20220921Comments.pdf

Kelsey Jae (ISB No. 7899)
Law for Conscious Leadership
920 N. Clover Dr.
Boise,ID 83703
Phone: [phone]
[e-mail]
Attorney for the CleanEneryy Opporunities of ldaho
IN THE MATTER OF IDAHO
POWER COMPANY'S
APPLICATION TO COMPLETE
TIIE STUDY REVIEW PI{ASE OF
THE COMPREHENSryE STUDY OF
COSTS AND BENEFMS OF
ON.SITE CUSTOMER
GENERATION & FOR AUTHORITY
TO IMPLEMENT CTIANGES TO
SCHEDULES 6,8, AND 84
BEFORE TIfi IDAHO PUBLIC UTILITIES COMMISSION
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CASE NO. IPC.E-22-22
CLEAN ENERGY OPPORTUN.ITIES
FOR IDAHO - INITIAL COMMENTS
,. .,. . :ri r _;''.Y
CLEAN ENERGY OPPORTUNITIES FOR IDAHO .INITIAL COMMENTS - IP.C-E-22-221,
CEO acknowledges ldaho Power Company's extensive effort in preparing the VODER analysis. CEO also
recognizes and appreciates the open and constructive communication the Company, PUC Staff and other
parties engaged in on September 12't'discussing technical issues related to eligibility caps for customer
self-generation.
We appreciate this opportunity to address specific aspects of the VODER study where CEO believes
additional perspective is merited.
Chapter 4 - Export Credit Rate
Section 4.l Avoided Energy Costs - Within the VODER study three possible data sources are suggested for
measuring the value of avoided energy - lRP, ICE Mid-C and ELAP. While the IRP does provide a multitude
of data streams that are useful in many regulatory situations, CEO believes that for multiple reasons the
IRP forecasts are inferior to the two market price alternatives.
Within the lRP, future estimates of hourly prices are largely influenced by the natural gas price forecasts
that were fed into the Aurora model. ln the middle of the last decade natural gas prices dropped
dramatically as a result of the use of hydraulic fracturing. At that time concern arose about PURPA
contracts containing prices which were dramatically higher than spot electricity prices. That condition
arose because prices in the PRUPA contracts had been produced using the natural gas price assumptions
in early decade lRPs.
Today the situation is reversed - high current natural gas prices make IRP hourly forecasted prices much
lower than market, The Company reflects this by their own actions. When requesting its current year
power cost adjustment, the Company used forward month price estimates rather than the forecast in its
most recent lRP. Apparently, the Company did not view its IRP forecast prices as adequately
representative of actual 2022 power costs.
For long-term resource planning purposes, variations in year-to-year natural gas prices balance out. The
Company also has the opportunity to revisit IRP assumptions at the time of critical decision points. But for
the public to perceive that the prices paid for energy from self-generators' exports are fair, using an
indicator of actual market prices would be superior to the often quickly outdated IRP forecast values.
The Company implicitly acknowledges the natural linkage between export values and market prices,
noting in a VODER section 8.2 discussion related to its recovery of export credit expenditures that:
$ Cleon fnergy Opporlunities for ldqho'
"Excess energy purchased from onsite generation customers benefits the entire system, not unlike
enerov ourchased on the morke(
!n sum, the Company does not always use forecasted energy prices from the IRP when proposing changes
for consumption rates, such as in a PCA application. Neither should the ECR use IRP forecasts. Within the
two market price alternatives, CEO notes that CAISO EIM prices are available to all to see via the internet.
ICE prices may in some cases be confidential. The VODER study should include explanations of these
fairness and transparency issues.
Section 4.1.2 - Weighted avera*e enerpv orice methods. CEO sees two opportunities for additional
clarity to be provided in this section of the VODER study.
First - Rather than a weighted average, avoided energy could be credited with real-time prices. lf either of
the net billing proposals (hourly or realtime) were implemented, exports could be credited with an
avoided energy value that reflects the actual market prices (either ICE or ELAP could work) at the time the
export occurs. The VODER study should note that, especially if the transparent ELAP market price were
utilized, customers could monitor prices on the CAISO website and possibly modify their consumption
plans to increase exports when they are most valuable on the grid.
Secondly - lf real-time market prices are not used for valuing exports, the method should use recent
market prices rather than three years of historical market prices. The avoided energy component of the
ECR could reflect an annually updated weighted average of prior year hourly exports and market prices.
