20221223Compliance Filing.pdf

MEGAN GOICOECHEA-ALLEN
Corporate Counsel
mgoicoecheaallenidahopower.com

December 23, 2022

VIA ELECTRONIC FILING

Jan Noriyuki, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg 8,
Suite 201-A (83714)
PO Box 83720
Boise, Idaho 83720-0074

Re: Case No. IPC-E-22-06
In the Matter of Idaho Power Company’s Application for Approval of a
Replacement Special Contract with Micron Technology, Inc. and A Power
Purchase Agreement with Black Mesa Energy, LLC

Dear Ms. Noriyuki:

Attached for electronic filing is Idaho Power’s Compliance Filing in the above-entitled
matter.

Please feel free to contact me directly with any questions you might have about this
filing.

Very truly yours,

Megan Goicoechea-Allen

MGA:sg
Enclosure
RECEIVED
Friday, December 23, 2022 1:45:33 PM
IDAHO PUBLIC
UTILITIES COMMISSION
IDAHO POWER COMPANY’S COMPLIANCE FILING - 1
MEGAN GOICOECHEA ALLEN (ISB No. 7623)
DONOVAN E. WALKER (ISB No. 5921)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]
[e-mail]
Attorneys for Idaho Power Company
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY’S APPLICATION FOR
APPROVAL OF A REPLACEMENT
SPECIAL CONTRACT WITH MICRON
TECHNOLOGY, INC. AND A POWER
PURCHASE AGREEMENT WITH BLACK
MESA ENERGY, LLC.
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CASE NO. IPC-E-22-06
IDAHO POWER COMPANY’S
COMPLIANCE FILING
Idaho Power Company (“Idaho Power” or “Company”), pursuant to Idaho Public
Utilities Commission (“Commission”) Order No. 35532,1 hereby respectfully submits the
following compliance filing for the rate structure to calculate Micron Technology, Inc.’s
(“Micron”) Renewable Capacity Credit (“RCC”) under Micron’s Revised Special Contract
(“Micron ESA”).
I. INTRODUCTION
As more fully described herein, in its compliance filing, Idaho Power proposes to
implement an RCC performance mechanism payment structure that was the outcome of
1 Order No. 35532, p. 6, 10.
IDAHO POWER COMPANY’S COMPLIANCE FILING - 2
significant collaboration with Staff and the Company. Importantly, while the proposed
performance mechanism does not match existing prescribed Incremental Cost Integrated
Resource Plan (“ICIRP”) Qualifying Facility (“QF”) storage methodology for agreements
under the Public Utility Regulatory Policies Act of 1978 (“PURPA”), the recommended
approach achieves the spirit of the Commission’s directive, while also addressing
limitations associated with application of the ICIRP QF storage method to non-
dispatchable Clean Energy Your Way (“CEYW”) resources. Specifically, the proposed
approach determines unique per-renewable-Power Purchase Agreement (“PPA”)-
resource specific performance standards and eliminates the potential to over-
compensate for capacity from the renewable PPA resource.
II. BACKGROUND
On August 1, 2022, the Commission issued its ruling on Idaho Power's Application
seeking approval of the Micron ESA in Order No. 35482, which directed, in pertinent part,
modifications to the Micron ESA, including use of a new method for calculating RCCs
based on Staff’s recommendations: “We find it fair, just, and reasonable that the RCC
utilize the rate and payment structure for IRP-based energy storage projects.”2 The
Commission instructed the Company to file an updated ESA and Schedule 26 based on
its modifications.
In response, the Company filed a Petition for Clarification and Reconsideration,
which, among other things, sought clarification on how to calculate the RCCs under the
Micron ESA. ln granting the Company's Petition, the Commission found it would be
beneficial to have the Company and Staff “work together to develop a rate structure for
2 Order No. 35482, p. 17.
IDAHO POWER COMPANY’S COMPLIANCE FILING - 3
calculating Micron's RCC under the ESA which the Company shall file as a compliance
filing in this case by December 13, 2022."3 Subsequently the Company requested
additional time, until December 23, 2022, to work through details of the rate structure and
finalize understanding between Idaho Power and Staff, which was granted by the
Commission on December 13, 2022.4
Beginning November 2, 2022, with a two-hour in-person meeting between Staff
and Idaho Power, significant collaborative efforts have been undertaken to implement the
Commission’s directive. In total, Staff and the Company have participated in six meetings,
with the most recent held December 14, 2022. In the early discussions, it became
apparent that simply implementing the ICIRP QF methodology could result in unexpected
outcomes. As the discussions progressed, the Company and Staff identified several
critical elements necessary for inclusion in a performance mechanism applied to a large
non-dispatchable CEYW-Construction resource that can have a large impact on the
Company’s system. This proposal provides the following, including additional elements
that are not present in the existing ICIRP QF storage methodology:
 Payment for performance during specific hours;
 Emphasis of current system capacity need;
 Recognition of the resource’s capacity contribution to the Company’s resource
stack even as critical hours shift through time (new);
 Non-dispatchable renewable resource agnostic (new);
 Reduced risk of capacity payment over-compensation (new);
 Incent renewable resources to maintain performance in consideration of future
3 Order No. 35532, p. 10.
4 Order No. 35625, p. 1.
IDAHO POWER COMPANY’S COMPLIANCE FILING - 4
capacity need (new).
The proposed RCC performance mechanism improves upon the ICIRP QF storage
methodology for capacity payments. Limitations of the ICIRP QF storage methodology in
meeting all the elements listed above are described in more detail in Section IV.
It is important to highlight regardless of which performance mechanism is utilized,
the proposed, or the ICIRP QF storage methodology, the eligible first year for payment,
and annual value of capacity for which Micron has the opportunity to receive payment for
is identical in either approach. That is, applying either the Company’s proposed method
or the ICIRP QF storage methodology both utilize the same Commission-directed
calculation to determine the RCC numerator and eligibility date.5 Both of these variables
are locked in at the time of PPA execution and remain unchanged for the duration of the
PPA.
That RCC numerator is defined as:
Capacity Contribution based on the methodology from the most recently
