20250515Comments.pdf

RECEIVED
May 15, 2025
Kelsey Jae (ISB No. 7899) IDAHO PUBLIC
Law for Conscious Leadership UTILITIES COMMISSION
920 N. Clover Dr.
Boise, ID 83703
Phone: [phone]
[e-mail]
Attorney for Clean Energy Opportunities of Idaho
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO )
POWER COMPANY'S )
APPLICATION FOR ITS FIRST )
ANNUAL UPDATE TO THE ) CASE NO. IPC-E-25-15
EXPORT CREDIT RATE FOR ) CLEAN ENERGY OPPORTUNITIES
NON-LEGACY ON-SITE ) FOR IDAHO
GENERATION CUSTOMERS FROM )
JUNE 1, 2025 THROUGH MAY 31, ) COMMENTS
2026, IN COMPLIANCE WITH )
ORDER NO. 36048 )
Pursuant to Commission Order No. 36558, Clean Energy Opportunities for Idaho
("CEO") hereby submits these comments and a request for hearing.
DATED this 15th day of May, 2025.
Respectfully submitted,
ot)"v
Kelsey Jae
Attorney for CEO
CLEAN ENERGY OPPORTUNITIES FOR IDAHO - COMMENTS
IPC-E-25-15

V Clean Energy Opportunities for Idaho
May 15, 2025
Reference: Case No. IPC-E-25-15
Subject: Comments of Clean Energy Opportunities for Idaho
Clean Energy Opportunities for Idaho (CEO)respectfully submits the following Comments regarding
IPC-E-25-15,the ECR Update. Our comments address and propose remedies to the following concerns:
1. The assumption that integration costs for utility-scale solar are equivalent to integration costs for
on-site exports is inaccurate,unsupported by evidence and, as such,unreasonable.
2. The stability of export credit rates can be improved without harm to their accuracy in ensuring
that the computation of such rates aligns with the actual hourly pattern of exports by using a
multi-year rolling average of exports weighted by each year's market prices.
3. Customers should not be charged for their exports, a policy embedded in the proposed calculation
of the ECR energy component.The VODER docket intent of using market prices was to establish
the value of"energy that Idaho Power would otherwise generate or purchase"in order to
determine an appropriate financial credit. The purpose was not to evaluate costs incurred to
receive an export.
4. Price signals for consumption conflict with price signals for exports,which harms customers.
5. A limit to the reduction in the ECR is merited given the range of uncertainty regarding fair export
compensation,the value of benefits too complex to quantify for the small scale of exports, and the
disproportionate harm to certain customers.
1 The assumption that integration costs for utility-scale solar are equivalent to integration
costs for on-site exports is inaccurate,unsupported by evidence and, as such,unreasonable
The VER integration report states:
While the VER integration study determined the cost of accommodating additional utility scale
solar,the Company found that a utility scale profile is a reasonable proxy for the shape of onsite
solar generation.As such,the Company assesses that the integration costs identified in this report
are an appropriate input to the ECR without modification. '
Within that report the Company offered no data to support its assertion"a utility scale profile is a
reasonable proxy for the shape of on-site solar generation."For reasons listed below, CEO believes that
the pattern of exports made by customers with self-generation differs substantially in quantity,timing and
variability of output levels compared to utility-scale generation.
These differences in the pattern of exports would be expected to produce a lower integration cost per the
following logic: The VER study modeled years when the additional output of a 100MW solar generation
site would, absent adding reserve capacity to the system, exceed a hurdle threshold for an unacceptably
high risk of having Expected Unserved Energy(EUEs). A less variable stream of exports, in smaller
quantities during the highest risk summer hours,would be expected to produce fewer instances of
Expected Unserved Ancillaries(EUAs). Per the VER model's design,fewer EUAs would likely result in
fewer annual exceedances of Expected Unserved Energy(EUE)threshold. Lower EUE violations would
reduce the number of years and quantity of additional 50MW blocks of 4-hour battery storage needed. A
reduced quantity of additional battery requirements would reduce the cost to integrate customer exports.
' See IPC-E-25-07,Compliance filing Attachment A,2024 VER integration cost study,page 4
Clean Energy Opportunities for Idaho—IPC-E-25-15 Comments 1