As the Company notes, the prices used in calculating energy value in an export credit should logically align
with the time that such exports occur:
"For exomple, energy prices during the night, when most customer-generotors dre not exporting
should not carry the some weight as hours when most customer-generators hove energy exported
to the grid."
Using actual prior year experience to calculate the current year avoided energy component in an ECR is
also attractive in its transparency and ease of understanding. Self-generating customers would know what
price they were to receive for all exports they provided during the year.
Section 4.1.2.2 Enerrv: Seasonal Time Variant Exoort Credit Value - The seasonal "time-variant" rate the
Company proposed sends price signals to customers related to the time-value of exports. TOU rates for
consumption also signal the time-value of a kWh consumed. Until customers have access to a similar
"symmetrical" time-of-use pricing on the consumption side CEO sees the use of this "time-variant" price
for exports only as problematic in a couple of respects.
Rates for consumption don't currently allow self-generators to benefit from reducing their load during On-
Peak hours. The VODER study finds that92% or 97% of exports occur during the time-variant Off-Peak
period (assuming ELCC methodology). Given that the ovenrhelming majority of exports occur during the
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* Cleon Energy Opporlunities for {doho'
Off-Peak period, it is unclear whether the large difference in price the Company suggested would create
the economic incentive for self-generators to export rather than consume their generation during peak.
Secondly, the asymmetry is unfair to multiple parties. A customer using on-site generation to reduce their
load during peak would benefit at a fraction of the rate applied to a customer using on-site generation to
export during peak. The VODER study should point out these problems with asymmetrically imposing on-
peak/off-peak rates for exports while customers have no access to on-peak/off-peak rates for
consumption.
4.1.3 Evaluation of Firmness of Exoort Enerw - ln October 2018, the Company initiated IPC-E-18-15: The
Study of Costs, Benefits, and Compensation of Net Excess Energy Supplied by Customer On-Site
Generation. A Settlement Agreement reflecting significant investment of time and resources by the
Company, PUC staff and intervening parties was filed a year later in October 2019. When the Commission
chose not to accept the Settlement Agreement and re-ordered the study, the Commission stated, "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).
ln addition to the 82.4% value, the VODER Evaluation of Firmness of Export Energy should acknowledge
the firmness value that the Company, PUC Staff, and signatory parties found in the prior study (lPC-E-18-
15 Settlement Agreement at 3):
"The energy value will be decreased by 1O% to reflect the non-firm nature of the energy provided
by on-site generators."
4.3 Avoided Transmission and Distribution Costs. The lumpy nature of T&D projects presents challenges
in how to value avoided costs and there are multiple methodologies for doing so. Some methodologies
are "lumpy'', some use statistical analysis to smooth the long-term relationship between exports and T&D
costs. lf a project-specific, all-or-nothing method is used, it can result in near zero values (as is the case
with ldaho Powe/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).
The determination of the ECR should be informed by the range of potential values resulting from different
methodologies. Consideration is merited of ahernative methods which take a smoother, more
probabilistic approach to valuing avoidable T&D costs over time. The VODER study should reflect those
a lternative methodologies.
Section 4-5 Avoided Environmental Costs -The Commission directed that the VODER Study reflect a value
of exports based only on measurable costs and benefits that effect rates. ln the VODER study and again in
a May 6 workshop regarding a study of distributed energy resources, the Company indicated that they
perceive the environmental values of self-generating customers to be limited to reductions the Company
would othenrise pay for emissions pollution. Consequently, the VODER study presents the value of
measurable environmentalcosts and benefits impacting ratepayers as $0.
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CEO believes that looking only at emission pollution costs is an unnecessarily narrow perspective. As a
consequence, by inadequately reviewing the value of environmental attributes of exports the VODER
study is deficient in valuing "all benefits & costs that are quantifiable, measurable, and avoided costs that
affect rates" (Order 35284, p271.
Within the Company's customers there are individuals and entities willing to pay a premium for renewable
energy. This creates a market value for the "environmental attributes" of renewable generation. ldaho
Power currently purchases RECs (certified renewable energy credits) and resells them to customers
willing to pay a premium for renewable energy.
