20231102Reply Comments.pdf

CLEAN ENERGY OPPORTUNITIES – REPLY COMMENTS - 1
Kelsey Jae (ISB No. 7899)
Law for Conscious Leadership
920 N. Clover Dr.
Boise, ID 83703
Phone: [phone]
[e-mail]
Attorney for the Clean Energy Opportunities for Idaho
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY’S APPLICATION FOR
AUTHORITY TO IMPLEMENT CHANGES
TO THE COMPENSATION STRUCTURE
APPLICABLE TO CUSTOMER ON-SITE
GENERATION UNDER SCHEDULES 6, 8,
AND 84 AND TO ESTABLISH AN EXPORT
CREDIT RATE
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Case No. IPC-E-23-14
Clean Energy Opportunities
for Idaho
Reply Comments
Clean Energy Opportunities for Idaho (CEO) appreciates the thoughtful proposals and well-structured
comments submitted by Commission Staff. Immediately below is a summary of CEO’s specific comments and
requests, followed by further explanation and specific replies, and lastly our closing remarks.
I. Summary of Requests
1.Time Period Rate-Differentiation based on System Reliability Risk:
1.1.CEO supports Staff’s proposal to define the Summer season as June 1 – September 30 and agrees with
Staff’s support for the Company’s proposed Summer On-Peak window of 3pm -11pm.
1.2.CEO requests that the Company provide an updated analysis of highest risk hours reflecting the
Battery Energy Storage Systems installed on the Company’s system as soon as feasible in order to
inform a) ECR avoided generation capacity value, b) ECR updates with regard to highest risk hours,
and c) workshops agreed to by the parties in IPC-E-23-11.
2.Avoided Energy:
2.1.CEO supports the Company’s proposed method for valuing avoided energy based on ELAP hourly
pricing from the prior year weighted by hourly exports in that year because the method provides an
appropriate balance of accuracy, stability, and transparency.
2.2.CEO supports Staff's proposal (at 18) to assign the energy value in accordance with energy-defined
Seasons, and to implement three ECR values: Non-Summer, Summer Off-Peak, and Summer On-Peak.
3.Fuel price hedge benefit: CEO asserts that an accurate fuel price hedge value is not zero and requests that
the ECR reflect a price hedge benefit equal to either 5% of the avoided energy value (consistent with the E3
recommendation to PacifiCorp1), or, at a minimum, 3.9% of the avoided energy value (consistent with
Rocky Mountain Power study of on-site generation for Idaho.2)
1 Jan 22, 2019 ORDER NO. 19-021 at 20, UM_1910_Order.pdf&il=true (state.or.us)
2 PAC-E-23-17, Rocky Mountain Power On-Site Generation Study, at 23.
RECEIVED
2023 NOVEMBER 2, 2023 4:55PM
IDAHO PUBLIC
UTILITIES COMMISSION
CLEAN ENERGY OPPORTUNITIES – REPLY COMMENTS - 2
4.Avoided Generation Capacity.
4.1.CEO supports Staff’s request to use a 5-year rolling average of the ELCC percentage to determine load
carrying capacity contribution of solar customer-owned solar generation rather than the 3-year rolling
average proposed by the Company.
4.2.As stated above in 1.2, CEO requests that the Company provide an updated analysis of highest risk
hours reflecting Battery Energy Storage Systems installed on the Company’s system as soon as
feasible in order to inform a) ECR avoided generation capacity value, b) ECR updates with regard to
highest risk hours, and c) workshops agreed to by the parties in IPC-E-23-11.
5.Avoided T&D: CEO requests that, in future ECR updates, because new transmission lines like B2H,
SWIP-North, and Gateway West sections 8 & 9 are to be used to link remote generation sources to load
centers, the costs for those marginal transmission lines should be treated in the same fashion as other
marginal generation resources when quantifying the T&D capacity contribution of self-generation.
