20221012Reply Comments.pdf

Kelsey Jae (ISB No. 7899)
Law for Conscious Leadership
920 N. Clover Dr.
Boise,ID 83703
Phone: [phone]
[e-mail]
Anorney for the Clean Energy Oppoftinities of ldoho
IN THE MATTER OF IDAHO
POWER COMPANY'S
APPLICATION TO COMPLETE
THE STUDY REVIEW PIIASE OF
THE COMPREHENSryE STUDY OF
COSTS AND BENEFITS OF
ON-SITE CUSTOMER
GENERATION & FOR AUTHORITY
TO IMPLEMENT CIIANGES TO
SCHEDULES 6, & AND 84
fiTC EIVED
tlii 0XT 12 Pt{ h: 35
;i-i:ii0 PUnLIC
I ili-i I ii:5 COi,{1,{lssl0N
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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cAsE NO. IPC-E-22-22
CLEAN ENERGY OPPORTUNITIES
FOR IDAHO. REPLY COMMENTS
CLEAN ENERGY OPPORTUNITIES FOR IDAHO . REPLY COMMENTS - IPC.E.22-22
$ Cf"on Gnergy Opportunltles for ldoho'
BEFORE TIIE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER COMPAI\IY'S
APPLICATION TO COMPLETE THE STUDY REVIEW
PHASE OF THE COMPREHENSTVE STUDY OF COSTS
AI\ID BEI\IEFITS OF ON-SITE CUSTOMER GENERATION
& FOR AUTHORITY TO IMPLEMENT CHANGES
TO SCIIEDULES 6,8, AI[D 84
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tPC-E,A}A2
Clean Energy
Opportunities for
Idaho - Reply
Comments
ln response to comments submitted by ldaho Power, PUC Staff and other parties to this docket on
or before September 21,has well as replies to Production Requests provided and the Order issued
in IPC-E-22-12 both occurring since September 216, CEO provides the fo!lowing reply comments.
ln their September 21,hcomments the Company revealed an intent to submit an updated VODER
document on or before October 26tr. Below CEO proposes 11 additions or clarifications that should
be addressed in that updated VODER as well as 3 procedural requests for additional meetings of
parties to discuss various topics that arise pursuant to resolution of matters raised in this docket.
CEO reply comments are organized around two primary matters:
1. Explanations for the changes CEO believes are needed in the updated VODER study the
Company plans to submit on October 25.h. These requested changes are hlghlighted in
yellow and identified below with the symbol and text "> VODER updates";
2. Recognizing the inherent interrelations between certain topics within the VODER analysis,
and absent clarity regarding the steps planned for the "recommendation/implementation
phase" of this docket, CEO notes our assumptions and presents some suggestions about the
follow-on process within the remainder of this docket. lnstances where CEO believes that
follow-on process step warrant a meeting of parties to discuss matters are identified with
the symbol & text ") Technical meeting" and are
CEO's reply comments are organized as shown in the table on the following page.
1 For example, decisions related to compensation structure such as only allowing ECR credits to be applied against the
custome/s billings inherently provide an economic incentive for customers to limit the size of their solar generation to
only produce an amount of exports that they can recover via bill offsets. Similarly, decisions related to monthly vs
hourly billing periods affect whether a time-variant ECR rate structure could possibly be implemented.
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CONTENTS
!. Export Credit Rate
4.l Avoided Energy Cost & 5.1 Frequency of Updates for Energy lnputs
a) lRP, ICE or ELAP as source of energy pricing data
blAveraging hourly ECR pricing data
c) Seasona!-diurnal Time Variant vs Flat annua! rate
d) Fuel Price Risk
4.2 Avoided Generation Capacity Costs
4.3 Avoided Transmission and Distribution Costs.
4.4 Avoided Line Losses
4.5 Avoided Environmental Costs
4.6 lntegration Costs
tl. Class Cost of Service (Chapter 7).
lll. Project Eligibility Cap (Chapter 9)
!V. Figure 10.3: Payback analysis of rooftop solar
V. Request for Clarification of Procedural Next Steps
ATTACHMENT 1 - lllustrative Calculations of Alternative Evaluations of Avoided T&D Costs
l. Export Credit Rate
4.l Avoided Enerfl Cost & 5.1 Freouenq, of Updates for Enerar lnputs
al lRP. ICE or EIAP as source of ener$ pricins data
The VODER study presents three data sources for possible use when calculating the Avoided Energy
component of any ECR:
t. IRP long-term hourly forecasts,
2. ICE Mid-C day ahead hourly forecasts and
3. EIAP - Location adjusted actual hourly EIM market values.
The originalVODER study displayed pricing information using historic data from allthree data
sources, with results suggesting these pricing sources produce roughly similar Avoided Energy
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values. However, comments by the parties and responses to production requests demonstrate that
using IRP forecasts can result in values dramatically different than actual market prices. The VODER
study needs to be updated to adequately inform the public and Commission of the magnitude of
difference between the most recent market prices and lRP estimates.
