20210210Reply Comments - Redacted.pdf

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LISA D. NORDSTROM
Lead Counsel
[e-mail] :'r L":l':ii ***"ofgu, *
February 10,2021
VIA ELECTRONIC EMAIL
Jan Noriyuki, Secretiary
ldaho Public Utilities Commission
11331W. Chinden Blvd., Bldg 8,
Suite 201-A(83714')
PO Box 83720
Boise, ldaho 83720-0074
Re Case No. IPC-E-19-19
2019 Integrated Resource Plan
Dear Ms. Noriyuki:
Attached for electronic filing, pursuant to Order No. 34602, is ldaho Power
Company's Reply Comments. Although a portion of this document has been redacted, a
version containing the confidential table is being sent via encrypted email to the ldaho
Public Utilities Commission and those parties that have signed the Protective Agreement.
lf you have any questions about the attached documents, please do not hesitate to
contact me.
Very truly yours,
X* !-(^l-t,.*,
Lisa D. Nordstrom
LDN:slb
Attachment
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Table of Contents
INTRODUCTION...
BOARDMAN TO HEMINGWAY...
A. Boardman to Hemingway Partnership Risks...
1. ldaho Power's B2H Partners Remain Committed to the Project...
2. ldaho Power Commits to Securing the Best B2H Partnership Arrangement for
ldaho Power's Customers... ...
3. ldaho Power's 2021 IRP Will Model B2H Partnership Costs and Risks..
B. Modeling B2H in AURORA
C. Modeling B2H Costs...
D. B2H Capacity Acknowledged in 2017 IRP: STOP B2H's Oregon Arguments
E. B2H and Carbon Reduction Goals...
F. Mid-C Market and Market Purchase Opportunities in the Pacific Northwest..
L ldaho Power's PNW Market Assumptions are Realistic...
2. The Mid-C and the PNW Markets \Mll Continue to Have Sufficient Depth...... .
G. B2H and Transmission Path Constraints...
SOFTWARE SELECTION, VALIDATION AND VERIFICATION...
A. The AURORA Modelfor Resource Planning.
B. Simultaneous Optimization...
PORTFOLIO DESIGN AND ANALYSIS...
A. Portfolio Modification and Selection......
B. Manual Portfolio Adjustments.........
C. Stochastic Risk Analysis...
D. Regulation Reserve
E. Discount Rate...
SUPPLY.SIDE RESOURCES...
A. Jim Bridger Unit Retirements...
B. Costs and Characteristics of Supply-Side Resources......
C. Distributed Generation and Distributed Energy Resources.
D. Battery Storage...
E. Adjustments to Natural Gas Plants
F. Market Purchases.
VI. DEMAND.SIDE RESOURCES...
A. Energy Efficiency...
1. EE Savings Have Grown Steadily Over Time.
2. ldaho Power's EE Targets Are Consistent with lndustry Standards
B. Demand Response..
IDAHO POWER COMPANY'S REPLY COMMENTS - ii
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v[. FoRECASTS......
A. Load Forecast...
1. Aggregation Modeling and Sensitivity Analysis.........
2. Peak Load Forecast Magnitude.
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3. lnferred Econometric Modeling.
B. NaturalGas Price Forecasts..
C. Climate lmpacts on Loads and Generation........
VII!. LOAD AND RESOURCE BALANCE.
A. PURPA Contract Renewals..
B. Market Purchases.
tx.
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C. Non-Owned Reserves......
D. Energy Efficiency...
IDAHO POWER'S CARBON EMISSIONS
A. Emission Goal Baseline Year...
B. Thermal Fleet Operation and the ElM...
1. ldaho Power Efficiently Operates Langley Gulch and lts Broader Thermal
Fleet to Serve Customers \Mile Decreasing Overall Carbon lntensity......
2. ldaho Power's EIM Participation Benefits Customers......
REQUEST FOR EXTENSION TO FILE 2021 IRP...
GONGLUSION.,.
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IDAHO POWER COMPANY'S REPLY COMMENTS - iii
I. INTRODUCTION
Idaho Power Company ("ldaho Powe/' or "Company") respectfully submits these
Reply Comments to the ldaho Public Utilities Commission ("Commission"). These
comments respond to the comments of Straff of the ldaho Public Utilities Commission
("Staff'), STOP BzH Coalition ('STOP B2H" or "STOP"), Sierra Club, the ldaho
Conservation League ('lCL'), and Micron Technology, lnc. ("Micron").
The Second Amended 2019 /RP continues to demonstrate a clear cost-effective
and reliable trajectory toward ldaho Powe/s clean energy future. This commitment is
reflected in the Company's three key nearterm (2020-2026) action plan ("Action Plan")
items: (1) adding 120 megawatts ("MW') of new solar generation by 2022; (2) exiting
from four coal-fired units by year-end 2022, and from five of the Company's seven coal-
fired units by year-end 2026; and (3) completing the Boardman-to-Hemingway ("B2H')
transmission line by 2026. The development of B2H, in particular, provides a crucial
carbon-free and cost-effective, supply-side resource that supports renewables and
enables the Company's transition away from coal. As recently detailed in an extensive
new report by the Americans for a CIean Energy Grid,1 and echoed by multiple former
Federal Energy Regulatory Commission ("FERC") chairs and commissioners,2
1 Americans for a Clean Energy Grid, Planning for the Future: FERC's Oppoftunity to Spur More Cost-
Effective Transmission lnfrastructure at 24 (Jan. 2021) (noting that almost 90 percent of the 734 gigawafts
of proposed generators waiting in interconnection queues in 2019 were renewable and storage resources).