6.Avoided Line Losses: CEO requests that the value of the line loss coefficient implemented in any 2024
ECR should be no lower than the 5.8% value proposed by the Company in IPC-E-22-22, and that the
Company be directed to hold a technical workshop to review its methodology for line loss calculations prior
to filing its next ECR update recommendation, which update will presumably occur in April of 2025.
7.Integration Costs. CEO requests that the proposed ECR be updated to reflect the integration costs value of
$.00064/kWh associated with Case 9 (Case 9 assumed 200MWs of storage on the Company’s system) in
the 2020 VER integration study. Case 9 more accurately reflects the on-line and in construction additions of
approximately 180MWs of Company controlled battery storage capacity, rather than the $0.00293/kWh
associated with Case 1 in that study (Case 1 assumed zero storage on the Company’s system).
8.Environmental Attributes: CEO reiterates our general request that resolution of the ECR include a
mechanism for monetizing renewable energy attributes of exports from self-generating customers covering:
a) transferal of ownership of those attributes, b) a process for ongoing evaluation of opportunities to
monetize renewable energy attributes, and c) at least a placeholder in this ECR for adding the value of such
attributes in the future ECR updates. Specifically -
8.1.Schedule 6 should be modified such that a) customers would, by default, transfer ownership of the
renewable energy attributes of their exports to the Company, b) customers may opt out of this transfer,
and c) the effective date for such transfer will begin with exports occurring on or after the effective
date of the 2025 ECR update.
Given that transfer of ownership is an important step toward monetizing renewable energy attributes,
CEO requests that if the Company does not support this specific proposal, the Company then propose
for the Commission’s consideration an alternative means to establish a path such that customers will
have the option to transfer ownership of renewable energy attributes to the Company.
8.2.The Company should be directed to evaluate opportunities for customer-owned generation to provide a
resource for avoiding the costs the Company would otherwise incur to serve potential Clean Energy
Your Way (CEYW) Flexible customer needs.
8.3.As part of the annual ECR update, the Company should report on opportunities to monetize the value
of renewable energy attributes of exports (including opportunities where the renewable attributes are
not formally certified as RECs) as well as opportunities for aggregation and/or certification of
customer-owned generation.
9.Initial ECR Effective Date and First Update: For Schedule 84, CEO strongly supports Staff’s proposal to
implement changes January 1, 2024 and for the first update to be filed in April 2025. Past dockets have built
a substantial record of requests from agribusinesses for timely visibility to changes affecting the design and
compensation for on-site generation.
10.Project Eligibility Cap: CEO supports the IPC-E-23-14 proposed changes to the Schedule 84 project
eligibility cap.
CLEAN ENERGY OPPORTUNITIES – REPLY COMMENTS - 3
II. Supporting Comments and Specific Replies
1. Time Period Rate Differentiation based on System Reliability Risks.
CEO supports Staff’s proposal to align the ECR definition of the Summer season (June 1 through September
30) with the definition of the Summer season proposed in the Company’s general rate case, IPC-E-23-11.
Similarly, CEO supports the Company’s proposal and Staff’s support for defining Summer On-Peak as 3pm to
11pm because it moves closer to a uniform definition of the System-level summer on-peak period being used
for both supply and demand side rate designs.
CEO shares Staff’s concern that the Company’s model for analyzing highest risk hours excluded the impacts of
the Battery Energy Storage Systems ("BESS") installed on its system. CEO requests that the Company provide
an updated hourly LOLP analysis which includes the use of BESS resource additions the Company has made in
2023 as soon as such an analysis can be performed. The parties to IPC-E-23-11 agreed3 to a series of workshops
which include review of cost of service methodologies and Time of Use rates. The hours of highest reliability
risk are a key component to those matters, thus a more accurate analysis of highest risk hours is needed both in
this matter as well as to inform those workshops.
2. Avoided Energy.
2.1 CEO agrees with Staff and the Company regarding the proposed method for valuing avoided energy based
on ELAP hourly pricing from the prior completed year weighted by hourly exports in that year. Rate-making
often calls for a balance between perfect accuracy and the need for stability, understandability, and
transparency, all of which are criteria that were established in IPC-E-22-22.