The Company suggests that the environmental characteristics of the Green Power it sells to some of its
customers need to be formally registered as RECs. CEO agrees that some large customers may require
certification ("RECS"). But assuming that everyone willing to pay a premium for renewable energy would
require that the electricity undergo the costly and administratively challenging process to be certified by
an agency as renewable is untested and may not be accurate.
CEO believes that not all customers who are willing to pay extra for the environmental attributes of
renewable energy would require REC certification to meet their needs. There are numerous examples of
commenters who value clean energy noting the merits of locally produced energy. Avoiding the need for
REC certification allows for a value to be placed on the environmental attributes of customer exports.
Certainly, the Company's billing system (which would be the source of information that an export by a
self-generator had occurred) is sufficiently robust to ensure that Green Power customers are in fact
receiving the environmental characteristics of a renewably generated kWh.
Customers with self-generation who export to the Company should have the option to sell to the utility
the environmental attributes of their exports. The VODER study should reflect an alternative where
customer generators have an option to sell to the utility the environmental attributes of their exports and
a receive value for this sale.
The VODER study suggests that one step required in order for customers to be compensated for the
environmental attributes of their renewable enerty is that the customer legally transfer the
environmental attributes of the on-site generation" (VODER, p52). CEO requests that, 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.
While the study is currently deficient in presenting instruments for valuing those environmental
attributes, there is no need to delay putting in place the mechanism necessary to allow the option of
transferring them. Should self-generating customers with exports choose to retain the environmental
characteristics of all their generation they should have the option of doing so but would as a result receive
a lower price for their exported power (a price which did not include the benefit the Company would
receive from the environmentalcharacteristics of those exports).
Exports by customers with renewable self-generation could be valued by the revenue they provided the
Company - the S.0VkWh charged to those purchasing clean energy under the Green Power, (eventually
the CEYW "Flexible") program offering. Alternatively, because the Company purchases some RECs to
supply to customers, the value of avoiding some of those purchases (by using instead the environmental
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characteristics of the solar energy customers with self-generation export) could be considered an avoided
environmental cost.
ln either case the environmental attributes of self-generator exports do tie to a measurable and avoidable
cost impacting rates. The VODER study needs to accurately reflect those avoided cost (or increased
revenue) impacts.
Chapter 5 - F'requency of ECR Updates
The value of Avoided Energy is a significant portion of the ECR and, as such, merits a more frequent
update than other components in order to maintain a fair ECR value.
5.1 Enerw Price lnputs. fu noted earlier:r Market prices much more accurately reflect the time value of exports than IRP values, which are
highly sensitive to excursions from forecast naturat gas pricing and can become quickly outdated.. Using the actual market price at the time of the export occurs would be perceived as most accurate
and thus fair.o The VODER should note that avoided energy component of the ECR could reflect an annually updated
weighted average of prior year hourly exports and market prices - providing an attractive balance of
fairness, transparency, and ease of understanding. Self-generating customers would know what ECR
to expect during the year, and an annual update based on prior year actual market prices would
provide a more accurate and thereby more fair value than IRP estimates.
Chapter 7 - Class cost-of-seruice
Section 7.2 CCOS resulg - CEO acknowledges that an up-to-date class cost-of-service analysis is a valuable
toolfor analyzing pricing structure. But fair allocation of largely sunk costs is not the only relevant factor
to consider when establishing a price structure.
Directing the Company to produce the VODER study had obvious advantages, especially due to the
Company's expertise and access to relevant data. But having a party with a natural interest in the
outcome of any review of self-generation produce the study does present opportunities for issues to be
analyzed through a one-way lens. Cost analysis is one such example.
On page 85 the study notes:
"opportunity exists to better align the pricing structure with the underlying cost structure"
Adequate revenue recovery to cover fixed cost expenses is an obvious constraint on any pricing structures.
But CEO disagrees with Company's implied position that the goal of rate design is to align with the
Company's cost structure.
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The VODER study does not make reference to the large amounts of new solar generation the Company
projects as needed in the preferred portfolio of its latest lRP. ln addition to being fair and reasonable,
prices should also encourage optimal future behavior. To the extent that customers choose to make
investments in solar self-generators, some of the Company's future expenditures for solar generation
could be offset. Also, while large concentrated utility scale has cost advantages it is less resilient to a
single line or transformer failure or cloud coming over - the geographic diversity of customer installed
solar provides a resiliency benefit.