The substantial difference between IRP estimates and actual market prices was evidenced in recent
responses to production requests. Using data supplied in response to a production request for
2022 ELAP hourly prices through September of this year and PVWatts solar production estimates2,
CEO displays in the chart below the dramatic inaccuracy of the IRP hourly price forecasts for 2022
by comparing them to the actual market prices that have occurred thus far in 2022.
Staff comments highlight the inherent trade-offs that must be made when balancing goals of
accuracy, stability & predictability. Actual market prices provide a much more accurate reflection
of the true value of any exported energy - and thus are more fair to both the exporter and non-
generating customers - when compared to the often quickly outdated IRP forecast values. Staff
initial comments note that "!RP pricing is likely the least accurate". of three data sources.
lCVCrossborder comments also present evidence that using actual, recent market prices results in
values substantially different than those in the VODER study. As a result, lCVCrossborder note, the
pricing information displayed in the original VODER study needs to be updated to reflect the most
current data.
The Company statedThat they won't make substantive changes to the VODER in the updated
version they propose submitting on October 26.r. CEO is not suggesting a substantive change is
required, but we do think an update is needed to adequately inform the public and Commission
, To remove the effects of variations in load between weekdays and weekends, these data were calculated taking
average prices by hour each month and weighting those prices by monthly average solar production for the relevant
hour to produce a monthly average value to the system from solar production.
, lP C-E-22-22 Staff Com men ts, 9 I 2Ll 2022, at 8.
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actual market prices. To meet Commission direction for use of the most recent data", the
updated VODER needs to show how different (and thus more fairly reflective of the true
value provided to the IPC system) Avoided Energy values would be using either the ICE or
ELAP data sources of actual 2022 market prices than by using outdaled 2O22lRP forecast
values.
bl Averagine hourlv ECR pricins data
Trade-offs between accuracy, stability and predictability also arise when considering how
frequently ECR prices should change. Crediting exports with the unique market value existing at
the time of their export - 8750 separate hourly prices each year - is possible and could provide a
pricing with accuracy that makes for fairness to all parties but with low stability.
Annua! true-ups: The VODER displays annual prices based on weighting prior year hourly prices
according to hourly export levels. llPA noted that if an annual average price based on IRP forecast
hourly values were used, it could have a "true-up"r to adjust for annual variations. CEO does not
take a position on using an annual true-up approach, but notes that predictability and accurate
price signaling are poorly served by using inaccurate IRP prices which are likely to require surprising
customers with a year-end bonus or penalty true-up adjustment.
Number of years of data: Staff notes that using more years of historical data enhances stability,
though stability may come at the expense of accuracy. CEO believes that using market prices from
the prior year, with or without an annual true-up, provides a reasonable balance between stability,
predictability a nd accu racy.
set to change hourly (the 8750 alternative), averaged over the course of the most recent
year, or averaged over multiple years. The study should explain the trade-offs between
accuracy, stability and predictability that each alternative provides.
cl Seasonal-diurnalTime Variant vs Flat annual rate
Having long argued in favor of time-of-use pricing in other fora, in concept, CEO heartily agrees
with Staff's observations regarding the value for time-variant prices to influence customer choices
and behavior. However, there are substantive issues associated with establishing a time-variant
, lP C-E-22-22 I I PA com me n ts 9 I 2U 22 at 5
, Staff 9/21 comments at 8: 'The seasonal time variant method would provide price signals to incentivize customer
behavior to enhance grid reliability."
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rate structure for exports before implementing similar time and rate variance on the consumption
side.
At this time, CEO remains concerned by the artificial economic incentive created by asymmetrically
imposing on-peak/off-peak rates for exports while customers have no access to on-peak/off-peak
rates for consumption. Customers could be inappropriately incentivized to make investments
based on a rate structure where a kWh of export is worth substantially more than a kWh of
reduced consumption.