acknowledged IRP * nameplate of the renewable resource * levelized capacity value
of the least-cost selectable capacity resource from the most recently
acknowledged IRP.
In the case of the Black Mesa project: 36.42% * 40,000 kilowatt (“kW”) *
$121.19/kW-yr; or $1,765,496 annually, with Micron eligible to begin receiving RCC
payments July 1, 2026.
III. BATTERY STORAGE QUALIFYING FACILITIES AVOIDED CAPACITY
PAYMENT BACKGROUND
As discussed above in reviewing the ESA between Micron and Idaho Power, Staff
recommended, and the Commission agreed, that the avoided capacity cost rate and
5 Order No. 35482, p. 17.
IDAHO POWER COMPANY’S COMPLIANCE FILING - 5
payment structure used to compensate PURPA IRP-based energy storage QF projects
should be applied in the Micron ESA. As noted by Staff, “the PURPA energy storage
payment structure . . . departed from previous PURPA rate structures when it was initially
developed. . .”6
As alluded to by Staff’s comment, Idaho’s implementation of PURPA has been an
ongoing and iterative process based on changing circumstances, emerging technologies,
and the benefit of hindsight. In a series of cases culminating in 2012, the Commission
overhauled PURPA implementation in Idaho, including setting the published and
negotiated cost rate parameters that are still used today. It noted, however: “As is evident
from this Commission’s history with PURPA, avoided cost methodologies, inputs and
calculations need to be reviewed and refreshed periodically.”7
To carry out the purpose and intent of PURPA - that a utility pays a QF only the
costs it avoids by not having to build or procure alternative energy - the Commission
previously confirmed that payments for both energy and capacity should be considered
in determining avoided costs. Considering a QF’s ability to provide capacity to a
purchasing utility against the backdrop of PURPA’s “must take obligation” and in
recognition of the fact that “[t]he value of all renewable resources is not equal”, the
Commission noted:
PURPA requires public utilities to purchase generation from QFs without
regard for whether the utility needs the energy. If a QF resource provides
energy but no capacity, then the utility is not avoiding a portion of costs that
will be required to build generation that provides capacity.8
6 Staff’s Answer to Petitions for Reconsideration, p. 3.
7 In the Matter of the Commission’s Review of PURPA QF Contract Provisions Including the Surrogate
Avoided Resource (SAR) and Integrated Resource Planning (IRP) Methodologies for Calculating Avoided
Cost Rates, Case No. GNR-E-11-03, Order No. 32697, p. 14 (Dec. 18, 2012).
8 Id., p. 16 (emphasis added).
IDAHO POWER COMPANY’S COMPLIANCE FILING - 6
Under these circumstances the Commission determined that assigning a value to a QF’s
ability to provide capacity using a resource-specific capacity factor would encourage QFs
to develop resources that would provide the utility with capacity that it actually needs.
More recently, advances in battery technologies to meet energy storage needs
raised the question of how this type of QF resource should be treated under Idaho’s
PURPA framework. One such shortcoming with the method that was in place subsequent
to the 2012 orders was that it failed to account for the nuances of the utility’s incremental
capacity needs such that avoided capacity cost payments did not accurately capture the
avoided cost of capacity or encourage the QF to dispatch stored energy in a manner that
would contribute to the Company’s actual capacity needs. In order to fully recognize the
“time-shifting value of battery storage QFs,” Staff recommended implementing more
granular avoided cost rates in an effort to align economic interests of QFs with the
Company’s needs.9 In calculating capacity for battery storage QFs, Staff felt that fine
tuning the existing ICIRP Method by only paying capacity cost payments if the QF
generated during peak hours would more accurately value the time difference of capacity
and would incentivize a battery storage QF to actually contribute to the Company’s
capacity needs.10
Ultimately the Commission agreed with Staff’s recommendations regarding how
battery storage QFs should be treated under Idaho’s PURPA framework. In pertinent part,
the Commission found that avoided cost rates for battery storage QFs above the project
eligibility cap should be calculated using the ICIRP Method for avoided energy rates and
9 In the Matter of Idaho Power’s Petition to Determine the Project Eligibility Cap for Published Avoided
Cost Rates and the Appropriate Contract Length for Energy Storage Facilities, Case No. IPC-E-20-02,
Revised Comments of the Commission Staff, p. 7 (Aug. 27, 2020).
10 Id., p. 14.
IDAHO POWER COMPANY’S COMPLIANCE FILING - 7
an Idaho-specific version of the Duke Energy Method for calculating capacity, under
which avoided capacity rates are paid for production hours identified as Company’s peak
hours as opposed to averaging capacity payments over all hours.11
The Commission ordered the Company to file an updated avoided cost capacity
methodology to be used in the mandatory purchases of battery storage QF PURPA
generation. In its compliance filing, Idaho Power noted its understanding of the
Commission’s directive was that no changes to the avoided cost of capacity in the ICIRP
Methodology were to be made except that the capacity portion of the avoided cost rate
should be paid only during peak hours.12 Accordingly, the Company made no changes to
the underlying methodology that calculated the avoided cost of capacity for battery
storage QFs and only changed the payment of that capacity amount to being paid only
during peak hours rather than being paid upon every kilowatt-hour (“kWh”) of generation.
The Commission approved the Company’s Compliance Filing with a modification relating
to updating peak hours.13
Though the Micron ESA is not under the scope of PUPRA, which is a complex
regulatory scheme with multiple interconnected variables, Staff initially recommended
that the PURPA energy storage payment structure be implemented with respect to the
Micron ESA. “The hallmark of this payment structure is its pricing for production delivered
during ‘peak’ and ‘premium peak hours’.”14 The Company was concerned with this
proposed application for a single, CEYW-specific large project, which can be easily
identified through time when it came online and the term it will provide capacity, because
