class loads at the time of
system peak demand during each of the l2 months were considered in the
development of allocation factors associated with production costs. If solar
customers had a higher than usual demand during some winter months due to the
peak falling outside of sunlight hours, that would already be captured in the
allocation factor. Second, and most importantly, it appears Mr. Yankel is
advocating for the development of a production cost allocator unique to NEM
customers. Such an undertaking would be discriminatory to those customers.
Cost-of-service should be calculated for all classes and customers based on
consistent, system-wide principles. If there is a need to modify any aspect of the
34
B. Kobor, Di-Reb
Vote Solar
A.
8
9
l0
l1
t2
13
t4
l5
t6
l7
l8
19
20
2t
23
22
24
se Id. at 10.20-ll:2.
2
J
4
5
6
7
8
9
l0
ll
t2
l3
t4
l5
16
17
18
t9
20
2t
22
23
a.
A.
cost-of-service study rnethodology, it must be applied to all customer classes and
not only to a NEM-specific class.
Please explain the problem with Mr. Yankel's suggestion that a subsequent
proceeding take the form of a workshop.
While I agree with Mr. Yankel that future discussion of the long-term benefits and
costs should involve collaborative work between the utility and interested parties,
I do not believe that the complex issues at hand could be addressed exclusively
through a workshop. The Company, alone, holds much of the information and the
data necessary to determine the long-term benefits and costs. This information
asymmetry means it has an inherent advantage over all other parties. A
collaborative process, without the right to full discovery, testimony under oath,
and cross-examination to obtain and test information held exclusively by the
Company tends to extenuate that advantage. Rather than relying only on a
workshop process, I recommend a two-phase docket including evidentiary
hearings in order to produce a robust result that can be relied on by this
Commission in future rate determinations.
5 Summary of Recommendations
Please summarize your recommendations.
In addition to the recornmendations I made in direct testimony, I also recommend
the following in response to testimony filed by Staff and intervenors to this case:
. The Commission should recognize the right of all customers to reduce behind.
the-meter consumption through any choices and technologies, without
discrimination, and any future discussion of modification to distributed
35
B. Kobor, Di-Reb
Vote Solar
a.
A.
2
J
4
5
6
7
8
9
generation rates should focus on the compensation customer-generators
receive for exported electricity under Schedule 84.
. The Commission should find that it is premature to consider Staff s
illustrative analysis of hourly net billing at avoided costs and should defer
consideration ofany changes to Schedule 84 until after a separate docket
determines the benefits and costs of net metering. Only !f the Commission
decides to modify Schedule 84 after a future benefit cost analysis, should the
Commission focus on which of the full menu of potential modifications is
appropriate based on the benefits and costs of each potential modification.
Staff s "placeholder" is only one possible option, and has limitations not
addressed in this docket.
. The Commission should instruct the parties that-to the extent the cost of
serving NEM customers is determined--distribution costs should be allocated
based on the broader class NCP because it more closely matches cost-
causation peaks than the NEM-subgroup NCP, which does not correspond to
cost-causing peaks.
Does this conclude your rebuttal testimony?
Yes. It does.
36
B. Kobor, Di-Reb
Vote Solar
l0
ll
12
l3
t4
l5
r6
t7a
18 A.
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that I have this 26th day of Janu ary, 20 I 8, served the foregoing
REBUTTAL TESTIMONY OF BRIANA KOBOR ON BEHALF OF VOTE SOLAR upon
all parties of record in this proceeding, via the manner indicated:
Diane Hanian
Commission Secretary
Idaho Public Utilities Commission
472 West Washington Street
Boise, lD 83702
I ) iane. holtili)puc. idaho. gLrv
(Nine copies)
Electronic Mail
IDAHO POWER COMPANY
Lisa D. Nordstrom
Idaho Power Company
l22l West Idaho Street (83702)
P.O. Box 70
Boise, lD 83707
I nordstrorn (.4) illahopo rvcr.cotr
docketsi?; i d aho porve r.c o rn
Timothy E. Tatum
Connie Aschenbrenner
Idaho Power Company
l22l West Idaho Street (83702)
P.O. Box 70
Boise, lD 83707
ttat u m rllJ i d a lro porvc r. co rn
saug!.qtr b rerln sr a0d-ah epJ,i $,er.. Q !l m
COMMISSION STAFF
Sean Costello
Deputy Attorney General
Idaho Public Utilities Commission
47 2 West Washington (837 02)
PO Box 83720
Boise, lD 83720-0074
.coslcltt.r
FedEx and Electronic Mail
IDAHYDRO
Idahydro clo C. Tom Arkoosh, and
Idaho Clean Energy Association clo C. Tom Arkoosh
Arkoosh Law Offices
802 W. Bannock Street, Suite 900
P.O. Box 2900
Boise, ID 83701'lixr.arkoosh,l{i.;arkooslt. cont
I'.,rin.ccc i I irr',arkoosh.conr
IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.