Additionally, CEO agrees with the concerns Staff raised that the VODER study does not show
"enough resolution to differentiate the avoided cost of energy; (between) the proposed "On-Peak"
and "Off-Peak" time windows. 6 Resolving the question of in which specific hours exports provide
substantially differing benefits also naturally arises when considering the potential for exports to
have a value for avoiding generation, transmission or distribution system capacity outlays.
As described more fully in the Avoided Capacity section below, CEO supports Staffs call for a
meeting of the parties to discuss capacity time variant value. CEO believes that discussions related
to the timing when exports can avoid capacity related expenses should naturally link to a discussion
of Time-variant compensation rates more generally.
CEO believes a holistic review of time-varying rates for consumption and exports should be a goal
of the next rate case, rather than a partial, export only, review within the VODER context. Based
on these concerns, CEO believes implementation of time-variant export rates should be deferred
until after a forthcoming rate case provides the venue for crafting symmetric Time of Use rates for
both exports and consumption.
with asymmetrically imposing on-peak/off-peak rates for exports before customers have
access to on-peak/off-peak rates for consumption. The update should also provide
additional clarity and/or a method for determining how "on-peak" and "off-peak" time
periods could be developed and applied consistently to rates for consumption and export
credits.
d) Fuel Price Risk
The Commission ordered the evaluation of fuel price risks within the VODER study.? The need for
inclusion of a fuel price hedge value was informed by evidence presented during IPC-E-?L-?L,
" Slaft 9l2L comments at 9
7 Order 35284 at 22:'The Company reviews energy and capacity needs. The Company's regular risk management
practices lock in fuel for energy production and dictate whether the Company enters into contracts to hedge prices
with physical orfinancial contracts. This process is already in place and looks out 18 months in advance. lt is reasonable
to evaluate fuel price risks."
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including the !nterstate Renewable Energy Council (IREC) "Checklist of Key Requirements for a
Thorough Evaluation of DSG Benefits".
A fuel price hedge value should be included. ln the past, utilities regularly bought natural
gas futures contracts or secured long-term contracts to avoid price volatility. The fact that
this is rarely done now and the customer is bearing the price volatility risk does not diminish
the fact that adding solar generation reduces the reliance on fuels and provides a hedging
benefit. s
CEO agrees with the City of Boise and |CL/Crossborder comments that the VODER study did not
sufficiently evaluate a fuel price hedge value and cannot accurately conclude the value to be zero.
CEO requests that -
methodologies for assigning value to this component of the ECR such as the Maine
Distributed Solar Valuation Study.
4.1.3 Firmness of Export Energv.
Though IPC-E-18-15 deliberations were confidential, issues associated with the non-firm
adjustment were thoroughly considered, and the Commission instructed that 'The work done in
this docket can and should be built upon in the next docket." (Order No 34509 at 7 and reiterated
in Order No. 34892 at 9).
The independent analysis provided by !CL/Crossborder. demonstrated that customer-owned
generation in ldaho Power service territory carries far less uncertainty than was associated with
resources from which the82.4% non-firm value was derived.
from IPC-E-18-15 that 10% is an appropriate reduction in energy value to reflect the non-
firm nature of energy provided by on-site generators and include this alternative valuation.
4.2 Avoided Generation Capacitv Costs
Measuring "On-Peak" exports: Staff comments note that the quantity of exports is more
accurately measured in real-time than hourly.'o Correspondingly, the true value of avoided capacity
is more accurately derived from calculations based on real-time rather than hourly exports.
e A Reguldtotts Guidebook: Colculoting the Benefits ond Costs of Distributed Solor Generotion, p36, by the lnterstate
Renewable Energy Council. This was presented in CEO's IPC-E-2L-21comments.
, Crossborder study at 2: The issue of the "firmness" of distributed solar is a matter of the time scale - on an individual
day, the amount of solar generation from an individual distributed solar system can be variable depending on the
weather. But the solar output becomes much more predictable as both the time scale and the number of distributed
systems increases. On an annual basis for an entire solar fleet, the amount of solar generation can be accurately
predicted with a relatively small uncertainty - much less than the uncertainty in hydro generation, for example.
,o Staff 9/2L/2022 Comments, at 6: The measurement on a real-time basis is more accurate than on an hourly basis.
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A policy decision regarding netting interval for billing purposes must consider tradeoffs between
accuracy and practical considerations. The contribution to peak calculation is not limited by those
same tradeoffs. CEO believes the percentage used to calculate contribution to peak should be as
accurate as possible, and that the calculation is independent of a what netting period is selected for
billing purposes going forward.
contribution to peak can be used to accurately calculate ECR capacity value components
even in the event an hourly netting period is selected for billing purposes.