2 Jeff St. John, GreenTech Media, Report Calls for a Ground-Up Overhaul of Federal Transmission Grid
Policy (Jan. 28, 2021) ("There is no climate plan that is serious if it does not anticipate a significant regional
transmission upgrade[.]") (quoting Pat Wood lll, FERC chair 2001-2005); rd (describing the need for new
transmission investments: "Not only yes, but hellyes.') (quoting James Hoecker, FERC chair 1997-2001).
IDAHO POWER COMPANY'S REPLY COMMENTS - 1
substantial new regiona! transmission is crucial to achieving a truly clean energy future.3
Parties to this proceeding largely support the Company's Action Plan, with the
exception of STOP B2H's opposition to B2H. ldaho Power appreciates Staffs
recommendation that the Commission acknowledge the Company's Second Amended
2019 lRP, and Micron's thoughtfulcomments submifted in this case. With the benefit of
Staff and stakeholder feedback, ldaho Power has diligently worked to improve its
modeling process in this case, resulting in more efficient, transparent, and replicable
resource planning. Throughout this process, the Company's analysis has clearly and
consistently supported the developmentof additionalsolargeneration, the transition away
from coal, and the construction of B2H as the least-cost, Ieast-risk means to serve
customers.
II. BOARDMAN TO HEMINGWAY
Staff and STOP B2H are the only parties that submifted comments on the Boardman
to Hemingway ("B2H") transmission project, which is a critical resource in the Company's
least-cost, Ieast-risk preferred portfolio. STOP B2H's comments are nearly identical to
those filed in ldaho Power's Oregon IRP Docket, LC 74 and Staffs concerns on
partnerships and market depth are similarly included in STOP B2H's comments.
Therefore, much of the Company's Reply Comments below are essentially the same as
3 See, e.9., Jeff St. John, GreenTech Media, Transmission Emerging as Major Stumbling Block for State
Renewable Targets (Jan. 15, 2020) ("One of the key takeaways ffrom the third-party reportl is the mismatch
between where renewable supply is versus where it's going to be needed to meet the various mandates
and renewables goals being made in states and regions[.]") (quoting Larry Gasteiger, former FERC Deputy
Director); see a/so Energy Strategies, LLC, Wesfern Flexibility Assessmenf; lnvestigating the West's
Changing Resource Mix and the lmplications for Sysfem Flexibility at 9 (Dec. 10, 201 9) ("As the resource
portfolio evolves into the 2030s, the need for transmission becomes more obvious and resources face
transmission constraints. ").
a Staffs Comments at 3.
IDAHO POWER COMPANY'S REPLY COMMENTS.2
the Company's Final Comments in the OPUC's LC 74 docket,s and are included here to
provide a complete record.
A. Boardman to Hemingway Partnership Risks
ln the Second Amended 2019 lRP, ldaho Power reported on the status of its
negotiations with 82H project permitting co-participants, PacifiCorp and Bonneville Power
Administration ("BPA"). The project permitting co-participants are actively discussing
potential arrangements and associated agreements for ownership and cost responsibility
for B2H.6 ln letters sent to the Commission on July 1 and July 31 ,2O2O,ldaho Power
provided updates on the Company's discussions with BPA, in particular.T As the
Company explained, it is exploring a possible change in ownership structure with BPA,
whereby ldaho Power would acquire BPA's 24 percent ownership share of B2H and
provide transmission service to BPA's southeast ldaho customers; in return, BPA and/or
its customers would, over time, pay for their respective usage of B2H by recompensing
ldaho Power for BPA's share in the transmission line.
The primary purpose of these update lefters was to inform the Commission and
stakeholders that BPA and ldaho Power are considering transitioning BPA's B2H
ownership into a transmission service-based stake in the project. To be clear, the
Company's description of this potential ownership arrangement was not an
announcement of BPA pulling out of negotiations for the project. BPA, PacifiCorp, and
5 Filed on February 5,2021 .6 Case No. IPC-E-19-19, ldaho Power Company's Amended 2019 IRP Application, Attach. 1 at 19(hereinafter "Second Amended 2019 IRP') (Oct. 2, 2020) ('The company's assumption of BpA's
contemplated 24 percent ownership would be offset by the transmission wheeling service to BPA and/or its
customers.").
7 Case No. IPC-E-19-19, ldaho Power's Motion to Suspend Procedural Schedule and Update Regarding
Boardman to Hemingway Transmission Line Project at 6-7 (July 1,2020); Case No. lpC-E-19-19, ldaho
Power's Update and Request for Extension of Two Months to Complete Extended Analysis at 3-4 (July 31,
2020).
IDAHO POWER COMPANY'S REPLY COMMENTS - 3
ldaho Power each remain committed to permitting the project and continue to actively
fund their share of costs associated with the development of B2H.
One option for BPA's participation may involve repayment through transmission
service, with BPA and/or its customers paying for network integration transmission
service under the provisions of ldaho Power's Open Access Transmission Tariff ('OATT")
and entering into a transmission service agreement.s Under this possible arrangement,
BPA and/or its customers' OATT payments would, over time, provide recovery of ldaho
Power's transmission revenue requirement associated with BPA's respective usage of
B2H. Any change in ownership arrangements does not change ldaho Power's need for
B2H capacity.e
BPA and ldaho Power remain in active dialog over the ownership arrangement,
and ldaho Power is also engaged with PacifiCorp in the larger B2H discussions. Beyond
the previously provided updates, described above, ldaho Power has no new substantive
reports to provide, though this does not mean that no progress is being made. On the
contrary, the parties are continuing discussions in earnest. ldaho Power anticipates that
the ownership arrangements will be finalized by the time the Company files its 2021 lRP.
However, for the reasons stated below, ldaho Power does not believe that the
implications of these ownership arrangements materially impact the Prefened Portfolio
results or Action ltems in the Second Amended 2019 lRP.