11 Id., Order. No. 34794, p. 10 (Oct. 2, 2020).
12 Id., Idaho Power Company’s Compliance Filing, p. 2 (Oct. 30, 2020).
13 Id., Order No. 34913, p. 6-7 (Feb. 5, 2021).
14 Staff’s Answer, p. 3.
IDAHO POWER COMPANY’S COMPLIANCE FILING - 8
the Commission’s determination relative to avoided capacity for battery storage QFs was
based on a very different set of circumstances, distinguishable from the Micron ESA as
to both the type of resources at issue and the underlying legal framework.
As to the first matter, the efficacy of efforts to motivate a QF to shape or shift their
energy production necessarily depends on the resource type; as the Commission has
noted the “value of all renewable resources is not equal.” For example, an energy storage
QFs ability to be dispatched on demand means it can be influenced to adjust its
operations in response to price signals. As the Commission Noted in Case No. IPC-E-20-
02:
By identifying its Peak Hours and Premium Peak Hours, the utility sends a
price signal to energy storage QFs to dispatch energy at the times the utility
most needs the energy. Because energy storage QFs can alter their output
to respond to price signals, identifying and pricing high-value hours
accordingly can encourage QF development and help the utility avoid
higher-cost resources, benefiting ratepayers.15
An intermittent resource QF, on the other hand, cannot control when it generates and is
therefore unable to adjust its output to align with utility needs as they shift through time,
it does, however, continue to provide the capacity benefit, and is relied on in its position
in the Company’s resource stack as was determined when the resource joined the
system.
Moreover, in reviewing a transaction under PURPA, the Commission’s interest in
ensuring that QFs are adequately incentivized to align their output with the Company’s
needs ensures that ratepayers are kept indifferent from the utility’s must purchase
obligation. Because a QF has the ability to force a utility to take its power outside of the
15 Case No. IPC-E-20-02, Order No. 34913, p. 6 (emphasis added).
IDAHO POWER COMPANY’S COMPLIANCE FILING - 9
utility planning process and even if it does not need the power, the Commission’s role in
this regard is critical since the Company itself is constrained.
Despite its concerns, the Company has been working with Staff diligently and in
good faith in an effort to implement the Commission’s intent for treatment of RCCs under
the Micron ESA. The results of the effort are set forth in this compliance filing.
IV. LIMITATIONS OF IRP-BASED ENERGY STORAGE PROJECT CAPACITY
PAYMENT MECHANISM
As the Company worked to incorporate the ICIRP Storage QF methodology, it
quickly identified both challenges of using that methodology for a non-dispatchable
resource, and through collaboration with Staff, additional critical elements which the
ICIRP Storage QF methodology does not meet. In applying the Peak Hour and Premium
Peak Hour payment methodology to Micron’s RCC numerator, both the Company and
Staff agree it meets the first two elements of emphasizing current system capacity need
through payment for resource performance during specific hours.
However, that prescriptive method has limitations which are addressed by the
proposed performance mechanism. First, there is potential to both over-compensate, and
not recognize the value of capacity the renewable resource provides. The Peak Hour and
Premium Peak Hour rate is determined by dividing the RCC numerator by the expected
kWh output of the renewable resource in those respective critical hours. While the
renewable resource will on average over time perform similar to the expected output,
actual output will be lower or higher than forecast in any given month. In any month above-
forecast generation occurs, that additional generation is multiplied by the fixed Peak Hour
or Premium Peak Hour rate and the potential exists that payments will exceed the RCC
IDAHO POWER COMPANY’S COMPLIANCE FILING - 10
numerator in those periods.
A single renewable resource the scale of Black Mesa, with nameplate of 40,000
kW, can be easily tracked to identify when and the amount of capacity it provides the
system, along with the duration of the PPA to identify the term under which the Company
can continue to expect that capacity be delivered. In terms of recognition of the resource’s
capacity contribution to the Company’s resource stack as critical hours shift through time,
the Commission directed updates to the RCC Peak Hours and Premium Peak Hours
occur every two years with acknowledgement of the IRP. There is potential that future
Peak Hours and Premium Peak Hours, representing the Company’s future capacity
needs, shift to a portion of the day when solar does not generate. However, the renewable
resource continues to provide capacity to the Company’s resource stack as identified at
the time of PPA execution. If that capacity position in the Company’s resource stack is
not maintained, hours of critical need may arise in hours outside of the deemed Peak
Hours and Premium Peak Hours, resulting in not recognizing the capacity benefit the
resource continues to provide through time. This outcome is counter to the Commission’s
rationale in determining that once a QF qualifies to receive capacity payments, contract
renewals and extensions continue to receive capacity payments because “an existing
QF’s capacity would have already been included in the utility’s load and resource
balance…”.16 It is the expectation that the CEYW renewable resource continues to deliver
the capacity it was evaluated for at the time of PPA execution, and maintains its position
in the Company’s resource stack to meet load requirement, even if future capacity needs
present themselves in other periods of time.
16Case No. GNR-E-11-03, Order No. 32697, p. 21.
IDAHO POWER COMPANY’S COMPLIANCE FILING - 11
Issues identified above are present for the Black Mesa solar resource, but the
considerations are magnified for other non-dispatchable resources such as wind. Idaho
Power agrees that providing payments only for capacity actually delivered to Idaho
Power’s system is an important mechanism to be included in RCCs, and the Company
believes it’s proposed performance mechanism achieves the same intent as directed by
the Commission, with additional enhancements which incentivize the resource to perform