Energy markets do not accurately reflect capacity value: Elsewhere within Staff comments is the
assertion that capacity value is embedded in on-peak energy prices - "The contribution of capacity
in the time-variant scenario is embedded in the energy actually delivered and does not require a
separate capacity contribution estimate as required in the flat annual rate scenario."r'
CEO strongly believes this assertion is incorrect. Participants in energy markets may find it to their
advantage to sell into the market whenever the incrementa! revenues received from that sale
exceed the incremental costs they incur to provide the energy. Those suppliers have no duty to
provide energy as needed the way an on-system capacity resource can. Capacity valuation should
reflect the full-cost of providing this "whenever needed" capability. Energy prices do not
necessarily reflect those full costs. Thus, CEO asserts that market energy prices during IPC's "on-
peak" periods do not accurately reflect the full value of both energy and capacity during those
hours.
On-peak houts warrant discussion: Additionally, within the parties' comments there are concerns
raised as to how the hours within "on-peak" periods are determined. ln addition to the NREL and
ELCC methods previously presented, ICL/Crossborder comments present the Peak Capacity
Allocation Factor (PCAF) alternative for determining the timing of capacity
requirements/contributions. CEO believes these topics warrant technical discussions among
interested parties.
4.3 Avoided Transmission and Distribution Costs.
The lCVCrossborder study combines two methodologies in order to value avoided T&D',:
a) The National Economic Research Associates (NERA) regression method, which correlates
ldaho Powe/s long-term transmission and distribution additions with changes in peak
load.
u Staff 9/21 comments at 9
.lCL9l2Ll2022 Comments, Crossborder Study Attachment, see p4-5 of study
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b) The Peak Capacity Allocation Factor (PCAF) method for determining capacity
contribution as an alternative to ELCC or NREL methodologies.
As reflected in the request for technical discussions mentioned immediately above, CEO
acknowledges that the methodology for determining capacity contribution (ELCC, NREL, or PCAF) is
a separate decision, which can result in very different values. The NERA method can be used in
combination with PCAF, NREL, or ELCC.
With regard to the methodology for determining avoided T&D costs, the NERA method is more
stable and accurate than the project-specific, all-or-nothing method used in VODER. The
Company's criteria are unreasonable to require that the quantity of the exports would need to be
sufficient to exceed the planning capacity shortfall for a specific project in order for any capacity
value to be assigned. Exports do contribute to the deferral of T&D and increase the probability that
costs can be deferred. Further, as described in prior commentsl3, the Company's all-or-nothing
approach can result in extremes.
As illustrated in Exhibit 1 below (see Attachment l for calculations), different analytical methods
can produce dramatically different estimates of the appropriate T&D capacity value. The VODER
study should display this range of alternate valuations.
Exhlbit {:Avoided T&D Gosts- Alternative Methodologies
$/MWh CrpssBoder: Applies a top down NERA rcgrerrlon method
combined with FCAF method for calculating capacity contribution
444IS]@E!$ rhe f, EnA r.ttt$lon
mcthod ls ussd to @rrelate avolded T&D osts yet
urer ELOC O l{iEt methods from VODER to
determlne capadty contrlbutlon
$11.e Sro.r
VODER W/ ELCC
ffiil
Regression w/ ELCC Regression w/ NREL Regression w/ PCAF
ldaho Powcr: Applies a
Bottoms-Up, All-Or-
Nodrlng approach to
deferredT&D combined
with EfCC method for
capacity contribution.
Flat rate, reaFdme.
tsCEO 9lzt Comments: lf a project-specific, all-or-nothing method is used, it can result in near zero values (as is the
case with ldaho Power's approach at this time) or could result in extremely high values (envision the straw that broke
the camel's back by requiring an expensive upgrade, and the cost assignable to that straw).
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option of utilizing the NERA method for valuing avoided T&D in combination with the ELCC,
NREL and PCAF methods for calculating T&D capacity contribution values.
4.4 Avoided Line Losses
Marginal, not average losses. The Commission ordered that line losses "are important issues to
study''and the study should include "the difference between using static or marginal losses and the
magnitude of each as part of the valuation to be included in the ECR."'o
Marginal avoided line losses are the established and appropriate methodology, as demonstrated in
A Regulatols Guidebook: Calculoting the Benefits and Costs of Distributed Solor Generotion rs CEO
agrees with |CL/Crossborder that the VODER study failed to provide an appropriate evaluation of
marginal avoided line losses.