Idaho Irrigation Pumpers Association, lnc.
Eric L. Olsen
ECHO HAWK & OLSEN, PLLC
505 Pershing Ave., Ste. 100
P.O. Box 6l l9
Pocatello, Idaho 83205
e l*r.iircc [t o lt alvli. r-:otlt
Idaho Irrigation Pumpers Association, Inc.
Anthony Yankel
12700 Lake Ave., Unit 2505
Lakewood, OH 44107
ulry
IDAHO CONSERVATION LEAGUE
MatthewA. Nykiel
ldaho Conservation League
P.O. Box 2308
102 E. Euclid,#207
Sandpoint, ID 83864
nr n) l( icl a idah()conssl'\ lrt i',n.r ,rr
AURIC LLC
Elias Bishop
Auric Solar, LLC
2310 s. 1300 w.
West Valley City, UT 841 l9
L l iq$i s hof .trau ri c so I Lrr. cr:!11
Preston N. Carter
Deborah E. Nelson
Givens Pursley LLC
601 West Bannock Street
Boise, lD 83702
prestoncartt:raii: givrn spu rs Ie)'.co rn
den iilqiven sp u rs I e \,. c on':
SIERRA CLUB
Kelsey Jae Nunez
KELSEY JAE NLINEZ LLC
920 N. Clover Dr.
Boise, ID 83703
l<c I sr;r::(rike I sey i aerr u nez.ct>tn
Tom Beach
Crossborder Energy
2560 9th Street, Suite 2l34
Berkeley, CA947l0
t<lm b(.)crosshorclcrcncfg),. conr
Zack Waterman
IDAHO SIERRA CLUB
503 W. Franklin St.
Boise, ID 83702
ZiL$h. lr,atenna nri?:sicrrac I u b.org
CITY OF BOISE CITY
Abigail R. Germaine
Deputy City Attorney
Boise City Attorney's Office
150 N. Capitol Blvd.
P.O. Box 500
Boise, Idaho 83701 -0500
aqel'lTlalllei{/iC It-vol'boise.org
Michael Heckler
3606 N. Prospect Way
Garden City, ID 83714
\4 ichasl.p.lrcck I errairgnrai I.conr
IDAHO CLEAN ENERGY ASSOCIATION
Preston N. Carter
Deborah E. Nelson
Givens Pursley LLC
601 West Bannock Street
Boise, ID 83702
prestoncru"teri'{tg ir,cn spu rs lc}..cr:nr
c.[eu rlr} qivenspu rs I ev.cour
VOTE SOLAR
David Bender
Earthjustice
3916 Nakoma Road
Madison, WI 5371I
dbender(a)earth ;r"rslrce.orII
Briana Kobor
Vote Solar
360 22"d Street, Suite 730
Oakland, CA94612
briana(*)voteso I ar'.org
SNAKE RIVER ALLIANCE AND NW ENERGY COALITION
John R. Hammond Jr.