as expected for that resource. It is critical that resource capacity contributions remain in
their position in the Company’s resource stack through time. If they do not because only
a small band of critical hours are incentivized based on today’s need, it creates a future
risk of a resource not delivering capacity in “non-critical hours” as initially modeled at the
time of PPA execution, which results in a “capacity hole” for capacity needs if today’s non-
critical hours become critical in the future, such as winter periods.
V. PROPOSED RENEWABLE CAPACITY CREDIT PAYMENT PERFORMANCE
MECHANISM
Included as Attachment 1 is a detailed description of the methodology for
Company’s proposed RCC performance mechanism for monthly payments. The
proposed mechanism may be summarized as paying for performance in critical hours
based on system needs today, as well as a weighting for future system needs. The goal
of the proposed RCC performance mechanism is that performance is measured in a
resource-agnostic manner, and compensation is offered to that resource as an incentive
to perform at the output expected for that specific resource. The maximum value Micron
is eligible to be paid for capacity delivered by the Black Mesa project is capped at the
RCC annual numerator of $1,765,496.
IDAHO POWER COMPANY’S COMPLIANCE FILING - 12
A. Determination of Critical Periods
The first step is to determine the months of capacity need at the time of PPA
execution in the year the resource is expected to come online, in this case 2023. Because
Black Mesa utilized the National Renewable Energy Laboratories (“NREL”) 8,760-based
top 100 hours methodology to determine capacity contribution, the 2023 monthly load
and resource balance was utilized to determine monthly capacity needs. For future CEYW
resources, Effective Load Carrying Capability will be the basis for capacity contribution
determinations, and monthly capacity needs will be calculated from Loss of Load
Expectations (“LOLEs”). Next, Idaho Power anticipates future load conditions in 2027 will
have considerable differences from today’s load conditions and used the 2027 load and
resource balance to also determine monthly LOLEs. The combination of the 2023 and
2027 LOLEs is used to inform the appropriate minimum and maximum values, critical
hours, seasonal groupings, and monthly weighting. The value of the annual RCC
numerator is spread to each month based on monthly weighting, representing the
maximum RCC payment value if the renewable resource performs as expected in the
identified monthly critical hours. As listed in Table 1 below, today’s critical hour needs
represent the overwhelming majority of weighting, 70 percent in the June through August
period, but weighting is also included for future winter needs to incent the resource to
maintain output the Company will rely on outside of today’s critical periods.
IDAHO POWER COMPANY’S COMPLIANCE FILING - 13
Table 1. Proposed Maximum Monthly Performance Payments
Month Weight Payment
January 5.25% $ 92,689
February 5.25% $ 92,689
March 0% $ -
April 0% $ -
May 0% $ -
June 17.50% $ 308,962
July 35.00% $ 617,924
August 17.50% $ 308,962
September 4.50% $ 79,447
October 4.50% $ 79,447
November 5.25% $ 92,689
December 5.25% $ 92,689
Total 100% $ 1,765,496
For the Black Mesa resource, this results in three seasons with unique critical
hours (hour beginning to hour ending):
 Winter (Nov-Feb) 6:00 am to 11:00 am and 5:00 pm to 10:00 pm
 Summer (June-Aug) 2:00 pm to 11:00 pm
 Non-summer (Sept-Oct) 6:00 am to 11:00 am
B. Performance Measurement
The energy generation of the Black Mesa project will be evaluated during these
hours and compared to the potential energy generation as measured by a co-located
Plane of Array irradiance measurement device. The comparison of actual generation and
expected generation during these critical hours results in a performance ratio, which is
evaluated against the performance metric target, 1.0 October through February, and 0.95
June through September. The less than 1.0 performance metric target for June through
September reflects that the performance metric captures irradiance variation but does not
capture the impact of temperature on solar array performance. High temperature impact
is considered in determining capacity contribution of the resource, so this adjustment is
IDAHO POWER COMPANY’S COMPLIANCE FILING - 14
necessary to maintain consistent assumptions between the determination of capacity
contribution and what expected generation at the site is actually possible. The ratio of
actual generation to expected generation informs the reduction to capacity payment for
that month.
The performance mechanism methodology described above is specific to a solar
project, however, the same concepts may be applied to wind projects with measurement
of wind speed, hub height, and rotor diameter to calculate expected performance.
In addition to the six elements previously listed as benefits of the proposed
mechanism as compared to the ICIRP QF storage method, this methodology provides for
a unique performance benchmark specific to the PPA resource. If additional CEYW solar
resources are added in the same year, each project is evaluated for critical hours in
consideration of each preceding project, including the impacts of those projects on critical
hours as well as in determination of season groupings, something not completed by the
ICIRP QF storage methodology.
Finally, the proposed method eliminates the opportunity for a developer to be
overcompensated for capacity because the maximum cap on monthly payments and
output measurement methodology ensures no additional compensation is possible.
VI. ALTERNATIVE IRP-BASED ENERGY STORAGE PROJECT RENEWABLE
CAPACITY CREDIT PAYMENT PERFORMANCE MECHANISM
Idaho Power believes the proposed performance mechanism captures the spirit of
the Commission’s directive for capacity payments to only be paid for capacity delivered
to Idaho Power’s system. The comprehensive work between Staff and Idaho Power to
develop and refine the proposed performance metric incorporates concerns Staff raised
IDAHO POWER COMPANY’S COMPLIANCE FILING - 15
in the filing which drove their initial recommendation to apply the ICIRP QF storage Peak
Hour and Premium Peak Hour payment mechanics to Micron’s RCC. If the Commission
believes the proposed performance metric is not aligned with the Commission’s directive,