Some commenters argue that this proposal for valuing avoided energy is too complex or is unstable, one
commenter argues that use of historical pricing is imperfect in accuracy and proposes additional complexity and
instability. CEO supports Staff’s assessment that the Company-proposed method achieves a fair balance
between accuracy and the need for stability and transparency, and that it is “important to provide customers a
fixed set of published energy values for a year.”4
CEO understood that the intent of using EIM sourced ELAP pricing as a component of ECR valuation was to
reflect the local energy value in each hour. This understanding conflicts with one party’s assertion that the
ELAP prices presented in this docket are inappropriately overstated by including a California Greenhouse Gas
component associated with EIM sales made into the CAISO market5. CEO requests that the Company clarify
(in their final reply comments) whether a Greenhouse Gas adder is, or is not, included in the ELAP prices.
In general, a market price reflects a balance of supply and demand, regardless of whether every buyer in the
market values the same attributes of the commodity. The Company does not have the opportunity to purchase
energy from the Energy Imbalance Market at lower than market price, thus the actual EIM market price
accurately represents avoidable energy costs.
2.2 CEO supports Staff's proposal (at 18) to assign the energy value in accordance with energy-defined
3 IPC-E-23-11, Motion for Approval of Stipulation and Settlement at 11-12.
4 IPC-E-23-14 Staff Comments at 17: “Staff believes it is more important to provide customers a fixed set of published
energy values for a year, than to assign an unknown and highly variable real time price to each unit of exported energy.”
5 See IIPA comments, item #3, page 2
CLEAN ENERGY OPPORTUNITIES – REPLY COMMENTS - 4
Seasons, and to implement three ECR values: Non-Summer, Summer Off-Peak, and Summer On-Peak.
3. Fuel Price Hedge.
The Commission ordered in IPC-E-21-21 that the VODER should evaluate a fuel price hedge value. The
VODER presented the Company’s position, not an evaluation. The value of a fuel price hedge is not zero as
noted in evidence presented on best practices6, by parties to this docket (CEO, Vote Solar, City of Boise), by the
PUC of Oregon7, and by Rocky Mountain Power’s June 2023 On-Site Generation study for Idaho.8
Natural gas prices have a history of volatility (see image below)9. Plans to shift Company generation resources
at Valmy and Jim Bridger from coal to gas fired serve to only increase customer exposure to annual rate
variations via the larger PCA adjustments that such year-to-year fuel price changes produce.

Customer load reduction at any hour reduces the aggregate fuel the Company would either buy directly or
implicitly through market purchases. Protecting customers from a portion of that volatility has a value and the
ECR should be updated to include a fuel price hedge value that is not zero. For that reason, CEO reiterates its
requests –
►That ECR rates reflect a price risk benefit equal to 5% of avoided energy value consist with the E3
recommendation to PacifiCorp10. In the event the Commission does not accept this request, CEO asks at
6 A Regulator’s Guidebook: Calculating the Benefits and Costs of Distributed Solar Generation, p36, Interstate Renewable
Energy Council: “A fuel price hedge value should be included.” Referenced by CEO in IPC-E-21-21 & IPC-E-22-22.
7 Oregon PUC, ORDER NO. 19-021 regarding Hedge Value:
“For this element, we adopted the E3 suggestion for a 5 percent hedge value of avoided energy. E3 's recommendation
is derived from a peer-reviewed paper entitled How Big Is the Risk Premium in an Electricity Forward Price? Evidence
from the Pacific Northwest. We noted that “[w]e decline the suggestion for a zero value, because similar to Market
Price Response, we are persuaded that there is value to this element.” [Order No. 17-357]
8 PAC-E-23-17, Rocky Mountain Power On-Site Generation Study, at 23. “PacifiCorp’s calculation of the energy value and
cost-effectiveness of energy efficiency measures used these stochastic results to identify the incremental value associated
with these risks, and PacifiCorp has calculated the avoided risk associated with customer exports using the same risk
values applied to energy efficiency. Over the 2021 IRP horizon, this increases the energy value of customer exports by 3.9
percent, or $1.24/MWh as shown on summary tab of CONF Appendix 4.2: ID EE Cost-Effectiveness.”