4.5 Avoided Environmental Costs
As reflected in CEO's previous comments within this docket, CEO believes that the environmental
attributes of self-generator exports do tie to a measurable and avoidable cost impacting rates. For
example, ldaho Power currently purchases REC's (certified renewable energy credits) and resells
them to customers willing to pay a premium for renewable energy. Further CEO asserts that the
VODER study does not accurately reflect those avoided costs (or increased revenues) when it
assumes that all customers require REC certification of the renewable aspects of clean energy
attributes they purchase from the Company and that REC certification imposes administrative costs
that outweigh any potential benefit that could be attributed to renewable energy exports from
self-generators.
provide information related to the intricacies and requirements to obtain and track RECs,
including a review of what quantity of exports from a particular customer would warrant
incurring the costs of registering and recording those exports as RECs.
" Order 35284 atzOi The Commission finds that line losses are important issues to study and that it is reasonable and
fair for the Study Framework to include these issues in its scope at both the distribution level and transmission level. lt
is also reasonable to study the difference between using static or marginal losses and the magnitude of each as part of
the valuation to be included in the ECR.
s lnterstate Renewable Energy Council. E.g., on p23: "Considering losses on a marginal basis is more accurate and
should be standard practice as it reflects the likely correlation of solar PV to hearry loading periods where congestion
and transformer thermal conditions tend to exacerbate losses."
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During implementation phase, CEO anticipates addressing our request from 9lZL comments: At the
time net metering tariffs are revised, such revisions should provide customers the option when
registering an on-site generation system to transfer to the Company the environmental attributes
of their future exports.
4.6 lnteeration Costs
CEO agrees with the points made by |CL/Crossborder regarding the need to show lower estimates
of integration costs in light of the Company's plans to acquire battery resources.
Company's ability to use batteries (as are identified in the 2021 IRP for resource acquisition)
to reduce integration costs require that the updated VODER study reflect this alternative
estimate of integration costs.
ll. Cost of Service (Chapter 7l
CEO acknowledges Staff concerns related to cost causation by customer class and the need for
adequate Company revenue recovery. But the CCOS methodology the Company used in the
VODER study is outdated and thus highly inaccurate. Recommendations regarding compensation
for net excess generation should not be derived from that CCOS review nor should they be held up
by that revenue requirement analysis. As PUC Staff has noted:16
"Although Staff takes it as axiomatic that rates must allow the Company a fair opportunity
to recover its revenue requirement, Staff notes that many different rate designs can achieve
this goal. So long as rates afford the Company an opportunity to recover its revenue
requirement, Staff believes that rates may be chosen to achieve other goals, such as energy
efficiency, incenting customer behaviors that defer or avoid future plant investment, or
allowing customers the ability to control their bills."
As was demonstrated in IPC-E-18-16 and again by the VODER analysis of revenue collection relative
to revenue requirements: Schedule 1 residential customers over-pay the most, and Irrigators
under-pay the most. ln any forthcoming rate case, the Commission will be faced with difficult policy
choices. Representatives of lrrigator interests can be expected to strongly oppose the elimination
of cross-class subsidies while Residential customer interests will oppose disproportionately bearing
the rising burden of energy costs.
CEO does not envy that the Commission wil! face these tradeoffs, yet we can strongly recommend
that allowing irrigators to self-generate could help reduce the cross-class tension. PUC Staff has
noted the importance of tying rates to cost causation, and the portion of summer peak attributable
to irrigators will impact cost allocations. The ability of self-generators within the lrrigator class to
s IPC-E-18-16 Staff Comments, Ll2Ll2O20
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collectively lower lrrigator class demand during peak periods can help in enabling new cost
allocations to be both fair and - from a custome/s perspective - reasonable, and less extreme.
Finally, there is a fundamental disconnect between ECR analyses based on incremental real-time
and future cost avoidance and cost of service allocations based on historical costs. CEO believes a
general rate case, rather than a VODER study, will provide the appropriate forum for resolving
these inconsistencies. As the Commission noted ten months ago, "we do anticipate that a general
rate case filing will be forthcoming"tz. The sooner the rate case is forthcoming, the better.