Fisher Pusch LLP
l0l South Capitol Blvd., Suite 701
PO Box 1308
Boise, Idaho 83702iM
Snake RiverAlliance
rvn,i I son,Os na kcri v elal I i a uce.o rg
NW Energy Coalition
d i c gQ(J):y',cl-qlg)'.i) rg
INTERMOUNTAIN WIND AND SOLAR, LLC
Ryan B. Frazier
Brian W. Burnett
KIRTON McCONKIE
50 East South Temple, Suite 400
P.O. Box 45120
Salt Lake City, UT 84lll
rfraz ier(rk nr y^ I a* . co nr
bbu nretLi(Lrl< nr c la r!.co nr
Intermountain Wind and Solar, LLC
1952 West 2425 South
Woods Cross, UT 84087
d o u g({) inr-r} ir]ilan ci so l ar. coni
s/ Al Luna
Al Luna, Litigation Assistant
Earthjustice
Before the Idaho Public Utilities Commission
Case No. IPC-E-17-13
Vote Solar
Kobor, DI-REB Testimony
Exhibit No. 903
SEAN COSTELLO
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
P0 BOX 83720
BOISE, IDAHO 837?0-A074
[phone]
IDAHO BAR NO. 8743
IN THE MATTER OF THE APPLICATION OF
IDAHO POWER COMPANY FOR
AUTI{ORITY TO ESTABLISH NEW
SCHI,DULES TOR RESIDENTIAL AND
SMALL GENBRAL SERVICE CUSTOMERS
WITH ON.SITE GtrNERATION
CASE NO. IPC.E.I7.I3
STAtr'F'S RESPONSE TO VOTE
SOLAR'S FIRST SET OF DATA
REQUESTS
RTCEIVED
201$ JiH l5 PH 2: 25
',?liil:J*iffil8u,o*
Street Address for Express Mail:
47? W . WASHINCTON
BOISE, IDAHO 83702-59t 8
Attomey for the Commission Staff
BETORE THE IDAHO PUBLIC UTILITTES COMMISSION
)
)
)
)
)
)
)
Thc Staffaf the ldaho Public Utilities Commission responds as follows to Vote
Solar's First Set of Data Requests to Commission Staff.
REQUEST NO. l: Please provide all work papers to support all witness testimony you
filed in this case, including but not limited to all underlying data and analyses supporting any
numerical calculations, tables, andlor figures presented in your testimony. Please provide work
papers in native format with formulas and links intact. To the extent that statistical software,
other than Excel, was used in the development of your anaiysis please provide the log file, script
and,ior code written in the software language that was used, including the original data and output
data. Please eonsider this an ongoing request and timely provide any additional work papers
supporting additional testimony hled in this proceeding.
STAFF'S PRODUCTION RESPONSE
TO VOTE SOLAR JANUARY 16,2018
Exhibit No. 903
Case No IPC-E- I 7- l3
B. Kobor, Vote Solar
Page I of7
1
STAFF RESPON$B NO. 1: As described on pages 10 and I I of his testimony, Dr"
Morison used data provided by the Company through StafFs Production Request No. 8 in his
analysis of net metering consumption pattems. Dr. Morrison's calculation of net metering
consumption and billing under current rates and Staffs proposal can be found in ceils 88789
through 8895 of the "Residential" tab in the spreadsheet "Net Metering Analysis*171228.xlsx."
These cells have been highlighted in Blue.
Dr. Monison used data provided by the Company tluough staff s Production Request
No. 12 in his analysis of non-net metering consumption patlerns. Dr. Morrison's calculation of
non-net metering consumption and billing under current rates and Staff s proposal can be found
in cells E8790 through 88825 of $e "Regional Summary" tab in the spreadsheet "Non Net
Metering Analysis*171228.x1sx." These cells have been highlighted in Blue.
The data obtained from these spreadsheets, and used as the basis for Tables I and 2, and
Figures 2,3, Nrd4 of Dr. Morrison's testimony can be found in the spreadsheet
'oTestimonyGraphics*l7l228.xlsx." All three sprcadsheets are included in File Name ldaho
Power PR #l -- 3 on the CD produced with Staffs Response to Idaho Power Company's First
Production Request.
This response is sponsored by Idaho Public Utilities Commission StaffEngineer, Michael
Morrison, PhD.
REQUEST N0. 2: On page I l, lines ?-12Mr, Morrison's Direct testimony refers to
"2A16 DSM avoided cost rates" that were used to estimate an average net metering customerns
bill under Staffs proposal.
a. Please provide a reference to the docket number in which those rates were developed
and a reference to the Commission Order approving the rates.
b. Please provide e copy of the filing(s) relied upon to obtain the 2016 DSM avoided
cost rates used in Mr. Morrison's analysis.