Idaho Power presents an alternative RCC payment approach consistent with the ICIRP
methodology but for two modifications developed with Staff’s input.
A. Rates Set for Term of PPA
As noted earlier, the Commission directed updates to the RCC Peak Hours and
Premium Peak Hours occur every two years with acknowledgement of the IRP. Because
there is potential for future Peak Hours and Premium Peak Hours to shift outside of solar
generating hours, Idaho Power proposes Peak Hours and Premium Peak Hours be
locked for the duration of the 20-year PPA based on the currently-approved hours.
Peak Hours: Hours that occur in July starting at 2:00 PM and ending at
10:59:59 PM, and hours that occur in August starting at 4:00 PM and ending
at 8:59:59.
Premium Peak Hours: Hours that occur in July, starting at 5:00 PM and
ending at 8:59:59 PM, and hours that occur in August, starting at 5:00 PM
and ending at 8:59:59 PM.17
B. Non-Premium Peak and Premium Peak Hour Differential
In developing the alternative RCC payment rates, Idaho Power incorporated a
methodology update proposed by Staff, 18 and agreed to by Idaho Power,19 as part of the
17 Idaho Power Company’s Annual Compliance Filing to Update the Load and Gas Forecasts in the
Incremental Cost Integrated Resource Plan Avoided Cost Model, Case No. IPC-E-21-35, Supplement to
Idaho Power Company’s Annual Compliance Filing, p. 3 (Nov. 5, 2021), approved by Order No. 35395
(May 4, 2022).
18 Idaho Power Company’s Annual Compliance Filing to Update the Load and Gas Forecasts in the
Incremental Cost Integrated Resource Plan Avoided Cost Model, Case No. IPC-E-22-26, Staff Comments
p. 9-10 (Dec. 6, 2022).
19 Id., Reply Comments, p. 2 (Dec. 13, 2022).
IDAHO POWER COMPANY’S COMPLIANCE FILING - 16
Company’s annual Compliance Filing to update the load and gas forecasts in the ICIRP
avoided cost model. Specifically, Staff recommended to modify the calculation of the Non-
Premium Peak and Premium Peak hour such that rates for Premium Peak Hour are
consistently 20 percent above Non-Premium Peak Hour rates without changing the total
amount of annual capacity payments that a qualifying facility can receive. The calculation
of the Non-Premium Peak Hour rate is as follows, with a 20 percent premium applied to
Premium Peak Hour rates. Idaho Power proposes this methodology update be applied to
the alternative RCC payment rates as well.
Non-Premium Peak Hour rates = Annual Capacity Payment / (Generation
during Non-Premium Peak Hours * Generation during Premium Peak
Hours * 1.2)
C. Alternate RCC Payment Rates
Incorporating the two modifications described above, the alternate RCC payment
rates for Micron’s Black Mesa project are $0.219609 per kWh for Peak Hour output, and
$0.263530 per kWh of Premium Peak Hour output for the 20-year term of the Black Mesa
PPA. Attachment 2 includes Black Mesa projected output and calculations of Peak Hour
and Premium Peak Hour rates.
VII. OTHER CONSIDERATIONS
As an outcome of the additional study of existing PURPA ICIRP QF storage
methodology in development of the proposed mechanism for Micron and discussion
with Staff, Idaho Power remains open to the application of those discussions to the
capacity methodologies applied to PURPA avoided cost pricing and will continue to
work with Staff towards any modifications or changes that would make sense for
customers in that context.
IDAHO POWER COMPANY’S COMPLIANCE FILING - 17
VIII. CONCLUSION
The collaborative process directed by the Commission has resulted in an improved
performance mechanism for Micron’s RCC payments. The diligent work between Staff
and Idaho Power to address the expressed concerns that payments for capacity
contribution only be made for energy actually delivered to Idaho Power’s system has
additionally addressed shortfalls of the ICIRP QF storage methodology when applied to
a non-dispatchable resource. Idaho Power thanks Staff for their time and effort in working
with the Company to develop a proposed performance mechanism that addresses
additional elements uncovered during the collaborative process. Idaho Power believes
the proposed performance mechanism not only meets the Commission’s intent but is a
superior methodology that captures the unique impacts of each CEYW renewable
resource, including those added in the same year as other CEYW resources. The ability
to incentivize performance to meet today’s system capacity needs, while ensuring the
resource performs as expected in the future, provides recognition of Idaho Power’s
reliance on that resource’s capacity contribution.
In Order No. 35532, the Commission stayed its initial directive for Idaho Power to
file an updated Micron ESA and Schedule 26 addressing the Commission’s modifications
by October 30, 2022, pending the outcome of reconsideration in this case.
Reconsideration of issues in this case has been settled, and in light of the anticipated
commercial operation date of June 1, 2023 for the Black Mesa project, Idaho Power
respectfully requests the Commission approve the Company’s proposed performance
mechanism to calculate Micron’s RCC payments by May 1, 2023 to provide for 30 days
for the Company to file a final Micron ESA and Schedule 26 by June 1, 2023.
IDAHO POWER COMPANY’S COMPLIANCE FILING - 18
Respectfully submitted this 23rd day of December 2022.
MEGAN GOICOECHEA ALLEN
Attorney for Idaho Power Company
IDAHO POWER COMPANY’S COMPLIANCE FILING - 19
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on the 23rd day of December 2022, I served a true and
correct copy of the foregoing Idaho Power Company’s Compliance Filing upon the
following named parties by the method indicated below, and addressed to the following:
Riley Newton
Deputy Attorney General
Idaho Public Utilities Commission
Po Box 83720
Boise, Idaho 83720-0074
Emailed to:
[e-mail]
Industrial Customers of Idaho Power
Peter J. Richardson
RICHARDSON ADAMS, PLLC
515 North 27th Street (83702)
Boise, Idaho 83707
Emailed to:
[e-mail]
Dr. Don Reading
6070 Hill Road
Boise, ID 83703
Emailed to:
[e-mail]
City of Boise
Ed Jewell
Deputy City Attorney
Boise City Attorney’s Office
150 North Capitol Boulevard
P.O. Box 500
Boise, Idaho 83701-0500
Emailed to:
[e-mail]
[e-mail]
Wil Gehl
Energy Program Manager
Boise City Dept. of Public Works
150 N. Capitol Blvd.
PO Box 500
Boise, Idaho 83701-0500
Emailed to:
[e-mail]
________________________________
Stacy Gust, Regulatory Administrative
Assistant