While the timing and extent of those capital expenditure offsets and resiliency benefits may be difficult to
quantify, the VODER study should note such values as relevant in any future pricing structures.
Chapter 9 - Project Eligibility Cap
CEO comments regarding the content of Chapter 9 are organized as follows: (1) Study deficiencies, (2)
Highlights of findings to date, and (3) Add potential alternatives.
1l Studv deficiencies.
The VODER study was deficient in its evaluation of the Project Eligibility Cap. The study was directed to
"Analyze the pros and cons of setting a customer's project eligibility cap according to a custome/s
demand as opposed to predetermined caps of 25 kilo-watt ("kW") and 100 kW" (Order 35284 @25). After
the VODER study was released, CEO received inquiries asking where to find this analysis within the Study -
those readers assumed that there must be more to the eligibility cap review than Chapter 9.
Similarly, in its first Production Request, PUC Staff asked -
"Please identify where the pros and cons of setting a cap according to a custome/s 100% and
125% demand as opposed to predetermined caps of 25 kW and 100 kW are located in the VODER
study. lf this was not provided in the VODER study, please provide them."
The Company responded:
"section 9.1 of the VODER Study evaluates the existing project eligibility cap, and Section 9.2
considers a modified project eligibility cap set relative to a customer/s demand. Both sections
describe the considerations evaluated. From the Company's perspective, assessing the
interconnection requirements and distribution system operational impacts is of primary
importance."
But even with the expressed concern regarding interconnection matter, the VODER Study evaluation of
interconnection requirements was incomplete. The Study notes in section 9.2.2 Modified Cap lmpact:
"Modifications to the project eligibility cap would require an evaluation of the interconnection
requirements".
As described more fully below, via Production Requests and a meeting of the parties 917212022 to discuss
technical aspects of the project eligibility cap, progress in addressing this deficiency has been made.
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2) Highlights of findings to date
To supplement gaps in the VODER study, CEO presents below highlights from the study, comments
Production Requests and other sources:
VODER studv highlishts:
o "[R]etaining the 25-kW cap for residential and small general customers could be reasonable." (VODER
p10u
o About 850,5 of solar irrigation systems bump up against the 100kW cap.
o IEEE 1547 compliance has reduced safety, service quality, and reliability risks.
o Setting a cap to customer demand is more challenging for customers/service points with lower
demand, presents issues when there's a change in ownership, and may not align with the changing
needs of customers.
The Company proposed that in 2023 it would "likely endeavor to hold technical workshops with
Commission Staff, installers, and other interested stakeholders to discuss proposed interconnection
requirements". (VODER Study, page 112)
Public record hirhlights (from public comments. IPC-E-20-26 and/or IPC-E-22-121:
o ldaho Grain Producers Association explained in IPC-E-22-12 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."
Multiple agribusiness interests have noted the urgency in revising the 100kW in 2022 given
agribusiness vulnerability to energy costs, rising electricity costs, and time-sensitive access to federal
funds.
Commenters to IPC-E-22-12 noted that if the CEO petition were not limited to the cap alternative
ordered in IPC-E-21-21, that an absolute level of 2000kW or a table of eligibility levels with protocols
for each level should be considered.
Highliehts from Companv Responses to Production Requests and All-Partv meetins 9/12:
It is the review process, not the cap, that protects the grid. Concerns related to safety, service
quality and grid reliability issues can be and are adequately addressed through the generator
interconnection process. Changes to tariffs necessary to implement a modified cap are minimal.
A 5 MW project might easily connect to a distribution feeder, while a 100-kW project located many
miles from the substation and at the end of smaller conductor might present issues or require system
upgrades. These issues are identified and addressed in the existing interconnection review process.
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Currently, prior to interconnection, all on-site generation p@ects undergo a Feasibility Review, and
some projects may require a Feasibility Study. Per response from the Company:'
The Company envisions the first step in reviewing larger projects would be to use the current
internal screen for each project. The current internal screen evaluates the project size relative
to the individual service transformer size and the distribution feeder hosting capacity - in
Schedule 68, this is referred to as the Feasibility Review. tf the project passed the initial
screen, then the project would be approved. However, if the project fails, the Company would
require a more detailed study to look at potential operational, safety, or power quality issues
caused by the project. These studies could follow the process for PURPA projects, with an
initialfeasibility study being completed within 30 days and, if necessary, a system impact
study that would take an additional 30 days. Each study would require funding from the
customer to cover the cost of the study.