Nevertheless, VODER related decisions, such as the project eligibility cap, should not be held
hostage by CCOS matters untilthat rate case occurs.
lll. Proiect Ellelblllil Cap (Chapter 9l
CEO appreciates the productive all-party technical meeting held 91L212022 and looks forward to
subsequent meetings as needed to discuss specific recommendations and markup any tariffs
necessary for implementing changes to eligibility caps. The Commission agreed with this approach
in its Order dismissing CEO's petition under IPC-E-22-L2, commenting:
"we encourage Staff, CEO, the Company, and interested parties in Case No IPC-E-22-22to
continue to communicate and, if necessary, meet and discuss specific technical issues and
options relating to modifications to the Schedule 84 cap and associated revisions to
Schedules 84 and 58 in a meeting between the partie5."t.
ln9l2L comments, CEO summarizes that setting the cap according to demand should not be the
only alternative considered for modifying the cap. As Staff noted in its comments:
"As long as each project's interconnection point is evaluated and the proper investments
and upgrades to harden the system are implemented based on these evaluations, the size
of the eligibility cap from a safety and reliability perspective is not an issue."t,
For lrrigators, the current practice is to install multiple 100kW systems rather than a right-sized
system.20 Doing so imposes unnecessary costs while resulting in the same capacity., CEO believes
,, Order 35284 at24
', Oder 35547 at 11f Staff Comments at 15
zo ldaho Grain Producers Association,IPC-E-22-L2 public comments: The current 100kW cap on irrigator projects
imposes unnecessary costs on farmers who want to invest in solar. Rather than being able to design, build, and connect
a single site to match their consumption, farmers are instead required to build multiple, smaller sites in multiple
locations - which is more expensive and less efficient for all parties involved."
2, Duane Grant Grant 4-D Farms, public comment, IPC-E-22-12: "The only thing negative about the sites is the fact that
ldaho Power's rules, blessed by the PUQ illogically limit the size of the sites to 100 KW, thus requiring the sites to be
scattered willy-nilly across the landscape wherever one can make the sizing and combination rules work. We would
have much preferred to construct 3 logical, efficient 1,000 KW central sites on a main feeder as opposed to the 26
scattered sites we currently have."
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that imposing unnecessary costs that discourage solar projects is poor policy. There appears to be
broad recognition of the need to modify the 100kW cap - the devil may be in the details.
For reasons partially described in earlier sections, CEO takes exception to llPA's comment22 implying
that review of Schedule 84 eligibility caps should be delayed until a rate case review is completed.
IIPA's suggestion is inconsistent with comments filed in IPC-E-22-L2 by farmers, dairies, the ldaho
Farm Bureau, and the ldaho Grain Producer Association in support of modifying the 100kW cap.
Additionally,in2O2O (IPC-E-20-26), farmers were asking the Commission to do "everything it can to
enable farmers to make informed decisions on solar generation during 2O2L,"r, and again in IPC-E-
2L-2L "to share the sense of urgency for us to access customer-owned generation."24
PUC Staff notes in genera! that compensating exports on a 1:1 kWh basis can result in cost shifts;
that is not in dispute. However, it is misleading to extrapolate that allowing lrrigators to invest in
right-sized solar to offset their needs would unfavorably impact other ratepayers.E On the
contrary, IPC-E-18-16 established that any reduction in lrrigator demand could reduce the need for
fixed cost additions by the utility.
PURPA: Staff comments introduced concerns that raising the cap could enable PURPA projects to
inappropriately take advantage of certain opportunities. CEO is confident this concern can be
resolved via technical meetings and/or appropriate language in the tariff modifications.
to Production Requests 4,7, lO & 11 in the updated VODER. With regard to Company
responses to Staffs Production Requests 5 & 5, CEO also appreciates that Staff did not ask
for these to be added to the study, and CEO specifically requests that these histograms not
be included in the updated VODER because they are misleadingzc and there is not adequate
opportunity to reply to the addition.
,, See llPA comments at 8
a IPC-E-20-26 comment, Michael N. Kochert, Roseberry Farms, Gooding, L212812O20: "l ask that the PUC to do
everything it can to enable farmers to make informed decisions on solar generation during 2021."
,1 IPC-E-21-2L public comment, Russell Schiermeier, Bruneau, ldaho, tll28l2O2l
:5 PUC Staff 9l2Ll2O22 Comments, p17: The implementation timing for changing the eligibility cap is a consideration to
protect non-generatint customers from cost shifu. As discussed above, subsidies exist under the current NEM
framework where credits are rewarded on a one-for-one per kWh basis. lf the eligibility cap is increased prior to an
avoided-cost-based ECR being implemented, it would result in more customer generation capacity being added with
additional cost shifu to non-generating customers.