STAFF RESPONSE NO. 2:
a. Dr. lvlorrison used the 2015 costs from the Company's 2013 IRP, Technicallndex
(Appendix C), Page 77, Docket No. IPC-E-13-15.
b. The Company's filing can be found at the Idaho Public Utilities Commission website:
S'I'AFF'S PRODUCTION RESPONSE
TO VOTE SOLAR JANUARY I6.20I8
Exhibit No. 903
Case No. IPC-E-17-13
B. Kobor, Vote Solar
Page 2 of 7
v
wwrv.puc.idaho.sovifilerooqlcases/elec{PQIPCEl3l5,'20130701IRP APPENDIX C
TECHNICAL INDEX.pDF.
This response is sponsored by Idaho Public Utilities Commission Staff Engineer, Michael
Morrison, PhD.
REQUBST NO.3: Please confirm that Mr. Morrison's statements on page 9,
lines I l-17, regarding a customer's "share" of costs and whether customers "are subsidized" and
on page 12, lines 5-7, regarding a "cost shift" are based on a comparison of a customer's bills to
the average per-customer cost of service, rather than a cuslomer's bills to that particular
customer's cost of service or that customer's load contributions to the class loads used to allocate
costs to the class in the cost of service study.
STAF'F RESPONSB NO.3: As stated on page 4 of Dr. Morrison's testimony, the
Company did not provide a cost of service study, so neither of these statemeilts is conect.
This response is sponsored by Idaho Public Utilities Commission Staff Engineer, Michael
Morrison, PhD.
RtrQUEST NO. 5: Please rsference page 15, lines i 7-20, and Table 2 of Mr. Morrison's
Direct.
a. Please identify the distribution plant component costs caused by the Net Metering
Group's non-coincident peak load.
b. Please identify the Net Metering Group's load at 7:00 prn on July 26,2016 (i.e.,
during the Non-Net Metering Croup's Non Coincidental Peak hour). Please provide this in the
same format as the data in'llable 2 (which appears lo be a per customer average).
c. To the extent that net metering customers share distribution equipment with non-net
metering customers, and the consumption characteristic that causes the Company to incur the
cost of that shared distribution equipment is &e peak load on the shared equipment, piease
explain why the nel metering customer group's non-coincidenl peak, rather than the group's
contribution to peak loading on the distribution equipment at issue, is an appropriate cost
causation allocator.
STAFF'S PRODUCTION RESPONSE
TO VOTE SOLAR tJ JANUARY I6. 20I8
Exhibit No. 903
Case No. IPC-E- I 7- I 3
B. Kobor, Vote Solar
Page 3 of 7
STAFF RESPONSE NO. 5:
a. The Company did not provide a cost of service study in this case, and Staff did not
perfbrm such an analysis, so it is not possible to provide the information requested by Vote
Solar.
b. The average net metering load for the hour ending at 7:00 pm on July 26th, 2016 rvas
2.35r kW.
c. Dr. Monison disagrees that Vote Solar's proposed allocator premise is appropriate. In
an idealized cost allocation scenario, the costs of distribution equipment would be allocated
based on each group's contribution to the peak loading of each distribution plant component;
however, because this would require a separate analysis of each component, this is not always
practical" Outside of the idealized scenaric discussed above, distribution plant is often allocated
based on each class'share ofnon-coincident peak.
This response is sponsored by Idaho Public Utilities Commission Staff Engineer, Michael
Morison, PhD.
REQUEST NO. 6: Reference Direct Testimony of Stacey Donohue, page 5, lines l-4
Please identify each of the capacity costs that are lowered by net metering customers.
STAFF RESPONSE NO. 6: The Company did not provide a cost of service study in
this case, so the specific capaciry costs which are lowered are unknown,
This response is sponsored by Idaho Public Utilities Commission, Technical Analysis
Prograrn Manager, Stacey Donohue, MPA.