Schedule 58 currently addresses interconnection criteria for on-site generation systems up to 3 MVA
(the equivalent of 3000 kW) and additional criteria for systems over 3 MVA.
"[Tlhe interconnection considerations re]ated to a generator will be evaluated independently from a
customer's demand.", Setting a cap according to demand is unrelated to interconnection matters and
does not affect safety, service quality, and reliability risk as those matters are addressed in the
interconnection review process.
While a 25kW cap addresses the vast majority of R&SGS, there are customers with higher electricity
requirements who would value a path to apply for larger systems.
Additional observations:
o There are implicit limitations to system size irrespective of customer demand:
o No benefit to over-sizing: An ECR credit redeemable only against energy expenditures provides no
economic benefit to customers for building over-sized systems.
o Upgrade costs: Potential costs for required distribution system upgrades often limits economic
ansta llation size to existing transformer/line capacity.
o Space limltations: Rooftops, acreage, etc.
1 ldaho Power Response to the First Production Request of PUC Staff, No. 9, c.
, ldaho Power Response to the First Production Request of PUC Staff, No. 4, b.
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3) Additional cap alternatives need consideration
A consideration behind setting the cap according to demand was summarized by the phrase "if it can
make, it can take it." That is, if the grid can safely deliver a custome/s peak demand, the grid has the
capacity to receive a similar amount of customer-generated exports. Findings now indicate that a cap
based on technical criteria (such as absolute size) merits consideration as an alternative to setting the cap
according to demand. Such a technical cap should be considered under the VODER study.
For example -
Rocky Mountain Power was ordered in 2020 to study setting the project eligibility cap according to
demand. RMP implemented a non-residential cap of 2000kW in Utah.
ldaho Power proposed to study setting the cap according to demand in IPC-E-21-21. The VODER
study raised administrative complexities with setting the cap to demand.
ldaho Power clarified in the course of Production Requests that customer demand is not a factor
in evaluating the interconnection requirements required to ensure safety, service quality, and
reliability.
ln sum, there exists sufficient evidence that setting the cap according to demand should not be the only
alternative considered for modifying the cap.
ln Exhibit 1 below, CEO presents four cap design alternatives and suggests, based on findings to date, a
possible scoring theme for how well each ahernative address three criterla: grid safety, fairness and
administration.
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Etrhlblt 1: Alternatlves for Modlfylnr Ptolect EllrlblllW Caos
ln considering a modlfied cap, the Commlsslon may be conerned wtth the followlq thrc€ factors:
1) Grid lmpacts (. primary bcss): Crn safety, scrvloc quality, rnd grid relaUlhy be cnsured under the modilted cap?
2) Fair & Equltabh: ls the modified cap felr and equltable rcross custom.6 and dasses?3l Adminlstratlve: ls modloed cap admlnlfiratlvely ctnightfiorward end Gffrclrnt to malntain?
* GRID - The revlew procedures required for interconnection khntlfy and addresr any issues with saftty, seMce quallty, and grid reliability,
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Abnntlvre iortodlfidno Crr Gru
Grld'
Safety, service
quallty, &
relhblliw
Felr &
Equlteblo
Admlnldrrtlvo.0ncbrcy Rolrt d Flndlngr
A! Malntaln current
251il&1fi)kWcaps
PuUk rcod &moortirt !:r t00kW crp hanm O&l cu$omcrr
VODER dcmorctr.trr:r lncquhrbh cap oficcs on dlffercnt
qrttornar dars$.
o Thc l(Dl(Sl cro b unnaesrarv
B) Set cap accordlntto
demand for all customers
Dkilmlrnr/rnfrrrlrrfrcnafrnrhlr
VIIDER prgents @ns of sltdn8 c.p set to
dcmrndl. CholhnttuE for smrficr systcms. Olanirs ln owncr$lp r.bcs bsuca. Ctrgtomar: havo dnnrlnr necdr
C! Set cap to be the greater
of 25kW or a perccntage of
customcr demand for all
customcr da$cs
Dl*nffifO!oaiaar/,,i3'f,l'tiorilk{rlorf
ft[rhrirlrclrr.*Dr*.'flx!