W Clean Energy Opportunities for Idaho
The estimated quantity of regulating reserves required by ECR exports is not accurately reflected by the
inputs used in the VER study based on the following observations:
1. 1 Geographic diversification and the variability of solar output—
It is unclear whether the estimated monthly reg-up/reg-down reserve requirements produced to reflect the
variability in the hourly production patterns of a relatively small number of utility scale resource sites
used in the 2023 IRP analysiS2 are reflective of the variability of output(and associated reg-up/reg-down
reserve requirements) given the quantity and extensive geographic dispersion of the 13,800+non-legacy
exporting systems'in the ECR docket.The risks, and thereby reserve requirements, associated with 270
GWh of generation from a single 100MW utility-scale site used in the VER study is not the same as that
associated with 146 GWh of exports distributed across 13,800+customer sites.'CEO contends that the
probability of a cloud abruptly interrupting supply to the grid from a single location is higher than risk of
a disruption in supply from a geographically diverse portfolio of sites.As a consequence,the level of
reserves needed for"reg-up or reg-down"requirements is likely to be lower for the 13,800+broadly
distributed potential export sites than the values used in the VER study,producing an inherent cost bias
against the geographically diversified exports associated with ECR rates.
1.2 Fixed vs Tracking systems and the associated generation patterns—
CEO works from an assumption that while some non-legacy exporting systems may use solar panels
installed on tracking systems,the vast majority of such systems use fixed panels. This assumption is
supported by the very large difference between the annual outputs of the solar systems in the VER study
(which display a 29%capacity factor) and the 16%1 CF for the non-legacy systems.
Fixed panel systems inherently have a narrower diurnal production pattern than systems that track the sun
all day. As displayed in the figure below,tracking systems at utility-scale sites enable generation to
Residential Exports v.Jackpot Generation Pattern Tracking systems extend Jackpot's generation
for July(%of total for the month) into hours of system stress.The ECR capacity
16% value reflects the lower value of this export
pattern,yet the ECR integration charge does
14% not reflect the lower portion of exports during
12% these high stress hours associated with
reserve requirements
8% .....
6%
4%
2%
0% ---
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 2
—Res ••••Jackpot
z See discussion preceding as well as contents of Table 9.1,2023 Integrated Resource Plan,p123
'IPC-E-25-15,Attachment 2,2024 DER Annual Status Report,p7,Table 3,Non-Legacy Active and Pending
Exporting Systems as of December 31,2024.
' 10OMW x 8760 Ins x 31%capacity factor=271.6 MWh; Exports sourced from IPC-E-25-15 Exhibit 2
5 5,116,037 MWh of incremental energy generated by a 100MW solar system over 20 years(see 2024 VER
Integration cost study page 13)implies an average capacity factor over that period of 29.2%
(5116037/20/8760=29.2)while the 1,362 kWhs per kilowatt(see Taylor direct p 4)value for non-legacy systems
implies an average capacity factor of 15.5%
Clean Energy Opportunities for Idaho—IPC-E-25-15 Comments 2

W Clean Energy Opportunities for Idaho
extend into hours more associated with system stress. CEO expects that the sufficiency of regulating
reserves will be especially stressed during late aftemoon/early evening summer periods. The generation
patterns of utility scale systems, on which the proposed integration charges are based, are likely to have a
level during these late afternoon/early evening summer periods of high system stress that is not
representative of the"stress"that self-generator exports would produce. Consequently, CEO believes
there is reason to believe that the VER study overstates the instances of Expected Unserved Ancillaries
(EUAs)(and their associated cost for more reserve requirements)than would be produced by pattern
based on non-legacy system exports.
1.3. Exports:�Generation: The pattern of non-legacy system exports is substantially different from
the pattern of utility scale generation.
On an hourly basis, export patterns are net of consumption and different from generation patterns.As
shown in the figure below,in July when utility-scale solar is putting all its generation onto the grid, on-
site generators are typically running their AC or irrigation system and consuming all or a high portion of
their on-site generation.
Two factors appear relevant here:
Export patterns are not the same as utility-scale
• in the VER report the Company generation patterns
asserts that its analysis applies
to ECR matters based on a of Annual Total Exports excl.Irrigators
comparison of generation 14% ackpot Generation
patterns. The ECR docket 12% ,,,,1
focuses on export,not Irrigator
generation,patterns. 1046 Exports
8%
• reserve requirements-which
drive integration costs -are 6%
particularly associated with 4% For example,6.6%of a exports by
Irrigators occurred in July,while
hours in which the system is 2% 12.2%of generation by Jackpot
stressed due to high loads occurred in July.
relative to supply. CEO 0%
Jan Feb Mar Apr May Lune July Aug Sep Oct Nov Dec
intuitively expects that the
lower level of non-legacy
system exports compared to utility system generation on summer evenings would result in the non-
legacy systems causing fewer instances of Expected Unserved Ancillaries(EUAs) and their
associated costs.
Requested remedy
As detailed above, CEO would posit as fact that the integration costs associated with generation from a
single 10OMW of utility-scale solar site are not equivalent to the integration costs associated with exports
from 123MW of solar distributed across 13,800+sites. The scope of that inaccuracy is unknown. The
scope of revenue requirements associated with this matter can be roughly estimated at$600k6, an impact
which harms a small set of customers yet with negligible benefit to the average customer. CEO believes it
would be unfair to increase the integration costs charged to on-site generators in the absence of an
accurate evaluation of integration costs specific to on-site generation. CEO suggests 2 alternative
remedies-
10.4 increase in integration costs times 146 GWh/yr of exports,the latter from IPC-E-25-15 Exhibit 2 Exports tab
Clean Energy Opportunities for Idaho—IPC-E-25-15 Comments 3