," For example, CEO is aware of an lrrigator who has 28 service points, most of which have demand less than 100kW,
yet as a customer he found the 100kW cap problematic.
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Fisure 10.3 -Payback analysis of Rooftop solar
The VODER study presents in Figure 10.3 an analysis of the payback a residential customer might
expect from an investment in rooftop solar. CEO perceives this analysis as biased and inappropriate
to include in the VODER study.
Figure 10.3 is introduced (p108-109): "Sample Payback: ln addition, tdaho Power provides an
example of a typical home's potential payback on a net monthly and net hourly scenario."
The analysis reflects choices which do not represent objective investment advice. A few examples:
a
o
Excess Energy Credit Value: The calculations for a "Modified Compensation Structure"
assume an ECR of 2.L75C. The VODER study demonstrates that this far under-values net
excess energy.
Retail Rate Forecast: The payback analysis of rooftop solar assumes that residential retail
rates will escalate 1.3% per year for the life of the system. Response to production request
# 5 shows that from 2W7 - 2021 residential retail rates have risen 4.0% per year
(Compound Annual Growth Rate).
Value of Reduced Consumption: The analysis assumes that customers offset consumption
at an overoge retail rate. Residential rates are tiered, and solar first offsets consumption in
the higher rate tiers.
a
CEO sees this payback analysis as less than even-handed. As such it should be deleted from
the VODER study.
lV. Request for Clarification of Next Steps
CEO requests clarification of next steps and suggests a strawman below informed by the
Company's IPC-E-22-22 application. The proposed next steps assume that the Company files an
updated VODER study which adequately addresses issues raised and does not introduce new issues
for which an additional comment period would be merited.
The Company proposed a process in which all parties would file recommendations, originally
targeted for 7011212022. At this point in time, we believe a more productive process would be an
all-party meeting in November in which the Company could share and discuss its tentative
recommendations. The Commission has stressed in the past that the parties should collaborate; an
all-party meeting creates better opportunity to collaborate, find common ground, and narrow the
range of differences.
We request that, in its next order in this docket, the Commission direct only the Company to file
recommendations in order to establish a comprehensive baseline informed by public and party
13
a
$ Cf.on fnergy Opporlunllles lor ldoho'
input. All parties should then have opportunity to submit initial comments and all parties should
have opportunity to reply. CEO suggests that the timing of all-party meetings could be determined
among the parties as soon as feasible in anticipation of a Commission order in November.
CEO suggests the following next steps:
Technical meetings: All-party technical meetings should be scheduled, which may include:
o Line losses (per request by Staff)
o Time Variant rate matters (per request by Staff)o Methodologies for evaluating avoided T&D costs (per request by CEO and reflective of
interests conveyed in both ICL and City of Boise initial comments)o Changes to Schedules 68 and 84 reflecting modifications to the project eligibility cap (per
previous request by CEO)
Commission Order. The Commission is anticipated to issue an order acknowledging, modifying,
or rejecting the updated VODER study.
Recommendation Collaboration Meeting: An all-party meeting should be scheduled to occur
after a Commission order and prior to the Company's submission of a recommendation. The
Company would review its tentative recommendations for the purpose of gaining input and
feedback from the parties.
!PC Recommendation Submitted. IPC only would file a recommendation after issuance of
Commission order and after the Recommendation Collaboration Meeting above (the IPC-E-22-
22 application proposed all-parties file recommendations 16 days after reply comments).
All-pafi Reply Comments. (lPC Application proposed due roughly 1 month after the date
recommendations were to be filed)
Customer Hearings: One or more customer hearings would be held after all-party reply
comments and before all-party final comments.
All-party final comments. (tPC Application proposed 16 days between reply comments and final
comments)
Commission Order.
The public is unclear of what and when matters will be decided and when such decisions will be
made effective. CEO suggests that clarification by the Commission regarding future process steps
would be broadly helpful.