REQUEST NO. 7: Reference Direct Testimony of Stacey Donohue, page 10,
lines I 5- l 7. Please confirm ( I ) that the re fere nce to a below average usage customer receiving a
subsidy is based on a comparison between below average usage sustomer bills and the cost to
serve a customer with an average load, and (2) that this stalement is not based on a cost of
service analysis for below average use customers as a class, or an analysis of the below average
usage customer's actual contribution to class loads during the hours to which costs ate allocated
to the class as a whole in the cost of sen ice study.
STAFI" S PRODUCTION RES PONSE
TO VOTE SOLAR .t{JANUARY i6.20I8Exhibft No 903
Case No. IPC-E-17-13
B. Kobor, Vote Solar
Page 4 of 7
STAFF Rf,SPONSE NO. 7: Neither of these statements were based on a cost of service
study because the Company did not provide such a study in this case.
This response is sponsored by ldaho Public Utilities Commission, TechnicalAnalysis
Program Manager, Stacey Donchue, MPA.
Dated at Boise, Idaho, this 7/2
,rL
day ofJanuary 2018
Costello
Deputy Attorney General
Technical Staff: lvlichael Morrison
Stacey Donohue
i umtsc prodrcq.;ipcc I 7 l3scmmsd rcsponsc lo Votc Solar prod rcq
STAFF'S PRODUCI'ION RESPONSE
TO VOTE SOLAR JANUARY 16.20I8Exhibit No. 901
Case No. IPC-E-17-13
B. Kobor. Vote Solar
Page 5 of 7
CERTIFICATE OT'' SERVICE
I HEREBY CERTITY THAT I HAVE THIS I6TIJ DAY OT'JANUARY 2018,
SERVED THE TOREGOING STAFF'S RBSPONSE TO VOTE SOLAR'S T'IRST SET
o$' DA:rA RTQUTSTS, N CASE N0. IPC-E-t7-t3, BY MAILINC A COPY
THEREOF, POSTAGE PREPAID, TO TI.IE FOLLOWING:
L]SA D NORDSTROM
REGULAI"ORY DOCKETS
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: [e-mail]
dockets@i dahopower.com
C TOM ARKOOSH
ARKOOSH LAW OFFICES
802 W BANNOCK ST STE 9OO
PO BOX 2900
BOISE ID 8370I
E-MAIL : tom.arkoosh@arLog$h.com
erin.cec i I (&arkoosh.com
ELIAS BISHOP
AURIC SOLAR LLC
2310 s 1300 w
W VALLEY CITY UT 84I19
E-MAIL: [e-mail]
ANTI{ONY YANKEL
I?7OO LAKE AVENUE
UNIT 2505
LAKEWOOD OH 44107
E-MAIL: [e-mail]
TOM BEACH
CROSSBORDER ENERCY
2560 gTH STR.EET, SUITE 213A
BERKELEY CA 94710
E-MAIL: [e-mail]
TIMOTHY E TATUM
CONNIE ASCHENBRENNER
IDAI{O POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: [e-mail]
caschenbrenner@idahoporver. com
MATTHEW A NYKIEL
ID CONSERVATION LEAGUE
102 s EUCLTD #207
PO BOX 2308
SANDPOTNT ID 83864
E-MAIL : [e-mail]
ERIC L OLSEN
ECHO HAU/K & OLSEN PLLC
PO BOX 6l 19
POCATELLO ID 83205
E-MAIL: [e-mail]
KELSEY JAE NTINEZLLC
920 N CLOVER DR
BOISE ID 83703
E-MAIL : [e-mail]
BLECTRONIp ONLY
MICHAEL HECKLER
mich ael. p. hcckler@.emai l. cory
ZACK WATERMAN
zack.waterman@.Si qrrac I ub.orp
CERTIFICATE OF SERVICTExhibit No. 903
Case No. IPC-E- I 7- I l
B. Kobor, Vote Solar
Page 6 of 7
ABIGAIL R GERMATNE
DEPUTY CITY ATTORNEY
BOISE CITY ATTORNEY'S
PO BOX 500
BoISE ID 8370t-0500
E-MAIL: [e-mail]
DAVID BENDER
EARTHJUSTICE
3916 NAKOMA ROAD
MADISON WI537I I
E-MAIL: [e-mail]
JOHN R HAMMOND JR
FISHER PUSCH LLP
PO BOX 1308