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-06

IDAHO POWER COMPANY

ATTACHMENT 1

PROPOSED PAYMENT STRUCTURE

Attachment 1 – Case No. IPC-22-06 - Proposed Payment
Structure for Micron & CEYW

The base annual payment will be determined based on the Effective Load Carrying
Capability (“ELCC”) methodology. The ELCC value will be calculated with the “last-in”
ELCC approach at the time of contract execution. A “last-in” ELCC value means that the
project will be modeled after all existing and contracted resources have been added to
the resource stack.
The in-service year shall be used as the Load and Resource (“L&R”) year for the
calculation of the ELCC. When available, a rolling average of the last eight years of
historical data will be used to determine the ELCC. If/when eight years of data are not
available, the maximum amount of historical data available will be used.
The final ELCC is calculated by taking the average of each of the ELCC values
calculated using each of the historical years scaled to the desired L&R year:
𝐸𝐿𝐶𝐶= 𝐸𝐿𝐶𝐶
𝑁
In the case of Micron, the contract was executed before the acknowledgement of
the Company’s 2021 Integrated Resource Plan (“IRP”). During the 2019 IRP, capacity
contribution was calculated based on the 8,760-based method developed by the National
Renewable Energy Laboratories (“NREL”).
The capacity contribution calculated at the time of contract execution was 36.42%.
The annual payment is determined by multiplying the average capacity contribution, as
calculated by the ELCC method (or NREL 8,760-based method for projects executed
before the 2021 IRP acknowledgement), by the avoided cost of capacity. The avoided

cost of capacity is the levelized fixed cost associated with the least-cost dispatchable
resource from the Company’s most recently acknowledged IRP; for the 2019 IRP the
identified resource was a reciprocating internal combustion engine (“RICE”), and for the
2021 IRP the identified resource was a simple-cycle combustion turbine. For the case of
Micron, the avoided cost of capacity at the time of contract execution was RICE with
levelized capacity cost of $121.19 kW per year.
Determine Annual Payment
The annual payment is calculated by multiplying the capacity contribution times
the nameplate of the selected project times the avoided cost of capacity:
𝐴𝑛𝑛𝑢𝑎𝑙 𝑃𝑎𝑦𝑚𝑒𝑛𝑡=𝐸𝐿𝐶𝐶∗𝑁𝑎𝑚𝑒𝑝𝑙𝑎𝑡𝑒∗𝐴𝑣𝑜𝑖𝑑𝑒𝑑 𝐶𝑜𝑠𝑡 𝑜𝑓 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦
Applying the annual payment calculation to the Micron project, the resulting value
is determined to be $1,765,496 per year:
𝐴𝑛𝑛𝑢𝑎𝑙 𝑃𝑎𝑦𝑚𝑒𝑛𝑡=(36.42%)∗(40,000 𝑘𝑊)∗$121.19
𝑘𝑊∙𝑦𝑟= $1,765,496/𝑦𝑟
Determine Months of Capacity Need
The annual payment will be calculated at the time of contract execution and
distributed proportionally over the months that capacity is expected to be needed. To
determine the months of capacity need, the LOLE per month of the different historical
years would be used to calculate an average LOLE for each month. If a significant
resource stack change is expected in the near future, a five-year case would be used to
guide the monthly weighted average calculations. For the Micron case, the average
monthly LOLE values for the 2023 L&R year are described in Table 1.

Table 1. 2023 L&R Average Monthly LOLE
Month Average LOLE
January 0.0011
February 0.0001
March 0.0000
April 0.0000
May 0.0000
June 0.0167
July 0.1113
August 0.0258
September 0.0034
October 0.0001
November 0.0042
December 0.0062
In the Micron case, because the contract was executed prior to the 2021 IRP
acknowledgement the NREL 8,760-based method was used to determine capacity
contribution, there were no monthly LOLE values calculated. A 2023 L&R year was used
to determine the months of capacity need because it is the year the project is expected
to be online. Idaho Power is expecting a considerable shift in its load forecast within the
next five years; to capture this change in load, a 2027 L&R was analyzed to obtain the
average and weighted monthly LOLE values as shown in Table 2.

Table 2. 2027 L&R Average & Weighted Monthly LOLE
Month 2027 Average LOLE 2027 Weighted LOLE
January 0.2309 2.74%
February 0.0148 0.18%
March 0.0004 0.00%
April 0.0000 0.00%
May 0.0000 0.00%
June 0.5088 6.05%
July 2.9850 35.47%
August 1.0587 12.58%
September 0.1477 1.76%
October 0.0351 0.42%
November 1.3934 16.56%
December 2.0399 24.24%
Non-Summer Average 5.10%
From the 2027 L&R, an average LOLE of the non-summer months was calculated
to be utilized as a minimum value for the non-summer months (also excluding March,
April, and May) in the 2023 L&R. The minimum monthly LOLE was added to the
corresponding average monthly LOLE calculated in the 2023 L&R. Using the results from
the 2023 L&R and 2027 L&R, the monthly LOLE weighted averages are described in
Table 3.

Table 3. Monthly LOLE Weighted Average
Month Weighted Average
January 4.40%
February 3.94%
March 0.00%
April 0.00%
May 0.00%
June 7.58%
July 50.49%
August 11.71%
September 5.43%
October 3.94%
November 5.79%
December 6.73%
The twelve months of the calendar year can be grouped into three different periods
given their Loss of Load Probability (“LOLP”) profiles, as described in the bulleted list
below:
 Summer which includes June, July, and August
 Winter which includes January, February, November, and December
 Off-season which includes September and October
Note that March through May will remain at 0%. A weighted average per period is
calculated by adding the percentages of each month within the corresponding period
together, as shown in Table 4.