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$ Cleon Energy Opportunlties for{doho'
ATTACHMENT 1
lllustrative Calculations of Alternative Evaluations of Avoided T&D Costs
AITERI{r\TIVE 1: lnstead of PCAF to determlne (bl Capaclty Contrlbutlon- use ELCC contribution to peak. realtlme
Transmlsslon Dlstrlbutlon I-Otd
dl Caoacitv Contribution oer VODER 7.62% 7.62% VODER - EICC
Avoided T&D Costs s 4.79 S ttq S 11.9 per MWh axd I c
ALTERilATIVE 2r lnstead of PCAF to detrmine (b! Capacfty Contrlbutlon, use [{REL contrlbutlon to peak. real-tlme
Transmisslon Dlstrlbution Total
e) Capacitv Contribution oer VODER tO.3L% 10.31% VODER - NREL
Avoided T&D Costs s 6.48 S g.ee S 15.1 perMWh axe/c
(a) NERA regression based on IPC's FERC Form I data on its historicaltansmission expenditures as a function of its peak load
growth over a 3O-year period from 1996 to 2025
(b) The PCAF method calculates the capacity contribution of solar exports across all hours that have loads within 10% of the
system peak hour. This method weights the solar output in these high-load hours by how close the system load in that hour
is to the annual peak hour load
(d) & (e) Rather than PCAF, this uses the ELCC & NREL contribution to peak from VODER study for real time on-peak exports:
Net-Hourly RealTime
ELCC - On-Peak Exports 3.42% 7.62%
NREL - On-Peak Exports 6.L8Yo t0.3L%
CrossBorder T&D Analv:is As oresented in: ICL Comments w,/ Crossborder Studv. see p4.5 of studv
Parameter
a) Avoided Capacity Cost
b) Solar Capacity Contribution
c) Solar Output
Transmisslon
107.5
29Yo
77lO
Dlstribution
160.3
33%
tTLO
per kW-yr
kwh/kw
Notes
NERA regression
PCAF analysis
PWVATTS - Boise
Total
Solar Avoided T&D Costs 18.s 31.3 S 49.8 per MWh axb / c
15
CERTIFICATE OF SERVICE
I hereby certify that on this 12th day of Octobel I delivered true and correct copies of the
foregoing REPLY COMMENTS to ttre following persons via the method of service noted:
Elecuonic Mail Deliverv (See Order No. 34602)
ldoho Public Utilities Commission
Jan Noriyuki
Commission Secretary
[e-mail]. gov
Idoho PUC Staff
Riley Newton
Chris Burdin
Deputy Attomeys General
Idaho Public Utilities Commission
riley. [e-mail]. gov
[e-mail]. gov
Idoho Power Company
Lisa D. Nordstom
Megan Goicoechea Allen
Timothy Tatum
Connie Aschenbrenner
Grant Anderson
lnordsrom@idahopower. com
mgoicoecheaallen@idahopower. com
ttatum@ idahopower. com
caschenbrenner@idahopower. com
ganderson@ idahopower. com
dockets@ idahopower. com
ABC Power Company
Ryan Bushland
ryan.bushland@ abcpower. co
[e-mail]
City of Boise
Mary Grant Deputy City Attomey
Boise City Attomey's Office
B oiseC ityAttomey@cityofboise. org
mrgrant@ cityofboise. org
Wil Gehl, Energy Program Manager
Boise City Dept. Of Public Works
[e-mail]
Idaho Consery otion L eague
Marie Kellner
mkellner@ idahoconservation. org
IdaHydro:
C. Tom Arkoosh
Amber Dresslar
Arkoosh Law Offices
tom. arkoosh@ arkoosh. com
amber.dresslar@arkoosh. com
erin. cecil@ arkoosh. com
CLEAN ENERGY OPPORTUNITTES FOR IDAHO - REPLY COMMENTS - IPC.E-22-22
Idaho Irrigation Pumpers Ass ociotion :
Eric L. Olsen
ECHO HAWK & OLSEN, PLLC
[e-mail]
Lance Kaufman, Ph.D.
lance@bardwellconsultin g. com
Idaho Solar Owners Network
Joshua Hill
solarownersnetwork@ gmail. com
[e-mail]
Industial Customers of Idaho Power
Peter J. Ridrardson Ridrardson Adams,
peter@richardsonadams. com
Dr. Don Reading
dreadin g@ mindspring. com
Richad E. Kluckhohn
Wesley A. Kluckhohn
[e-mail]
[e-mail]
Miqon Technology,Inc.
Jim Swier
[e-mail]
Austin Rueschhoff
Thorvald A. Nelson
Austin W. Jensen
Holland & Hart, LLP
darueschhoff @hollandhart com
melson@hollandhart com
awjensen@hollandhart com
aclee@hollandhart. com
ril\e
Kelsey Jae
Anorney for CEO
CLEAN ENERGY OPPORTUNITIES FOR IDAHO - REPLY COMMENTS .IPC.E.22.22