V Clean Energy Opportunities for Idaho
1. Order a technical hearing to address the concerns CEO raises related to the reasonableness of using
the PURPA VER integration cost estimates as a proxy for the integration costs associated with on-
site generator exports in this round of ECR rate updates, or
2. Make no change to integration costs in the 2025 ECR update; direct a review to occur such that any
potential changes to integration costs become effective in the 2026 ECR update after sufficient
review of the costs associated with integrating exports made by customers with self-generation.
2 A multi-year rolling average of energy market prices would improve stability with minimal
decrease in accuracy.
During the review of matters related to the VODER study, a concern was raised related to the use of
forecast market rather than historical market prices. The argument for using multi-year energy price
forecasts was based on the recognition that ECR rate updates would be applied only to future exports and
thus future hourly cost estimates should be used. The counter argument was that self-generators show a
particular pattern of exports that is influenced by weather conditions and that because future weather and
export patterns cannot be predicted,weighting hourly historical prices by hourly historical patterns of
exports would provide additional accuracy. In the"battle"between stability and accuracy,the accuracy
argument won.
A lesson learned in this first ECR update is that an energy value based on a singular year of market prices
results in high instability(e.g.,the 80%decrease in the Non-Summer ECR). This lack of stability causes
unnecessary harm.
In its 2022 VODER Study,the Company presented an approach using a 3-year ELAP price data':
The value for the ECR, for purposes of the study,uses a historically based indicative price based
on a three year average of the ELAP price.The three-year average was provided to illustrate an
average price using recent data; however,it is important to note there are a variety of
implementation possibilities if the Commission were to adopt the ELAP Price as an input.
The harm to customers resulting from the instability of the ECR can be reduced with no substantial
decrease in accuracy by using a rolling average of export weighted energy market prices across multiple
years.
Requested remedy
CEO suggests, in any potential update to the ECR,that the energy component utilize 3 to 5 years of
historical market prices in order to offer customers greater stability while creating little risk of inaccuracy
and associated subsidization by the average customer.
3 CEO opposes the policy of charging customers for their exports.
The energy component of the ECR assumes that if the market price is negative in a given hour,then Idaho
Power incurred an actual cost equivalent to the negative market price,which then lowers the average
"credit"for exports.
'IPC-E-22-22,October 2022 VODER Study,p42
Clean Energy Opportunities for Idaho—IPC-E-25-15 Comments 4