Table 4. LOLE Weighted Average per Period
Summer Winter Off-Season
June 7.57% January 4.40% September 5.44%
July 50.49% February 3.95% October 3.95%
August 11.71% November 5.80%
December 6.72%
Summer Total ~70% Winter Total ~21% Off-Season Total ~9%
For the winter and off-season periods, the total is spread out relatively evenly over
the various the months; this means the approximate 21% for the winter total would be
divided by the 4 months for 5.25% and the approximate 9% for the off-season total would
be divided by the 2 months for a 4.5%.
For the summer period, the high LOLP hours span from the last 2 weeks of June
through the first 2 weeks of August (totaling 8 weeks), meaning there are 4 weeks in July,
2 weeks in June and 2 weeks in August that encompass the high LOLP hours. Since the
summer total is set to equal the approximate 70%, the high LOLP hours weekly weighting
can be used to smooth the summer period spread:
 June - 70% ∗
= 17.5%
 July - 70% ∗
= 35.0%
 August - 70% ∗
= 17.5%
The final weights by month are shown in Table 5.

Table 5. Seasonal Monthly LOLE Weighted Average
Month Weighted Average
January 5.25%
February 5.25%
March -
April -
May -
June 17.5%
July 35.0%
August 17.5%
September 4.5%
October 4.5%
November 5.25%
December 5.25%
The monthly payment is calculated by taking the previously calculated annual
payment of $1,765,496 per year and multiplying it by the weighted average for each
month, as shown in Table 6.
Table 6. Seasonal Monthly Payment
Month Weighted Average Monthly Payment
January 5.25% $92,689
February 5.25% $92,689
March - -
April - -
May - -
June 17.5% $308,962
July 35.0% $617,924
August 17.5% $308,962
September 4.5% $79,447
October 4.5% $79,447
November 5.25% $92,689
December 5.25% $92,689
Total 100.00% $1,765,496

Performance Metric
The Performance Ratio (“PR”) is a metric widely used to track performance of
photovoltaic (“PV”) systems in the industry.123 The PR metric can be used to ensure a
project is being well maintained and is performing as expected. PR can be defined as the
ratio of measured output to the expected output for a given reporting period based on the
system nameplate rating. Traditionally, PR is mathematically expressed as
𝑃𝑅=
𝑘𝑊ℎ
𝑘𝑊,
𝑘𝑊ℎ
𝑚
1𝑘𝑊
𝑚

where
𝑘𝑊ℎ=𝐸𝑛𝑒𝑟𝑔𝑦 𝐺𝑒𝑛𝑒𝑟𝑎𝑡𝑒𝑑 𝑏𝑦 𝑡ℎ𝑒 𝑃𝑙𝑎𝑛𝑡
𝑘𝑊,=𝑅𝑎𝑡𝑒𝑑 𝐷𝑖𝑟𝑒𝑐𝑡 𝐶𝑢𝑟𝑟𝑒𝑛𝑡 𝑃𝑜𝑤𝑒𝑟 𝑜𝑓 𝑡ℎ𝑒 𝑃𝑙𝑎𝑛𝑡 𝑎𝑡 𝑆𝑡𝑎𝑛𝑑𝑎𝑟𝑑 𝑇𝑒𝑠𝑡 𝐶𝑜𝑛𝑑𝑖𝑡𝑖𝑜𝑛𝑠
𝑘𝑊ℎ=𝑃𝑙𝑎𝑛𝑒 𝑜𝑓 𝐴𝑟𝑟𝑎𝑦 (“𝑃𝑂𝐴”) 𝐼𝑟𝑟𝑎𝑑𝑖𝑎𝑛𝑐𝑒
The PR metric is most often used by power plant operators to track plant
performance. Idaho Power proposes to modify the previously shown equation to consider
the contracted nameplate of the plant on the Alternating Current (“AC”) side and not on
the Direct Current (“DC”) side. The contract with Idaho Power is on the AC side and it has
the potential to be the limiting factor during operation. The proposed modification would
result in the following PR equation:
𝑃𝑅=𝑘𝑊ℎ
𝑘𝑊,∗𝑘𝑊ℎ

1 IEC 61724-1: 2017 Photovoltaic System Performance
2 Performance of Photovoltaic Systems Recorded by oSPARC, NREL 2020
3 PV System Performance Assessment, Sunspec Alliance, San Jose State University, 2014

One of the interconnection requirements is for the project to provide Idaho Power
with weather data via Supervisory Control and Data Acquisition (“SCADA”). One of the
variables required is the Plane of Array (“POA”) irradiance (𝑘𝑊ℎ). The energy injected
into the system is also measured via SCADA, making the PR calculation relatively simple.
Performance Ratio Target
The PR metric is directly influenced by the energy output which is proportional to
irradiance and inversely proportional to module temperature. The PR equation accounts
for irradiation; changes in irradiation will have little effect on the PR. However, changes
in temperature are not accounted for in the PR calculation and the PR will decrease as
temperature increases. To account for the impact of temperature on the PR calculation,
Idaho Power proposes to set a different PR target for the summer months than the non-
summer months. The Company proposes to use the PR targets described in Table 7 and
graphically displayed in Figure 1.
Table 7. PR Targets by Period
Period Target
January through May 𝑃𝑅≥1.0
June through September 𝑃𝑅≥0.95
October through December 𝑃𝑅≥1.0