8 Second Amended 2019 lRP, Appendix D at 59.
e Second Amended 2019 IRP a119.
IDAHO POWER COMPANY'S REPLY COMMENTS - 4
1. ldaho Power's B2H Partners Remain Committed to the Proiect.
Both Stafflo and STOP B2Hll voice concerns regarding the status of negotiations
with the 82H co-participants-requesting a detailed analysis of any changes in ownership
and financing arrangements, and questioning PacifiCorp's and BPA's commitment. As
noted above, because negotiations with BPA are not finalized, it is premature for the
Company to incorporate changes to the ownership that, at this stage, remain hypothetical.
But regardless of the ultimate ownership stakes, the Company will not agree to
anangements that shift cost risk to its retail customers without a conesponding increase
in benefit-and, as such, the Company does not expect material changes to its IRP
analysis stemming from BPA-related B2H ownership arrangements.
Regarding PacifiCorp's commitment to B2H, STOP B2H misunderstands
PacifiCorp's recent 2019 IRP filings while Staff remarks that B2H was not included in
PacifiCorp's 2019 IRP preferred portfolio and has very little presence or analysis in IRP
materials that would reveal the status of longterm commitment to 82H.12
STOP B2H points to PacifiCorp's discussion of B2H in that company's 2019 lRP,
in which PacifiCorp stated that it remains committed to the permitting of the project and
will continue to evaluate the benefits of the project throughout project development
activities, including moving fonrvard with preliminary construction.l3 STOP B2H also
points to PacifiCorp's explanation in response to a Staff DR submitted in PacifiCorp's
2019 lRP.14 ln that DR response, PacifiCorp explained that it did not include B2H in any
10 Staffs Comments at 10 (Jan. 20,2021).
11 STOP B2H's Comments at 7-12 (Jan.20,2021).
12 Staffs Comments at 10.
1a ln the Matter of PacifiCorp, dba Pacific Power, 2019 lntegrated Resource Plan, Docket LC 70, PacifiCorp
2019 lRP at 25, 77-79 (Oct. 18, 2019).
14 STOP B2H's Comments at 8-9.
IDAHO POWER COMPANY'S REPLY COMMENTS - 5
of its new transmission options in System Optimizer. While ldaho Power cannot speak
to the decision-making of another utility in its modeling process, PacifiCorp's own fina!
comments in the 2019 lRP make clear that the treatment of transmission in its modeling
is a technical question-not an issue of commitment to B2H as a least-cost, least-risk
resource.ls
Similarly, STOP B2H suggests that PacifiCorp is not commifted to the B2H project
by pointing to an old PacifiCorp Gateway West project called Hemingway-to-Captain Jack
("Captain Jack") as a B2H alternative-one which PacifiCorp is purportedly exploring.lo
STOP B2H appears to misunderstand the referenced footnote in PacifiCorp's lRP, which
states: "The Boardman-to-Hemingway project was pursued as an alternative to
PacifiCorp's originally proposed transmission segment from eastern ldaho into southern
Oregon (Hemingway to Captain Jack)."l7 ldaho Power understands that the Captain Jack
project was pursued by PacifiCorp over a decade ago; as far as ldaho Power is aware,
the Captain Jack project was long since abandoned.
ldaho Power believes that PacifiCorp remains committed to its longstanding plan
to assume a 55 percent ownership share in B2H. And while the details of the
arangements with all parties have yet to be finalized, the Company anticipates that
PacifiCorp will continue to support full participation in B2H going forward. Development
of B2H remains part of PacifiCorp's Action Plan in its most recent lRP.18
15 Oregon Docket LC 70, PacifiCorp's Final Comments at 42 (Apr. 1,2020) (responding to OPUC Staffls
comments regarding why the B2H transmission line 'cannot be modeled endogenously as a simple
connector between the Hemingway bubble and the [BPA] bubble in the IRP topology.").
16 STOP B2H's Comments at 7, 12.
17 Oregon Docket LC 70 and ldaho Case No. PAC-E-19-16, PacifiCorp's 2019 IRP at 83.
18 Case No. IPC-E-19-16, Reply Comments of Rocky Mountain Power at 5 (Aug. 19,2020); Oregon Docket
LC 70, PacifiCorp's Reply Comments at 6 (Feb. 5,2020|
IDAHO POWER COMPANY'S REPLY COMMENTS - 6
2. ldaho Power Commits to Securino the Best B2H Partnership Arranqement for
ldaho Power's Customers.
Staff expresses concern over the possibility of ldaho Power assuming BPA's
ownership share of B2H, citing there could be important tax and cost implications that
have not been vetted.le As discussed further in the next section, ldaho Power agrees to
assess this in its 2021 lRP.
lmportantly, any changes to the ownership structure for B2H are immaterial for this
IRP cycle, as the hypotheticalarrangements contemplated to date would not increase the
net costs associated with the project for Idaho Power's customerc relative to amounts
already considered in the Second Amended 2019 IRP analysis. ldaho Power has
committed that it will not reach any deal with BPA that would harm retail customers or the
Company's shareholders, thus eliminating any cost increases not associated with
increases in benefits for retail customers due to partnership changes. Given that the
Company's Preferred Portfolio is designed to reflect the least-cost, least-risk option in the
long-term interests of customers, ldaho Power appropriately would not include cost
factors that are irrelevant to customers in the IRP modeling process.
STOP B2H argues that, until ldaho Power finalizes all ownership anangements,
the Commission should not acknowledge the Second Amended 2019 lRP.2o STOP B2H
further re@mmends that the Commission direct ldaho Power to complete funding and
financing arrangements before the next IRP begins so that it can develop a new suite of
portfolios with contractually verifiable costs, thus allowing the analysis to be based on
"hard numbers."21 The Commission should reject these recommendations.