9 Annual average Henry Hub spot gas price. Source: US Energy Information Administration
10 Jan 22, 2019 ORDER NO. 19-021 at 20, UM_1910_Order.pdf&il=true (state.or.us)
CLEAN ENERGY OPPORTUNITIES – REPLY COMMENTS - 5
minimum that the energy value be increased by 3.9% to reflect a fuel price hedge value consistent with the
analysis completed by Rocky Mountain Power for its Idaho on-site generation customers. 11
4. Avoided Generation Capacity.
4.1 CEO supports Staff’s request to use a five-year rolling average of the ELCC percentage to determine
the load carrying capacity contribution of solar customer-owned solar generation rather than the 3-year rolling
average proposed by the Company.
4.2 As stated above in 1.2, CEO requests that the Company provide an updated analysis of highest risk
hours reflecting Battery Energy Storage Systems installed on the Company’s system as soon as feasible in order
to inform a) ECR avoided generation capacity value, b) ECR updates with regard to highest risk hours, and c)
workshops agreed to by the parties in IPC-E-23-11.
IIPA asserts that “market prices during hours where the market is capacity constrained have both a capacity and
energy component.”12 CEO contests the accuracy of this assertion. The Energy Imbalance Market (EIM) is just
that: an energy market. Participants in the market must be fully reserved against their forecast load before being
able to participate in EIM transactions. The EIM transaction values reflect the marginal cost for energy (with
location based adjustments for losses and congestion) in any period. High marginal energy prices occurring
during periods of high WECC load reflect the higher operating costs for generation resources higher in the
dispatch stack. CEO maintains that short-term EIM prices do not reflect a capacity value as that term is used in
this case.
Perhaps in 2027, if the Company is then participating in the WRAP (Western Resource Adequacy Program), a
broader WECC-wide view of capacity may be warranted. But today, capacity value, as it is considered in this
case, is determined at the Idaho Power system level. Customer exports to the monopsony purchaser (IPC)
should be valued based on the benefit they provide in allowing IPC to avoid the cost of adding an incremental
resource to maintain an acceptable level of reliability within the Company’s system. EIM prices should be
considered as an appropriate measure of marginal energy value but not as including any capacity value.
►CEO opposes IIPA’s requests to re-price the on-peak energy credit to equal the off-peak energy credit given
that customer exports to the monopsony purchaser (IPC) during certain hours with a high loss of load risk,
reflect the avoided cost for IPC to maintain reliability levels within IPC’s system. If such a request were
granted, CEO would request that the non-firm adjustment be removed so as not to double-discount the value
of exports.
5. Avoided T&D Capacity -Future treatment of marginal transmission
CEO requests that, in future ECR updates, because new transmission lines like B2H, SWIP-north, and Gateway
West sections 8 & 9 are to be used to access remote generation sources, the costs for those marginal
transmission lines should be treated in the same fashion as other marginal generation resources when
quantifying the T&D capacity contribution of self-generation.
IIPA suggests that customers who reduce their bill via on-site generation “will receive double compensation for
reduced distribution costs” when they decrease their bill for consumption if energy charges include some
portion of distribution demand costs13. The Commission thoroughly reviewed this matter in IPC-E-17-13 and
found that matters of fixed cost recovery behind them meter are separate from matters of valuing net excess
11 PAC-E-23-17, Rocky Mountain Power On-Site Generation Study, at 23.
12 IPC-E-23-14 IIPA Initial Comments at 7.
13 IPC-E-23-14 IIPA Initial Comments at 3.
CLEAN ENERGY OPPORTUNITIES – REPLY COMMENTS - 6
energy, which is the focus of this docket. Per Order No. 34147 at 16, “It is reasonable and fair to distinguish a
customer's freedom to offset usage behind the meter from a customer's choice to export energy to the grid.”