Figure 1. PR Targets by Month
Hours of Need
Capacity is only avoided during certain hours of the calendar year. The hours
where capacity is needed are the hours which have high LOLP values. To provide
compensation for capacity when it is needed, the PR metric will be calculated based on
the high LOLP hours of each period for the 2023 L&R, which have been identified in Table
8.
Table 8. 2023 L&R High LOLP Hours
Period Identified High LOLP Hours (Hour End)
Summer 3:00 pm - 11:00 pm
Winter 7:00 am - 11:00 am & 6:00 pm - 10:00 pm
Off-Season 7:00 am - 11:00 am
For clarification, the hours presented in Table 8 are Hour Ending (“HE”). Using
the summer period as an example, 3:00 pm HE represents the hour spanning from 2:00
pm to 3:00 pm while 11:00 pm HE represents the hour spanning from 10:00 pm to 11:00
2 4 6 8 10 12
Month of the Year
0.5
0.6
0.7
0.8
0.9
1
Performance Metric Threshold by Month

pm; this means the identified summer period high LOLP hours begin at 2:00 pm and
conclude at 11:00 pm.
Reduction on Payment
To receive the full monthly payment, the project will have to meet the PR threshold
in the corresponding high LOLP hours (as set in Table 8). If the PR is not met, a reduction
in payment will be applied to the project. The reduction will be calculated based on the
impact to capacity as measured by the ELCC. The impact on capacity will be determined
by reducing the output of the project and calculating its ELCC. For the Micron project, the
relationship between output and ELCC reduction was calculated over the range of 0.5 PR
to 1.0 PR, as shown in Figure 2.

Figure 2. Relationship Between PR & ELCC
The results shown in Figure 2 would be used to determine the monthly payment
reduction if the project did not meet the monthly PR target. If any month where capacity
0
20
40
60
80
100 Performance Ra o vs ELCC
0.5 0.6 0.7 0.8 0.9 1
PV Output

payments are applied do not meet the corresponding target PR, a reduction as presented
in Figure 2 would be applied (the reduction is calculated by interpolating between the
monthly PR value and the target PR value for that month). As an example of how the PR
versus ELCC approach would be implemented, data for a similar project near the Micron
site was collected for the 2021 L&R; the PRs were then calculated for the corresponding
high LOLP hours of each month with the results shown in Table 9 (bolded values
represent calculated PR values that did not meet the targets identified in Table 7).
Table 9. Monthly Performance Ratio & Payment Example
Month Performance Ratio Payment Reduction Monthly Payment
January 1.08 0.00% $92,689
February 1.13 0.00% $92,689
March - - -
April - - -
May - - -
June 0.98 0.00% $308,962
July 1.00 0.00% $617,924
August 0.99 0.00% $308,962
September 0.97 0.00% $79,447
October 1.01 0.00% $79,447
November 1.11 0.00% $92,689
December 0.98 1.80% $91,020
Total $1,763,828

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-06

IDAHO POWER COMPANY

ATTACHMENT 2

ALTERNATE RCC RATE WORKPAPER
IPC-E-22-06 - Attachment 2 - Alternate RCC Payment Rate
Hour Start Hour End Hour January February March April May June July August September October November December (a)Nameplate (kW)40,000
12:00 AM 1:00 AM 1 - - - - - - - - - - - - (b)2019 IRP Capacity Contribution 36.42%
1:00 AM 2:00 AM 2 - - - - - - - - - - - - (c)2019 IRP Surrogate Resource Value ($/kW-yr)121.19$
2:00 AM 3:00 AM 3 - - - - - - - - - - - - [ a * b * c ]Capacity Value from 2019 IRP 1,765,496$
3:00 AM 4:00 AM 4 - - - - - - - - - - - -
4:00 AM 5:00 AM 5 - - - - - - - - - - - - (c)
5:00 AM 6:00 AM 6 - - - - 0 1 0 - - - - -
6:00 AM 7:00 AM 7 - - - 3 11 16 11 3 0 - - -
7:00 AM 8:00 AM 8 - 0 4 19 28 30 30 23 13 4 0 -
8:00 AM 9:00 AM 9 1 6 21 33 32 35 35 34 27 22 8 1
9:00 AM 10:00 AM 10 13 18 26 34 34 36 37 36 31 29 17 11
10:00 AM 11:00 AM 11 15 21 30 34 34 36 37 37 33 28 18 14
11:00 AM 12:00 PM 12 14 23 30 33 34 38 38 37 34 27 18 14
12:00 PM 1:00 PM 13 14 22 28 33 34 38 39 36 34 26 18 13
1:00 PM 2:00 PM 14 15 22 28 31 34 37 38 35 32 27 18 13
2:00 PM 3:00 PM 15 15 23 27 30 33 35 37 36 34 28 20 14
3:00 PM 4:00 PM 16 16 24 27 29 31 32 38 35 35 27 18 13
4:00 PM 5:00 PM 17 8 21 26 28 31 30 35 34 33 20 5 3
5:00 PM 6:00 PM 18 0 6 17 26 32 30 29 30 21 3 0 -
6:00 PM 7:00 PM 19 - 0 2 8 20 22 20 13 3 - - -
7:00 PM 8:00 PM 20 - - - 0 2 5 4 1 - - - -
8:00 PM 9:00 PM 21 - - - - - - - - - - - -
9:00 PM 10:00 PM 22 - - - - - - - - - - - -
10:00 PM 11:00 PM 23 - - - - - - - - - - - -
11:00 PM 12:00 AM 24 - - - - - - - - - - - -
Annual Capacity Credit IPC-E-21-35 Hours:
Daily Generation (MWh)peak 109 34
premium peak 53 44
Days in Month 31 31
Monthly Generation (MWh)peak 3,368 1,051
premium peak 1,645 1,372
Total kWh peak 4,418,458
premium peak 3,017,357
Rate/kWh peak
premium peak
Annual $ check
20% premium peak check 20%
1,765,496$
Black Mesa Generation Profile
https://puc.idaho.gov/Fileroom/Publi
cFiles/ELEC/IPC/IPCE2135/CaseFiles/
20211105Supplement%20to%20Appl
ication-Redacted.pdf
https://puc.idaho.gov/Fileroom/PublicFiles/ELEC/IPC/IPCE19
19/CaseFiles/20201002Appendix%20C%20Technical%20Repo
rt.pdf
https://puc.idaho.gov/Fileroom/PublicFiles/ELEC/IPC/IPCE19
19/CaseFiles/20201002Second%20Amended%202019%20IRP
.pdf
1,765,496$
0.219609$
0.263530$