BOISE ID 83701
E-MAI L: i rh@fi sherpusch.com
RYAN B FR,{ZIER
BRIAN W BURNETI'
KIRTON McCONKIE
PO BOX 45120
SALT LAKE CITY UT 84I I I
E-MAI L: [e-mail]
[e-mail]
PRESTON N CARTER
DEBORAH E NELSON
GIVENS PURSLEY LLP
60I W BANNOCK ST
BOISE ID 83702
E-MA I L : prestoncarter@ giyg,rrsnursle.v, qom
den@ givenspursley. com
DAVID H ARKOOSH
LAW OFFICE OF DAVID ARKOOSH
PO BoX 28r7
BOISE iD 8370I
E-MAIL : david'Brarkooshlaw.g.om
BRIANA KOBOR
VOTE SOLAR
986 PRINCETON AVENUE S
SALT LAK-E CITY UT 84105
E-MAiL: [e-mail]
ELECTRONTg ONLY
SNAKE RIVER ALLIANCE
wu'i-lson@tsnakeriveral liance.org
NW ENERGY COALITION
dieeo@nwenergy,org
DOUG SHIPLEY
INTERMOLTNTATN WTND AND
SOLAR LLC
1953 WEST 2425 SOUTH
wooDs cRoss uT 84087
E-MAIL: [e-mail]
CSRTIFICATE OF SERVICEExhibit No. 903
Case No. IPC-E- I 7- I 3
B. Kobor, Vote Solar
Page 7 of 7
SECITETAR
Before the Idaho Public Utilities Commission
Case No. IPC -E-17 -13
Vote Solar
Kobor, DI-REB Testimony
Exhibit No. 904
I
I
I
JANUARY 2018
Lawrence Jones, Ghris Gould
Tanuj Deora, Erika Myers
Dave Christian, Don Clevenger
Maddy Yozwiak, Jan Vrins
Tom Flaherty, Hossein Haeri
,i
.:
Exhibit No. 904
Case No. IPC-E-17-li
B. Kobor, Vote Solar
Page I of4 ;
uln
t**
with N
Hvre
Ti
E
t
I 0
!
II
I
orfi the Pablie lnte'3stu
Cover photography: From left to right,
Energy CFo Bob Frenzel, Entergy CFo
Marsh and Ameren CFo Marty Lyons,
ln PUfr, lmpact
the Debate
AnTtcrGs
2? The Industry Globalized
LaurenceJones, EEI
2S Everyone Benefits
from EV Managed Charging
Thnuj Deora and Eriha Myers, SEPA
28 From RWE
Oliuer Reidel and Andre Richter, innogy Consuhing
32 Should FERC Reconsider
Policy Statement on
Pipeline Gertification?
Ken Costelh, National Regulatory Research Institute
38 Energy Efficiency -
The Art of Measurement
Hossein Haeri, Cadrnus Group
44 Book Review of
"Galifornia Goes Green"
Ahmad Faruqui, The Braxle Group
pur 0t0BAr HTERGY rout[TY $[srE$
48 Bright ldeas Deliver Affordable Lighting
By Marilyn Smitb, Execatiae Director EnAct
Has your organization ioined
the nearly two hundred mem-
bers of the PUF community to
impact the debate?
Jaruary )018 . Volrrne I 56, No, I
4 From the Editor: Ten Predictions for 201 8
a0ultsTA$N.1$
S CFO Roundtable - Part l!
Bob Frenzel, Xcel Energy; Marty Lyons, Ameren;
Drew Marslt, Entergl. V{tith Jan Vrins, Nauigant
't4 lnnovation Leaders' Roundtable - Part ll
Daae Cbristian, Dominion; Don Cleuenger, Oncor;
Chris Gould, Exelon; Bert Valdman, Optimum Energlr
(formerly at Edis on International).
Vith Tom Fkherty, Staugyy't
ESSAYS
52 The lmpact of Shorter Netting
Maddy Yozwiah, Vote Solar
54 Whither Section 2(b), That is the Question
Steue Goodman, PUF Tblecom Columnist
5CI The Smart Thermostat
John Hargroue, Association of Energ Seruices Profexionals
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Exhibit No. 904
Case No. IPC-E- 17- l3
B. Kobor, Vote Solar
Page 2 ol4
JANUABy 20 1 8 ii:r:::.::i l.:::i::: :t:ii ::..:,t:,:::,:,.. : :'. 3
Xcel
Drew
at our
recent CFO Boundtable. Photographer: PUF staff.