1P Clean Energy Opportunities for Idaho
Purpose of Market Price Analysis
Consider in the VODER study, IPC-E-22-22,how Idaho Power describes the use of Market Prices in 4.1
AVOIDED ENERGY COSTS (p35):
When a customer generates energy in excess of its own energy consumption and exports it to
Idaho Power's system,the company may be able to use that energy to meet its customers'energy
needs.As a result,this will reduce the energy that Idaho Power would otherwise generate or
purchase.When this occurs, Idaho Power will avoid the cost of that generation or energy
purchase.
The intent of using market prices has been to establish the value of"energy that Idaho Power would
otherwise generate or purchase." The purpose is not to evaluate costs incurred to receive an export.
Negative prices 7�Actual costs
Negative market prices do not equate to actual costs incurred by the Company. Data provided by the
utility for 2023 EIM transactions indicates that, for the vast majority of hours when prices were negative,
the company was not in a position of selling excess power that hour and thus no showing is made that the
Company would incur a cost to accept exports from self-generators during that period.
Can't have it both ways
If charging customers for exports during certain hours is merited,the Company would be offering
Demand Side Management programs to pay customers to add load during those hours'. If Idaho Power is
expecting to incur costs -whether direct costs or opportunity costs-to absorb exports during hours when
market prices are negative,the IRP process should have allowed the AURORA model to select Demand
Side resources to lower costs by absorbing load in those hours.
Appropriate to revise
It is common practice for the Company, staff, and parties to seek continuous improvement in
methodologies for evaluating costs and determining rates. CEO believes it is appropriate to consider this
improvement in the ECR methodology.
Requested remedy
CEO asks that, in any potential ECR Update,the energy component of an export should not be valued at
less than zero at any given hour. I.e., in the weighted average calculation of avoided energy costs,
negative market prices should be set at zero.
s Utilities with much higher solar penetration than Idaho Power,such as Arizona Public Service,consider
opportunities to lower costs via Reverse Demand Response programs in which customers are compensated for
absorbing surplus supply on the grid.Idaho Power does not.
Clean Energy Opportunities for Idaho—IPC-E-25-15 Comments 5

V Clean Energy Opportunities for Idaho
4 The price signals for consumption conflict with price signals for exports,which harms
customers.
Cost causation varies hourly, a fact which holds true for consumption as well as exports. It is unfair to
subject customers to price signals for consumption that incentivize choices which are misaligned with
those incentivized by price signals for exports.
Regarding capacity costs,Mr. Ellsworth testifies'to the goal of incentivizing customer investments given
the time-varying nature of cost causation:
Q. Why does the Company believe it is reasonable to provide a time-variant credit for capacity?
A The procurement of capacity resources is driven by the identified hours of highest risk-the period
that capacity can be avoided. By aligning the period of capacity avoidance with that of the ECR, a
price signal is created that could incentivize customers to invest in or optimize systems to maximize
output during the period of capacity avoidance. Examples of a potential incentivized price signal with
a time-variant credit for capacity include systems with optimized direction of panels or installation of
energy storage devices.
Yet for consumption rates for non-residential customers, Idaho Power's high demand charges and flat(or
near-flat)volumetric rates have incentivized flat loads. E.g., demand charges have roughly doubled for
Irrigators in recent years.When an Irrigator makes an investment decision on pump size, a consideration
is that their power bill is lower if they pump 24/7. Shifting consumption out of the On-Peak window
defined in the ECR,and into hours when the cost to serve is low,would increase the customer's demand
charge. If the customer invests in solar,then the ECR tariff abruptly treats exports as being vastly
different in value across hours, and the ECR incentivizes pumps sized to allow demand flexibility. For
illustration,we encourage the Commission to review the comments of an affected irrigator posted May 5,
202510,who describes:
Idaho Power's irrigation rate structure of the past several decades has incentivized farmers to
build systems that run 24/7.This has placed us in a situation where we are largely unable to
mitigate rising electricity costs, especially since there is no incentive for irrigators, at large,to
shut off during peak-demand hours. In fact,under the current rate structure,my electric bill would
be higher if I designed a system with the capacity to shut off during peak-demand hours than if I
irrigated day-in and day-out. This fundamental misalignment could be remedied by giving
irrigators the option to pay a time-variable rate in lieu of demand charges.
Idaho's farming industry is foundational to our economy. Power costs affect the ability of Idaho irrigators
to compete, and many have turned to solar to help mitigate rising power costs. Customers should not bear
the harm of the delay in aligning consumption prices with hourly cost causation for energy and capacity.
The urgency to ensure tariffs align with hourly cost causation should be applied to rates for consumption,
and the harmful impact of this ECR update to many Idaho farmers merits pause.
9 Ellsworth direct testimony in IPC-E-23-14,p17
https:Hlf--puc.idaho.gov/WebLink/DocView.aspx?dbid=0&id=147491,see p32
Clean Energy Opportunities for Idaho—IPC-E-25-15 Comments 6