1e Staffs Comments at 11.
20 STOP B2H's Comments at 11
21 ld. at 11.
IDAHO POWER COMPANY'S REPLY COMMENTS. T
First, STOP B2H's proposal assumes a degree of granularity and certainty in
project costs that is neither reasonable nor feasible for long-term resource planning-and
which is not demanded for other resources in the IRP process. As discussed in more
detail below, ldaho Power has included a substantial 20 percent contingency as a buffer
for B2H costs, thus allowing for considerable leeway in modeling relative portfolio costs
and benefits. Any Iong-term forecast of project costs will inevitably carry some degree of
risk with respect to cost fluctuations.
Second, making the Company's entire 2021 IRP contingent on the timing of B2H
negotiations is unreasonable and impractical. While B2H has been a very important
component of each of the Company's past lRPs, it is only one component, and it should
not hold up an entire process. As with any element in its lRP, the Company will provide
updated B2H information as an input into the process as soon as practicable.
Third, and as noted above, there is no need to condition the Company's ability to
move forward with prudent resource planning on cementing specific contractual
anangements. Certainly, ldaho Power looks fonrvard to finalizing ownership and cost
responsibility arrangements for B2H so that it can provide an updated analysis in its next
IRP. That said, the Company has already determined that B2H costs would need to
increase significantly beyond the 20 percent contingency before it is no longer least-cost
and least-risk. And based on the direction of current negotiations, the Company hopes
to further increase the benefits of B2H to customers:beyond those contemplated in the
cunent lRP. Finally, the Company reiterates its commitment that an ownership change
to provide transmission service to BPA will not increase the net costs without associated
increases in benefits for ldaho Power's retail customers. Therefore, these ownership
IDAHO POWER COMPANY'S REPLY COMMENTS - 8
arrangements should not impact the Commission's ability to reasonably assess the
potential economic and operational benefits of B2H in this lRP. As a result, there is plainly
enough certainty that B2H is a reasonable part of the Company's Preferred Portfolio for
the Commission to acknowledge the lRP, based on the analysis that has been provided.
3. ldaho Power's 2021 IRP Will Model B2H Partnership Costs and Risks.
As part of the 2021 lRP, Staff recommends that, absent resolution of ownership
status, the Company should provide a detailed analysis for a hypothetical 45 percent and
100 percent ownership share of the B2H transmission line.22
The Company understands Staffs desire to have a better understanding of the
potential impacts on ldaho Power's customers of any changes to the ownership and cost
responsibility arrangements for B2H, and the Company further agrees that the 2021 IRP
will be the appropriate context for that analysis. During the development of the 2021 IRP ,
the Company anticipates that it wil! have finalized the details of the ownership and cost
responsibility anangements for B2H. To that end, the Company expects to be able to
provide a more detailed analysis of any associated cost and risk impacts in the 2021 lRP.
The Company agrees that any known changes to the B2H co-partnership
arrangement with BPA and PacifiCorp will be included as an input to the 2021 IRP and
intends to make every effort to finalize and release the terms of an arrangement as soon
as possible. Once a framework of terms is agreed to, the Company looks forward to more
detailed discussions concerning the agreed-upon arrangement.
22 Staffs Comments at 11
IDAHO POWER COMPANY'S REPLY COMMENTS - 9
B. Modeling B2H in AURORA
Staff believes the Company's analysis for B2H is flawed because the analysis was
conducted using portfolios optimized for the Westem Electricity Coordinating Council
('WECC") and, therefore, that B2H was evaluated based on its value to the WECC, rather
than its value to ldaho Power's customers.23 The Company assures Staff and the
Commission that B2H was evaluated only on its value to ldaho Power's native load
customers. The B2H project provides two primary values in the !RP: first, it is a lower
capital cost resource compared to alternatives; and second, it offers additional market
purchase opportunities.
When comparing the resource buildouts for portfolios including B2H to the
portfolios not including B2H,2a there are significantly fewer resources added into ldaho
Power's system in B2H portfolios compared to non-B2H portfolios. Table 1 of Appendix
D highlights the capital cost differences between B2H and other comparable resources.
For example, B2H is $626 per kW-peak, whereas a combined-cycle combustion turbine
is $1,294 per kW-peak. B2H also allows for additional market purchases (and therefore
additional energy benefits) between the Pacific Northwest ('PNW') and ldaho.
The Company's 2019 IRP portfolio analysis only quantifies costs and benefits to
ldaho Power's customers. ln the AURORA model, other WECC entities do benefit from
this additional transmission connectivity between the Pacific Northwest and Idaho;
however, these benefits to other entities are not quantified in the analysis. Nevertheless,
the Company does expect that B2H capacity will be utilized by other entities. As
compensation for this usage, other entities will be required to purchase transmission
23 ld. at8.
2a Second Amended 2019 lRP, Appendix C at46-57
IDAHO POWER COMPANY'S REPLY COMMENTS - 1O
service from ldaho Power and these revenues willflow back to retail customers to offset
the cost of the project. To ensure a conservative financial picture for ldaho Power, these
potential revenues from incremental third-party usage have not been factored into the
2019 tRP.
G. Modeling B2H Gosts
The B2H cost estimate included in the Second Amended 2019lRPwas developed
in 2018 as a key IRP input, and includes a 20 percent contingency as part of the
estimate.2s Other resources evaluated in the lRP had zero contingency included in their
estimates. This 20 percent contingency for B2H is unique and provides a significant cost
buffer for the project.