6. Avoided Line Losses
CEO appreciates the thoughtful improvement to line loss calculations proposed by Staff. Nevertheless, CEO
refers to our initial comments recounting concerns with process. E.g., the VODER the Company filed in June
2022 did not study and compare marginal line losses as ordered in IPC-E-21-2114, the further discussion among
the parties encouraged by the Commission in IPC-E-22-2215 did not occur, and the Company instead is
proposing in this docket to reduce the line loss coefficient from the 5.8% it presented in IPC-E-22-22.
CEO requests –
►That the line loss coefficient implemented in 2024 should be no lower than the 5.8% proposed by the
Company in IPC-E-22-22.
►That the Company be directed to hold a technical workshop to review its methodologies for line loss
calculations prior to filing its next ECR update recommendation presumably in April of 2025.
7. Integration Costs
As noted by Staff, the Company proposes to use its 2020 VER integration study to provide an integration cost
of $0.00293/kWh to be accounted as a reduction to the proposed ECR. The Company presumes that Case 1 of
that 2020 study (which assumes zero storage on the Company’s system) is still most fitting. Staff’s comments
did not address which Case scenario evaluated in the 2020 VER integration study was most accurate. The
Company now has 120MW of storage online and another 60MW under development.16
As noted in CEO’s initial comments as well as Vote Solar’s initial comments, Case 9, which assumes 200MW
of storage and implies an integration cost of $.00064/kWh, is now a more accurate representation of the
Company’s system than Case 1 which assumed zero storage.
►CEO requests that the proposed ECR be updated to reflect the integration costs of $.00064/kWh associated
with Case 9 rather than the $0.00293/kWh the Company proposed.
8. Environmental Attributes
CEO acknowledges that avoided costs for environmental benefits may be currently assigned to zero in an ECR
effective January 1, 2024 yet reiterates our request that this docket provide a placeholder, process, and platform
to value the potential for the Company to avoid costs or increase revenues by utilizing the renewable energy
attributes associated with customer on-site generation.
Staff’s comments regarding avoided environmental costs assumed that customers retain ownership of REC’s.17
IIPA makes similar comments related to customers retaining ownership of the renewable attribute of their
exports.18 CEO maintains that the ownership of renewable attributes is transferrable.19 There is the potential for
14 IPC-E-21-21, Order 35284 at 20, the Commission found: “It 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.”
15 ORDER NO. 35631, p 29: “We believe that additional discussion between Staff, Intervenors, and the Company on the
topic of avoided line losses, during the implementation case, may be fruitful and potentially resolve any remaining issues
or confusion surrounding the Company’s calculation of avoided line losses.”
16 IDACORP Q2 2023 Earnings Conference Call, August 3, 2023.
17 IPC-E-23-14, Initial Comments by IPUC Staff at 24, “Regarding Renewable Energy Credits ("RECs"), ownership
remains with the owner of the on-site generation system absent an RPS or other legislation.”
18 IPC-E-23-14 IIPA comments page 2 “net metering participants retain RECs and all renewable attributes of their net
production, thus these customers should not be compensated as if these attributes are being provided to IPC”
CLEAN ENERGY OPPORTUNITIES – REPLY COMMENTS - 7
the Company to avoid costs it would otherwise incur to purchase REC’s (a quantifiable avoided cost) by
substituting the renewable attributes of the exports it purchases from self-generating customers. This potential
needs to be reviewed.
For the year 2022, the Company purchased 37,519 MWh renewable energy certificates at an expense of
$266,379.34 to fulfill the needs of the Green Power Program.20 Further, as described in CEO’s initial
comments, some portion of the customers who are willing to pay a 1¢ premium for renewable energy may value
the option to purchase renewable attributes of exports from self-generators in their community even if those
exports were not formally certified by Green-e or other entity.