1p Clean Energy Opportunities for Idaho
Requested remedy
Before implementation of the severe reduction in off-peak and non-summer ECR proposed in IPC-E-25-
15 for customer classes with demand charges and no access to time-of-day volumetric rates, CEO asks
that rate design for consumption should be revised in the 2025 GRC to provide price signals more
accurately aligned with time-varying cost causation.
5 A limit to the reduction in the ECR is merited given the range of uncertainty regarding fair
export compensation,the value of benefits too complex to quantify for the small scale of
exports, and the disproportionate harm to certain customers.
"Not everything that counts can be counted"is an expression attributed to Einstein.Unfortunately for
customers,the contribution of distributed energy to risk mitigation and local grid resilience is difficult to
quantify.
Consider, for example,that Idaho will increasingly face risks of extreme weather and gas price volatility.
In its preliminary 2025 Integrated Resource Planning results,Idaho Power modeled the cost impact of
Extreme Weather,which resulted in a$2.7 billion increase in costs for its preferred portfolio. The impact
of High Gas and Carbon Tax resulted in a$3.2 billion increase in costs. On-site generation mitigates these
and many other risks which are complex to quantify.
Ahamd Faruqui spent years testifying on behalf of Investor Owned Utilities regarding concerns with net
metering,then later reformed his view. In Why did I reform my views on net metering," Dr. Faruqui
describes-
I am confident my reformed vision is in line with reality. Consumers,rich and poor,want to
install solar panels. They enhance affordability and green energy.When paired with batteries,
they enhance local resilience. They lower investments in the distribution and transmission system.
The impact of changes to the ECR are significantly harmful to a small set of customers with little impact
on the average customer. Every 1 � /kWh decrease in the Non-Summar ECR has substantial impact to
on-site generators,yet is associated with-roughly- less than$1 M in revenue requirements12.
Requested remedy
CEO has no easy remedy for calculating the additional benefits not reflected in the ECR. Given that
• there's a range of uncertainty regarding the accuracy of the proposed ECR,
• on-site generation offers benefits which are not reflected in the ECR, and
• the 80%reduction in non-summer ECR is acutely harmful to a small set of customers with little
benefit to the average customer,
CEO suggests that any potential reduction in the non-summer ECR by more than 50%would exceed the
norms of reasonableness and conflict with the principle of gradualism.
Respectfully submitted,
Courtney White,Managing Director and Mike Heckler,Policy Director
" Why did I reform my views on net metering?by Ahmad Faruqui,PV Magazine, September 27,2022
12 IPC-E-25-15 Exhibit 2,sum of total exports for non-summer months=86,539MWh
Clean Energy Opportunities for Idaho—IPC-E-25-15 Comments 7

1P Clean Energy Opportunities for Idaho
Clean Energy Opportunities for Idaho
Clean Energy Opportunities for Idaho—IPC-E-25-15 Comments 8

CERTIFICATE OF SERVICE
I hereby certify that on this 15th day of May, 2025, 1 delivered true and correct copies of
the foregoing COMMENTS to the following persons via the method of service noted:
Electronic Mail Delivery (See Order No. 34602)
Idaho Public Utilities Commission
Monica Barrios-Sanchez
Commission Secretary
secretary(d)puc.idaho.y,ov
Idaho PUC Staff
Chris Burdin
Deputy Attorney General
Idaho Public Utilities Commission
chris.burdin(a puc.idaho.gov
Idaho Power Company
Megan Goicoechea Allen
Donovan Walker
Connie Aschenbrenner
Mary Alice Taylor
Regulatory Dockets
mgoicoecheaallenOidahopower.com
[e-mail]
caschenbrennerna idahopower.com
mtaylor(@idahopower.com
dockets idahopower.com
City of Boise
Jessica Harrison
Katie O'Neil
BoiseCityAttorney(a)cityofboise.org
iarrison(a)cityofboise.org
koneilOcityofboise.org
Kevin Dickey
bellefourche0l(a)y,mail.com
Martha Bibb
marthsbigg(a)gmail.com
CLEAN ENERGY OPPORTUNITIES FOR IDAHO - COMMENTS
IPC-E-25-15

Scott Pinizzotto
s.pinizzoto@ gmail.com
Sierra Club & Vote Solar
Rose Monahan
Kate Bowman
Greg Adams
ro se.monahanO sierraclub.org
kbowman(@votesolar.org
gre�@richardsonadams.com
Kelsey Jae
Attorney for CEO
CLEAN ENERGY OPPORTUNITIES FOR IDAHO - COMMENTS
IPC-E-25-15