The 'net' in net metering and net
billing indicates that a customer is only
charged on the difference between their
total imports and exports for a period
of time. For example: I import ten, I
export seven, and I'm charged for three.
The 'netting period' simply defines
when this subtraction occurs.
For net merering, the imports and
exports are traditionally netted at the
end ofeach month. For the new net
billing arrangemenrs, however, utilities
have proposed reconciling the two at
much shorter intervals - every hour,
l$addy Yozwiak is the regulalory research
manager atVote Solar, a non-pmiit advancing
$0lar acce$$ at lhe state-l0vgl nallonvridr.
fifteen minutes, or even instantly.
These shorter periods increase the
variation in the amount o[ net exports
calculated across different customers'
bills. This is because a shorter period
can expose any real-time mismatches
between a customer'.s usage and produc-
tion. This match-up can vary signi6-
cantly between households. The result is
that an individual customer considering
whether to install solar has less certainty
about what their savings will be.
To illustrate rhis dynamic, Vote Solar
analyzed a sample of around twenty-four
thousand solar customers' usage in the
Arizona Public Service territory. The
range of net exports under an hourly
netting period varies by as much as
Exhibit No. 904
Case No. IPC-E-17-13
B. Kobor, Vote Solar
Page 3 of4
twenry-two percellr based on the cus-
tomer. -fhe average falls at forty-seven
percent ofsolar generation, but can be
thirty-seven percent (for the twenty-fifth
percentile) up to around fifty-nine per-
cent ([or the seventy-fifth percentile).
See Figure One.r
Similarly, exports assessed ol1
an instantaneous basis range from
thirty-five percent ar the twenty-fifth
Percentile to seventy-two percent at
the seventy-fifth percentile, with an
average offifty-five percent. Note that
the shorter netting period shifts the
distribution of net exports to the righr,
which results in more net exports rela-
tive to hourly.
The amount ofnet exports a cus-
tomer makes, under a net billing policy,
directly determines the value of their
solar generation. \When the credit for
any net exports is lower than the price
of any net imports, solar generation that
has a high percentage ofnet exports is
going to be worth less than solar genera-
tion with a smaller share.
For example, take a customer ol1 the
upper end of the APS sample, with a net
export percentage ofaround eighty per-
cent. If that customer had, instead, only
twenty Percent net exports, the value of
their solar generation would be 1.2 cents
per kilowatt-hour higher in the first
year, assuming an export rate of two
cenrs per kilowart-hour below retail.2
The impact of net exports on the
value of a customer's solar generation
depends on the export rate. The lower
the export rate, the lower the value of
solar generation, given a certain net
exPort Percentage.
See Figure'lwo.l
The distribution of customers' net
exports is going to be different for
each rrtility. For cxample. customers in
Michigan do not behave in the same
way as customers in Arizona, nor does
the sun shir.re in the same way in both
places. The analysis we've provided
should only be viewed as illustrative,
The Impact
of Shorter Netting
Increased Uncertainry fot Cousu"mers
By MnIoYYOZMAK
(l everal states - such as Nevada, Arizonaand Utah - recently replaced their
\ n., metering policies with a construct called net billing. The customer pays
\J rhe normal rerail rare for any net imports, and is credited at a second rate for
any net exPorts.
\ffhile much of the debate centered on the value of this export rate - is it at,
above, or below retail? - the new policies also changed a second, less obvious
aspect of net metering: the 'netting period' over which net exports or imports
are determined.
52 P$6,"1f i.*Ilil;rfs F0*{!,fii}iirt} JANUARY 201I
Nrr Exponrs (0/o 0r PRoDUGnoru), AP$ NEM Gusrourns,20lS
4,000
3,500
3,000
2,500
2,000
1,500
1,000
500
0
and not as representative of the impact
for another utiliry.