Given informal discussion among stakeholders in response to initial comments, 8.1. reflects a modification to
CEO’s specific proposal in initial comments, while 8.2 and 8.3 reiterate our requests from initial comments:
8.1 Schedule 6 should be modified such that a) customers would, by default, transfer ownership of the
renewable energy attributes of their exports to the Company, b) customers may opt out of this transfer, and
c) the effective date for such transfer will begin with exports occurring on or after the effective date of the
2025 ECR update.
Given that transfer of ownership is an important step toward monetizing renewable energy attributes, CEO
requests that if the Company does not support this specific proposal, the Company then propose for the
Commission’s consideration an alternative means to establish a path such that customers will have the
option to transfer ownership of renewable energy attributes to the Company.
8.2 CEO requests that the Company be directed to evaluate opportunities for customer-owned generation to
provide a resource for avoiding the costs the Company would otherwise incur to serve potential Clean
Energy Your Way (CEYW) Flexible customer needs.
8.3 CEO requests that, as part of the annual ECR update, the Company should report on opportunities to
monetize the value of renewable energy attributes of exports (including opportunities where the renewable
attributes are not formally certified as RECs) as well as opportunities for aggregation and/or certification of
customer-owned generation. More generally, CEO is asking that a placeholder in the ECR value stack be
defined to ensure ongoing evaluation of opportunities to monetize the value of renewable energy attributes
of customer-owned resources, and that ECR methodology should retain an annual calculation of
environmental benefits.
9. Effective Date, Gradualism, & Timing of ECR Update
CEO remains empathetic for the Residents and Small General Service customers who have sought to manage
their rising energy costs via on-site generation and assumed that the regulatory process applies principles of
gradualism across all customer classes, including Schedules 6 & 8. While Staff notes that the regulatory process
has provided notice of the potential for changes to rates affecting on-site generation, CEO reiterates that notice
does not substitute for gradualism in the regulation of rates.
CEO maintains that customer classes are impacted differently, and that changes to Schedule 84 should be
implemented January 1, 2024. Past dockets have built a substantial record of agribusinesses requesting visibility
as soon as possible to Schedule 84 changes affecting the design and compensation structure for on-site
generation. A few representative examples include –
19 Rocky Mountain Power Service Schedule NO. 107,
https://www.rockymountainpower.net/content/dam/pcorp/documents/en/rockymountainpower/rates-
regulation/utah/rates/107_Solar_Incentive_Program.pdf
20 Idaho Power Response to CEO Production Request No. 2.
CLEAN ENERGY OPPORTUNITIES – REPLY COMMENTS - 8
In IPC-E-20-26, agribusinesses asked that the Commission do “everything it can to enable farmers to make
informed decisions on solar generation during 2021.” 21
In IPC-E-21-21, the Idaho Farm Bureau asked that the study be conducted in an “efficient, thorough, fair,
and expedited manner” and reiterated a request “that this entire process be done in a timely manner for
Idahoans to take advantage of funding opportunities that exist to aid those that may choose to pursue on-site
generation.” 22
In IPC-E-22-12, the Idaho Grain Producers Association commented, “Improving the predictability and
stability of export compensation rates is critical for farmers.” 23
In reply to one party’s proposal to delay implementation of the ECR until June of 2024: for Schedule 84, CEO
strongly favors Staff’s proposal to implement the proposed changes January 1, 2024 and that the first update
occur in 2025 given the need for stability and the harm of further delay. A farmer commenting in IPC-E-22-12
summarized the matter: “As many farmers testified to the PUC in 2020, we are harmed by the delay in
addressing the 100kW cap and a lack of predictability or stability of the future export credit rate.”24
For residents and small general service customers, if the Commission does not support proposals by other
commenters concerned with gradualism, CEO supports Staff’s request for a January 1, 2024 effective date and
for the first update to be filed in April 2025, which aligns with CEO’s request in initial comments.
10.Project Eligibility Cap for Schedule 84.
CEO supports the IPC-E-23-14 proposed changes to the Schedule 84 project eligibility cap.