STOP B2H requests that ldaho Power perform a tipping point analysis to
determine how much mor:e cost the Company can absorb until another portfolio becomes
the least-cost and least-risk.26 ln the 2019 lRP, ldaho Power estimated that the
Company's share of the B2H project would total $313 million, including contingency and
allowance for funds used during construction ("AFUDC'). Once levelized and converted
to a present value, the total B2H net present value ("NPV") cost is approximately
$108 million.2T This $108 million cost is part of the total cost of all portfolios that include
the B2H project. Removing the 20 percent contingency would reduce this $108 million
by about 20 percent and reduce the cost of al! B2H portfolios by that amount. Conversely,
increasing the cost contingency would similarly increase the cost of B2H portfolios.
25 ldaho Power discussed B2H costs in the Second Amended 2019 lRP, Appendix D at 40, and in the IRP
Review Report starting on page 37.
26 STOP B2H's Comments at 8.
27 Second Amended 2019 lRP, Appendix D at 53.
IDAHO POWER COMPANY'S REPLY COMMENTS - 11
With this understanding-and focusing on Table 9.7 in the Second Amended 2019
/RP, specifically the Planning Gas-Planning Carbon ("PGPC") column-the best portfolio
including B2H is PGPC B2H (1) and the best portfolio without B2H is PGPC (2). The
difference between these portfolios is approximately $35 million on an NPV basis. That
indicates B2H costs could increase another 30-35 percent above the current 20 percent
contingency already included before a non-B2H portfolio would be more cost-effective.
This simple analysis assumes only cost increases with no conesponding value increases.
lf additiona! capacity were associated with cost increases, additional AURORA modeling
would be required.
ln preparation for the 2021 lRP, the Company is currently working with an
engineering consultant to revise the B2H estimate. ldaho Power plans to include a
breakdown of the cost estimate, including the contingency component, in the 2021 lRP.
Preliminary results suggest that the 2021 cost estimate will be less than the 2018
estimate. The Company has not determined whether it is appropriate to maintain a Iarge
contingency for B2H given that no contingency is included for other resources being
evaluated in the 20211RP. Based on stakeholderfeedback, the Companywill incorporate
a cost-sensitivity analysis in the 2021 lRP.
D. B2H Gapacity Acknowledged in2017 !RP: STOP B2H's Oregon Arguments
ln the Second Amended 2019 lRP, the Company modeled B2H as 500 MW of
summer capacity and 200 MW of winter capacity (on average, such a capacity
arrangement results in ldaho Power's 21 percent share). This amount is consistent with
the B2H Permit Funding Agreement and with the Company's approach in the 2017 lRP.
!n this proceeding, STOP B2H includes a line of questioning specific to the Oregon
IDAHO POWER COMPANY'S REPLY COMMENTS - 12
Commission. Specifically, STOP B2H asks the Oregon Commission to retrospectively
"clariff what capacity measure" the Oregon Commission acknowledged in the 20'17 lRP.28
Recognizing that the Oregon and ldaho Commissions are distinct regulatory bodies,
ldaho Power does not believe the OPUC's acknowledgement of a prior IRP has bearing
on or relevance to the ldaho Commission's consideration of the 2019 lRP.2e
E. B2H and Carbon Reduction Goals
The Company believesthatthe B2H project isfoundationalto a clean energyfuture
for ldaho Power and the Western grid. lncreased transmission connectivity is widely
viewed as a critical component to meeting future carbon reduction goals.3o ln addition to
Idaho Power's own clean energy goals, the Company understands that the new
Presidential Administration intends to focus on clean energy-including prioritizing
necessary transmission infrastructure.3l ldaho Power is pursuing various options to move
toward a clean energy future, but without transmission other clean energy options cannot
be fully leveraged.
STOP B2H believes that B2H should not be referred to as a carbon-free supply-
side resource because the line wil! enable market purchases of energy that are not
necessarily carbon free, especially in the near term.32 The Company cannot limit energy
transmitted across the line to renewable energy only, but in order to transition to a clean
energy future, robust transmission must be available in order to access renewable
resources in different geographic areas. The Company would like to encourage STOP
28 STOP B2H's Comments at 17.
2e For ldaho Power's full comments with respect to this matter, see pages 13-17 ol its Final Comments in
OPUC Docket LC 74 (Feb. 5,2021).
30 See, e.9., National Renewable Energy Laboratory, Renewable Electricity Futures Study at 25 (2012)
( https ://www. n rel. qov/docs/fu 1 3osti/52409-ES. odf).
31 Executive Order No. 14008,86 FR 7619 (Jan. 27,2021).
32 STOP B2H's Comments at 34.
IDAHO POWER COMPANY'S REPLY COMMENTS - 13
B2H-and all stakeholders-to view B2H as a long-term resource, keeping in mind the
cunent direction of the industry.
The Company's vision of the PNWs future energy supplies is that clean energy
will take the place of fossil fuels, and transmission will be key to moving that carbon-free
energy to load. ln this way, available energy resources will decarbonize, as will the
energy transmitted via B2H. In sum, B2H is not only a least-cost, least-risk resource
today, but will also continue to enable the transition to a clean energy future.
F. Mid-C Market and Market Purchase Opportunities in the Pacific Northwest
Both Staff and STOP B2H express concern over the Company's assumptions
around the availability of power at Mid-Columbia ("Mid-C') and in the PNW. While STOP
B2H broadly objects to the Company's reliance on western markets in evaluating the
potential supply-side benefits of B2H,33 Staff is concerned that the Company's
assumptions about power availability in the PNW may be unrealistic and assume that
much more dispatchable power will be available for import into ldaho Power's system
than seems likely under the current regulatory climate.s
1. ldaho Power's PNW Market Assumptions are Realistic.
The electric utility industry, and the western interconnection, are curently going
through a major energy transition. The Company acknowledges Staffs concern about
dispatchable power; however, it should be noted that dispatchable power is not the only
power that makes up generation bought and sold at the Mid-C market hub. Dispatchable
energy is certainly a component of a "firm" block of energy; however, it should be noted
that the PNW has ample hydro capacity (hydro is often more limited by energy concems).