But the overall impact of shorter
netting periods is straightforward:
increased uncertainty. The basic ques-
tion for an individual considering
solar is, "Does this decision make
economic sense for me?" The answer
becomes significantly more difficult
to determine when hourly, fifteen-
minute or real-time historical usage
Endnotes:
l. Page I l5 ofKobor Phase 2 Surrebuttal
Testinrony in Docket No. E-01933A-15-0122 at
the Arizona Corporation Commission. http://
docket.images.azcc.gov/00001 82991.pdf.
2. This is not an I.COE analysis. \Ue are only esti-
mating the dollars per kilolvatr-hour value of
generatiorr in the first year.
3. Ttre 'retail rate' herc is the etluivalent volumetric
Hourly
I
t
10Yo 20Yo 300/o 40Yo 50o/o 600/o 70Yo 8070 90% '10070
Exports as a percentage ol solar production
Net exports, measured on an hourly and instantaneous basis, as a percentage of annual
solar production for APS NEM customers in 2015.
a low exporter, but because they wiil
not know for sure, they need to assume
a quarter oftheir generation could
swing either way.
The challenge for policymakers is to
deeply consider the practical implica-
tions ofshorter netting periods before
implementing. In particular, we high-
light rhree distinct areas to assess:
First, the distribution of net exports
for the customer base oFthe unique
utility in question must be calculated
to understand the range ofpotential
impacts on customers. The data used
in this analysis should be complete,
statistically significant for the applicable
customer group, and broadly available
to other stakeholders.
Second, data and metering infra-
structure requirements for more granu-
lar billing must be evaluated, to ensure
unnecessary costs afe not incurred with
shorter netting periods. Recent experi-
ence in Utah demonstrates this risk.4
Finally, the utility must give custom-
ers access to their usage information
at the same frequency as the netting
period, so that they can effectively
respond to price signals and manage
their usage. 0l
rccoverywill be similar in both qses. As a result,
rhe voluure ofdata can cause complications and
potential costs ifthe correct nretering inlrasrruc-
ture is not deployed. An example comes from
Rocky N{ountain Power in Utah, where fifteen-
minute netting rvas recently adopted. The meters
the utility plans to deploy to accommodare the
l5-min netting would not be AMR capable and
are expected to require manual monthly readings.
It
oEo
oo
oEEz
IIIIIt lnstantaneous,/
1Yo
:il.l'i ii,:r*ir l'lll
How much the value 0f solar generation (dollars per kilowatlhour) decreases by export percentage - assuming an export credit rate that
falls the given amount below retail.
must be crunched to estimate savings.
Never mind parsing how these values
can change over time, or overlap with
other policy changes.
Remember the twenty-two percent
variation under hourly netting seen ear-
lier in the APS sample? Another way to
think of this number is that the value
of nearly a quarter of customers' genera-
tion is uncertain. An individual could
be a high net exporter, or they could be
charge rhat a cusromer could offser via uer meter-
ing. The value ofsolar generation is the weighred
average ofthe inrport price and exporr crcdit,
given the net exporr percenrage.
4. Short netting periods increase the volume of data
the utility needs to collect in order to bill the cus-
tomer. A fifteen-minute netting period will
require four times as nrany dara poirrrs as rn
hourly netting period, even though the utility cost
Exhibir No 904
Case No. IPC-E- | 7- I 3
B. Kobor, Vote Solar
Pagc 4 of4
,,
0o/o t0%20o/o 3070 40Yo 50%60%71Yo B07o 90%10070
$0,01 $$(0.001)$(0.002)$(0.003)$(0.004)$(0.005)$(0.006)$(0.007)$(0.008)$(0.00e)$(0.010)
$0.02 $$(0.002)$(0.004)$(0.006)$(0.008)$(o.o2o)
$0.03 $$(0.003)$(0.006)$(0.00e)$(0.012)$(0.030)
$0.04 $$(0.004)$(0.008)$(0.0'r2)$(0.016)$(o.o4o)
$0.05 $$(o.oo5)$(0.010)$(0.0r5)$(0.020)$(0.050)
Export
rate is
$_/k\^Jh
below
retail
% of solar on is net ex
JANUABY 201 8 p*slr$ [n?i,"r{i*$ FflE}rs!&,r&,! 53
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