11.IIPA proposal to include market predictions in tariffs
IIPA asserts that, given market prices may decline over time, that the ECR will decline, and therefore “IPC
should provide notice of this by including tariff language that informs customers of the expected decreases in
the net export credit over time.” CEO opposes this proposal for many reasons, two of which include: 1) A tariff
is not the place to make predictions regarding future market prices, 2) the Commission does not have evidence
supporting a declaration of future market prices. Market prices have gone both up and down since the VODER
study was ordered. Natural disasters, a potential carbon adder, and other unforeseen events could impact the
value of the ECR as well as rates for consumption over the coming decade.
If the Commission believes that visibility to future ECR is merited, a more appropriate approach would be a
mechanism for publishing an indicator of the next year’s ECR based on the trailing twelve months of available
data. CEO offers this suggestion not as a request, only as a more appropriate alternative than ordering that a
presumption of future market prices should be incorporated into tariffs.
III. Closing Remarks
While there are vastly different views regarding the regulation of on-site generation in Idaho, we can all agree
on two things – that an order in this docket will reflect a significant milestone, and that the journey will
continue. The energy world keeps changing, which challenges us all to maintain an open, curious, and adaptive
mindset. As Idaho grows, technologies evolve, and the Company invests $3 billion of capital expenditures over
the next five years, maintaining the affordability of electricity in Idaho requires an ongoing and collective effort
to better understand the drivers of costs and benefits. That endeavor will serve Idaho well by informing rates
21 IPC-E-20-26 public comment, Michael N. Kochert, Roseberry Farms, Gooding, Idaho, 12/28/2020
22 IPCE-21-21 public comment, Idaho Farm Bureau, 11/30/21.
https://puc.idaho.gov/Fileroom/PublicFiles/ELEC/IPC/IPCE2121/PublicComments/20211130Comments(38)_38.pdf
23 IPC-E-22-12 Public Comment, Idaho Grain Producers Association, 12/19/2022.
https://puc.idaho.gov/Fileroom/PublicFiles/ELEC/IPC/IPCE2212/PublicComments/20220720Comments(2)_2.pdf
24 IPC-E-22-12 Public Comment, Russell Schiermeier, 12/19/2022.
CLEAN ENERGY OPPORTUNITIES – REPLY COMMENTS - 9
which allow customers the freedom to control their own energy costs and the opportunity to mitigate future
costs for all.
Dated this 2nd day of November, 2023.
______________________________
Courtney White
Managing Director
Clean Energy Opportunities for Idaho
CERTIFICATE OF SERVICE
I hereby certify that on this 2nd day of November, 2023. I delivered true and correct
copies of the foregoing COMMENTS to the following persons via the method of service noted:
Electronic Mail Delivery
Idaho Public Utilities Commission
Jan Noriyuki
Commission Secretary
[e-mail]
Idaho PUC Staff
Chris Burdin
Deputy Attorney General
Idaho Public Utilities Commission
[e-mail]
Idaho Power Company
Megan Goicoechea Allen
Lisa D. Nordstrom
Timothy Tatum
Connie Aschenbrenner
Grant Anderson
[e-mail]
[e-mail]
[e-mail]
[e-mail]
[e-mail]
[e-mail]
City of Boise
Darrell G. Early
Wil Gehl
[e-mail]
[e-mail]
[e-mail]
Idaho Conservation League
Matthew Nykiel
Brad Heusinkveld
[e-mail]
[e-mail]
CLEAN ENERGY OPPORTUNITIES FOR IDAHO - IPC-E-23-14
IdaHydro
Tom Arkoosh
[e-mail]
[e-mail]
Idaho Irrigation Pumpers Association, Inc.
Eric L. Olsen
Lance Kaufman
[e-mail]
[e-mail]
Micron Technology, Inc.
Jim Swier
[e-mail]
Austin Rueschhoff
Thorvald A. Nelson
Austin W. Jensen
[e-mail]
[e-mail]
[e-mail]
[e-mail]
[e-mail]
Vote Solar
Abigail R. Germaine
Kate Bowman
[e-mail]
[e-mail]
_____________________________
Kelsey Jae
Attorney for CEO
CLEAN ENERGY OPPORTUNITIES FOR IDAHO - IPC-E-23-14