33 /d. at 32-35.il Staffs Comments at 9.
IDAHO POWER COMPANY'S REPLY COMMENTS - 14
Renewables (energy) and hydro (capacity) pair very well together and are packaged
together by established PNW energy marketing firms.
Staff points out that the impact of Washington's Clean Energy Transformation Act
("CETA"1ss was not included in the Company's assumptions of resource adequacy, nor
was it included in the studies36 the Company relied upon for its resource adequacy
assessment.3T Staffs comments indicate that CETA will have a negative impact on the
ability to acquire powerfrom wholesale markets. The Company disagrees. lndeed, while
both studies referenced include commifted retirements, these studies are conservative
forecasts that do not factor in future resource plans or additions, and only represent two
of the many data points provided by the Company in Appendix D.
ldaho Power ensures that none of its resource planning decisions compromise
reliability and expects that other PNW utilities plan in a similar fashion. ldaho Power
believes that CETA will result in the PNW building substantial amounts of renewables
with corresponding firm capacity (which can be non-thermal capacity) to ensure peak
needs are met.
Lastly, Staff explains that due to reduced costs for renewable energy and regional
policies penalizing thermal resouroes, utilities are transitioning away from the
development of gas/thermal plants that could supply the B2H transmission line.38 Staff
recommends that in the next lRP, the Company provide detailed analysis and explanation
3s CETA (E2SSB 5116, 2019) requires Washington's electric utilities to fully transition to clean, renewable
and non-emitting resources by 2045.
36 The Pacific Northwest Power Supply Adequacy Assessment and the 2018 BPA Pacific Northwest Loads
and Resources Study.
37 Staffs Comments at 9.
38 /d. at 9-10.
IDAHO POWER COMPANY'S REPLY COMMENTS - 15
for how the forecasted capacity, if any, will be available for B2H to import and provide
more specifics about where it will come from.3e
With respect to these concerns, the Company addresses the depth of the PNW
market in Appendix D of the Second Amended 2019 lRP. Further, ldaho Power notes
that, regardless of PNW utilities' futures with respect to coal and other thermal generation,
these utilities (and the region) will still have reliability obligations. The region will build to
meet its winter peak needs (likely to grow with electrification), and excess resources will
be available in the summer.
The Company would also like to clarify that it will not identify specific resources in
the2021 IRP thatwill be utilized by B2H. B2H is intended to be a connection to a diverse,
liquid market hub. The Mid-C is a deep market hub, with dozens of counterparties, and
the Company will look for the most cost-effective resources through competitive
processes to ensure least-cost resources for the Company's customers.
2. The Mid-C and the PNW Markets Wil! Continue to Have Sufficient Depth.
STOP B2H broadly objects to the Company's reliance on Western markets in
evaluating the potential supply-side benefits of 82H.a0
First, STOP B2H does not agree with the Company's analysis of the flexibility,
liquidity, reliability, and low cost of market purchases at the Mid-C trading hub.al As ldaho
Power explained in its Second Amended 2019 /RP, Appendix D, the Mid-C hub is very
liquid.a2 \n2018, on a day-ahead basis, daily average trading volume during heavy-load
hours in June and July ranged from nearly 10,000 MWh to over 29,000 MWh. Despite
3e /d. at 9-10.
40 STOP B2H's Comments at 32-35.
41 ld. at 5,34.
a2 Second Amended 2019 lRP, Appendix D at 8.
IDAHO POWER COMPANY'S REPLY COMMENTS - 16
these facts, STOP B2H claims that regional resource adequacy concerns, identified by
the Northwest Power Conservation Council's ("NWPCC") Pacific Northwest Power Supply
Assessment for 2024, and the prices established for the forthcoming Jackpot Solar
generating facility, indicate that the Mid-C is an unreliable source of long-term market
purchases.4e ldaho Power disagrees.
With respect to the reference to NWPCC's Assessment, ldaho Power is a
stakeholder in NWPCC processes and studies, which provide the region with usefu!
information to assist in planning decisions. Typically, ldaho Power would have included
an analysis of this report in Appendix D; however, this Assessment had not yet been
released when the Company developed Appendix D in this case. As a result, the
Company will briefly summarize its understanding of the implications of the NWPCC
Assessment here.
By way of background, the focus of the NWPCC Assessment is on electric utilities
in the Northwest United States ("Northwest") and their resources.aa The study makes
only limited allowances for the transmission connectivity of the region and independent
power producers within the region. More critically for ldaho Power, the NWPCC
Assessment continues to show that the primary issues faced by the Northwest, on
average, are in the winter months. Figure 1, below, shows that the severity of loss of load
expectation ("LOLE") in July and August dwarfed by events in the winter months. The
Northwest's primary issue remains in the winter-not during ldaho Power's peak summer
season in late June and early July.
43 STOP B2H's Comments at 32-34.
44 NWPCC, Pacific Northwest Power Supply Adequacy Assessment for 2024 at 24 (Oct. 31, 2019)
https://www.nwcouncil.orq/sites/defaulUfiles/2024%20RA%2OAssessment%20Final-2019-10-31.pdf.
IDAHO POWER COMPANY'S REPLY COMMENTS - 17
Figure 1: NWPCC Assessment of Average LOLE Magnitudeas
Average Event Magnitude by Month
th
o€t3
=
70000
60000
50000
40000
30(n0
20000
10000
0
Nov DecOct Jan Feb
IIIr
Jul Augl- AuglG Sep
15 31
Looking forward strategically, the Northwest region is on a clean-energy trajectory
and the Company expects the region will address their winter LOLE risk with renewable
energy such as optimally located solar-plus-storage (including optimized hydro) and wind.