a. Efndeot.nd f.kbr i&SGS
. F.r $rperlor to cuntnt 10(NW c.p
lnortt th€ @nr of setdu the crp rcoordlnt
to dcmrnd wlthout derr bencfit
Dl SGt an absolute cap
lcvel of 2MWforall
customer classes
r Easlert to undcrttrd .nd .dmlnttcr.r ECRompcnsrdon pollcyClo*r q$tomcrs
m bcnc,ft br ovcr.aklf sFtem$. lntrr@onacilon crltarL & ragulramontt
:crvc to fu rther rown sYstem ilzas
if CIeon €nergy Opportunilies for {doho'
Chapter 11 - Implementation considerations
11.1 Transitional Rates
The VODER study invited input regarding a reasonable transition time period or impact on customers for
implementation of new net metering terms. Some commenters have also raised the issue of providing
legacy treatment to existing non-legacy customers. ln IPC-E-18-15, the parties agreed to an 8-year glide
path which was projected to average an 8% decline per year relative in the export credit rate. This had the
advantage of not only preventing rate shock but also offering a transition period for customers and the
industry to build the skills, tools, and experience base needed to evaluate the economics of on-site
generation systems.
lnformed by what was agreed to as reasonable in IPC-E-18-15, CEO would suggest that the VODER study
should include an option for implementation that would set a limit that the Export Credit Rate would not
decline more than 8% per year relative to the average retail rate until such time that it reaches the then-
current ECR.
U.2.2 Tariff Chanees
The Company notes that "modifications to the project eligibility cap would require changes to Schedule
58, which may include expanded interconnection requirements." (VODER, p112) CEO is under the
perception that such changes are minimal given responses to Production Requests and a meeting of the
pa rties Septem ber 72, 2022.
CEO requests that the impact on Cl&l customers who are impeded by the 100kW cap should be among the
VODER considerations. Such considerations include -
The harm to customers of delaying the implementation of a modification to the 100kW cap.
o Time-sensitive access to federal funds.
o The challenge of supply chain issues, which create delays from the time an application is approved to
the time equipment is procured, installed, and operational.
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CERTIFICATE OF SERVICE
I hereby certify that on this 21st of Septembe4 I delivered nue and conect copies of the
foregoing INITIAL COMMENTS to the following persons via the method of service noted:
Elecronic Mail Delivery (See Order No. 34602)
Idaho Public Utilities Commission
Jan Noriyuki
Commission Secretary
secretary@puc. idaho. gov
Idaho PUC Staff
Riley Newton
Chris Burdin
Deputy Attomeys General
Idaho Public Utilities Commission
riley. newton@puc. idaho. gov
[e-mail]. gov
Idaho Power Company
Lisa D. Nordsnom
Megan Goicoechea Allen
Timothy Tatum
Connie Aschenbrenner
Grant Anderson
lnordsnom@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 oiseCityAttomey @cityofboise. org
mrgrant@ cityofboise. org
Wil Gehl, Energy Program Manager
Boise City Dept. Of Public Works
w gehl@ cityofboise. org
Idaho Conservation League
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 OPPORTUNITIES FOR IDAHO - INMIAL COMMENTS . IPC-E-22-22 2
Idaho Irrig otion P ump ers Associotrbn :
Eric L. Olsen
ECHO HAWK & OLSEN, PLLC
[e-mail]
Lance Kaufuan, Ph.D.
Iance@bardwellconsulting. com
Idaho Solar Owners Nenuork
Joshua Hill
solarownersnetwork@ gmail. com
[e-mail]
Industial Customers of ldaho Power
Peter J. Ridrardson Rictrardson Adams,
peter@richardsonadams. com
Dr. Don Reading
dreading@ mindspring. com
Richard E. Kluckhohn
Wesley A. Kluckhohn
[e-mail]
[e-mail]
Miqon Technology,Inc.
Jim Swier
[e-mail]
Austin Ruesctrhoff
Thorvald A. Nelson
Austin W. Jensen
Holland & Hart, LLP
darueschhoff @hollandharl com
melson@hollandhart com
awjensen@hollandhart" com
aclee@hollandhartcom
rs\e
Kelsey Jae
Aaomey for CEO
CLEAN ENERGY OPPORTUNITIES FOR IDAHO .INITIAL COMMENTS .IPC.E-22.223