These new resources will address regional winter LOLE risk and eliminate the already
much less severe summer LOLE risk. ln fact, solar-plus-storage and solar-plus-wind are
even more effective at addressing summer peak than they are at addressing winter peak.
ln the summer, once the solar ramps down, there are only a few hours remaining unti! the
late evening hours. Storage can come in the form of short-duration batteries (which
utilities such as ldaho Power can combine with solar projects) or hydro generation (which
has great amounts of capacity but limited energy). B2H fits very well within these
opportunities by enabling access via transmission to these supporting resources.
45 ld. at 15.
IDAHO POWER COMPANY'S REPLY COMMENTS. 18
Winter LOLE risk is more challenging due to the dual morning and evening peaks
before and after sun-down. Critically, this is the period during which transmission such
as B2H is likely to play an even larger role by connecting remote renewable resources to
load centers. While STOP B2H interprets the NWPCC Assessment as suggesting a lack
of adequate market capacity, ldaho Power understands the report as reinforcing the need
to improve access to power when and where there is heightened demand.
Next, with respect to Jackpot Solar, STOP B2H claims that this resource was
identified as a more cost-effective resource than Mid-C. ldaho Power understands STOP
B2H as claiming that, by extension, market purchases are over-priced.ao Idaho Power
agrees the Jackpot Solar resource is very cost-effective, which is why the Company
executed a Power Purchase Agreement ("PPA") to purchase the project's output. But the
Company believes STOP B2H is misguided in its implication that Mid-C has a static (and
high-cost) price relative to Jackpot Solar or other resouroes. Mid-C is, in point of fact, a
market like any other, where prices go up and down based on supply and demand. As
such, Mid-C is not a single resource and should not be used to support the inconect
inference that B2H is a more costly resource than solar, for example. Rather, B2H
provides a different value to the Company's customers in the form of a firm, and diverse,
resource-for instance, by providing access to power in those hours after the sun goes
down.
Finally, STOP B2H claims that the Company included 1,800 MW of "phantom coal
generation" selling into the Mid-C hub by including Boardman and Centralia throughout
the 20-year planning period.aT This claim is false. The data request referenced by STOP
46 STOP B2H's Comments at 5.
47 ld. at35.
IDAHO POWER COMPANY'S REPLY COMMENTS - 19
B2H asked for resources and resource retirements selected by AURORA. Retirement
dates for the three plants mentioned were not selected by AURORA. These retirements
were modeled as follows:
1. Centralia 1 - December 2020
2. Boardman - End of Year 2020
3. Centralia 2 - December 2025
Notably, the Transalta natura! gas units were retired December 2013 in the
AURORA resource table; therefore, they were not included in the analysis as STOP B2H
claims. STOP B2H also claims that the Company "zero[ed] out BPA's existing wheeling
charges assessed to ldaho imports from the PNW, by incorporating a phantom asset
swap with BPA into the B2H cases."48 Not only does STOP B2H provide no basis for its
claim, the assertion is simply not true. The Company modeled BPA's wheeling rate on
the B2H segment in the AURORA model.ae
G. B2H and Transmission Path Constraints
STOP B2H objects to the Company's analysis of the path between the Northwest
and ldaho, and ldaho Power's treatment of the capacity across that path.so Specifically,
STOP B2H claims that the Company's capacity constraints are manufactured, stating that
the Company's actual transmission flows often exceed the existing transmission path's
West-to-East commercial rating.51 Here, STOP B2H fails to understand how transmission
capacity is contracted for in the West, and the difference between a transmission line's
as /d. at 35.
as ldaho Power reviewed its transmission assumptions in the IRP review process, and documented updates
in Table 5.1 of the IRP Review Report. Areas of the table without information reflect no update was
necessary. Wheeling charges with respect to B2H were modeled at $2.83/MWh. Second Amended 2019
lRP, Attach. 3, 2019 IRP Review Report at 58.
50 STOP B2H's Comments at 5€.
51 ld. al5.
IDAHO POWER COMPANY'S REPLY COMMENTS.20
commercial transmission capacity and actual power flows. Contractual capacity defines
the amount of firm capacity that can be reserved on a transmission line, while actual
power flows are just that-the amount of power that actually flows on the path.
The typical commercia! path rating between the Northwest and ldaho (Path 14) in
the summer months is 1,200 MW. This means that the transmission provider cannot
grant firm transmission requests over and above 1,200 MW. lt is true that, over the past
few years, the Company has seen actualflows exceeding this amount, and at times flow
has exceeded 1,200 MW by hundreds of megawatts. This flow over 1,200 MW is called
"adverse unscheduled flow", which can be caused by several events, but is typically
associated with commercial schedules elsewhere experiencing opposing conditions-
i.e., the path is scheduled but the power is not flowing. Controlling real power flow on a
single path within an interconnected power system is challenging and requires significant
coordination between utility real-time operations centers and the reliability coordinator.
To be clear, the fact that actual power flows exceed a commercial path rating does not
mean that capacity constraints do not exist. STOP B2H's argument (perhaps
understandably) confuses the discrete physical and contractual approaches to
transmission planning and operation in the West.
With respect to the specific issue STOP B2H identifies, B2H will add 1,050 MW of
West-to-East capability to Path 14 and will provide significant operational flexibility to
ldaho Power.s2 Adverse loop flow (such as the type that can lead to flows wetl in excess
of path ratings) is becoming a significant operational issue and solving this problem by
52 Second Amended 2019\RP, Appendix D at 15.
IDAHO POWER COMPANY'S REPLY COMMENTS .21
increasing the path rating is an ancillary benefit of B2H that the Company has not
quantified in this IRP analysis.
Next, STOP B2H asserts that "there has not been a date that we could find, where
[ldaho Power] could not purchase the power it wanted from the Mid-C.'53 First, it is not
clear on what evidentiary basis STOP B2H rests its assertion. To verify STOP B2H's
claim, one would need to conduct a detailed examination of real-time grid operations to
determine what power is procured from where at any given point to meet changing !oad.
STOP B2H provided no evidence of such examination. That said, ldaho Power can
certainly attest that the grid experiences significant stress and, in almost all cases,
transmission capacity-not generation-is the constraint. The Summer 2020 California
rolling outages are prime examples of this transmission constraint. On August 18,2020,
resources were available at the Mid-C market hub, however, deliverability constraints
(transmission) limited that market's ability to provide support to the desert southwest.
This was indicated by the major price spread that occurred on August 18,2020 with the
Mid-C price getting to about $200 per MWh, whereas the Palo Verde market hub (Desert
Southwest) price exceeded $1,500 per MWh. Second, ldaho Power would note that
STOP B2H's statement concerning the apparent adequacy of the Mid-C market and ldaho
Power's ability to readily rely on such market purchases appears to be in tension with
STOP B2H's earlier questioning of the liquidity of the Mid-C market hub.
STOP B2H raises concerns with ldaho Power's calculation and use of
Transmission Reliability Margin ("TRM") and Capacity Benefit Margin ("CBM"). ln the mid
1990's, FERC issued a series of orders that required transmission providers to calculate
53 STOP B2H's Comments at 5
IDAHO POWER COMPANY'S REPLY COMMENTS - 22
and post for sale their Available Transfer Capacity ("ATC"). As part of that calculation,
FERC determined that it was important for the reliability of the system for utilities to create
two margins that are deducted from ATC: TRM and CBM. Over the past severa! decades,
FERC and North American Electric Reliability Corporation ("NERC") issued orders and
promulgated rules that require specific calculations of TRM and CBM as inputs to the ATC
methodology, the results of which are now contained in ldaho Powefs FERC-approved
OATT. Regardless of STOP B2H's concerns, ldaho Power follows and must continue to
follow FERC-approved rules related to calculation and applicability of TRM and CBM,
which requires withholding TRM and CBM amounts from its ATC.
STOP B2H further suggests that ldaho Power inappropriately holds back
transmission capacity in the form of TRM.54 As stated above, ldaho Power is required by
FERC to calculate a certain amount of TRM for transmission paths on its system and
withhold that amount from its ATC. And to reiterate, TRM allows the Company to maintain
adequate transmission capacity to account for unscheduled flow, such as the adverse
unscheduled flow mentioned above. As described in its OATT, ldaho Power makes this
capacity available for non-firm usage, and when flows reach unmanageable levels, it is
curtailed.
Next, STOP B2H claims that ldaho Power should eliminate "some or all" of the
330 MW of CBM by adding new resources within the Company's Balancing Authority
Area 1"BA,q"1.ss This argument echoes STOP B2H's prior comments in LC 74, which
argued that CBM can and should be used as a resource to offset the need for B2H.56 ln
il ld. at5.
55 /d. at 36.
56 Oregon Docket LC74, STOP B2H's Amended and Revised Opening Comments at 19 (Apr. 7,2020).
IDAHO POWER COMPANY'S REPLY COMMENTS - 23
ldaho Power's prior Reply Comment, the Company provided a detailed discussion of the
scope and purpose of CBM, explaining that CBM is capacity set aside for system
emergencies, but is nonetheless already included in the Company's IRP as part of the
Company's Planning Margin.s7 Nonetheless, STOP B2H now states that "ldaho Power
misrepresented STOP [B2H]'s comments and invented a new undefined term'emergency
transmission' to belittle STOP [B2H]'s suggestion."ss
To be clear, ldaho Power did not belittle STOP B2H's suggestion by describing
CBM colloquially as "emergency transmission." Rather, the Company explained the
function of CBM in an accessible manner. ln contrast, the actua! definition of CBM out of
the NERC glossary is as follows:
The amount of firm transmission transfer capability preserved by the
transmission provider for Load-Serving Entities (LSEs), whose loads are
located on that Transmission Service Provider's system, to enable access
by the LSEs to generation from interconnected systems to meet generation
reliability requirements. Preservation of CBM for an LSE allows that entity
to reduce its installed generating capacity below that which may otherwise
have been necessary without interconnections to meet its generation
reliability requirements. The transmission transfer capability preserved as
CBM is intended to be used by the LSE only in times of emergency
generation defi ciencies.se
!n summary, CBM is, by definition, a transmission margin that is set aside for times of
emergency generation deficiencies, and removal of the CBM from a transmission
provider's ATC is mandated by FERC
With respect to STOP B2H's claim that adding new resources within ldaho Power's
BAA would eliminate the need for a CBM "at no incremental cost," this assumption is
57 Oregon Docket LC 74,ldaho Power's Reply Comments at 11 (May 15,2020).
58 STOP B2H's Comments at 36.
5e NERC Glossary of Terms, available at hltps://www.nerc.com/files/olossary of terms.odf .
IDAHO POWER COMPANY'S REPLY COMMENTS - 24
inconect.60 Whether it is more affordable to add one type of resource (such as B2H) over
another (such as new generation within ldaho Power's BAA) is precisely the question that
the IRP process is designed to answer. As the Company's portfolio analysis
demonstrates, the cost of necessary resources in the absence of B2H would be far
greater than the cost of building B2H.
Similarly, if ldaho Power were to replace the emergency reserve provided by CBM
with another on-system resource, then the Company would be in precisely the same
position for resource planning purposes-in need of generation to meet that same 330
MW-because emergency support not provided by CBM would need to be provided by
something else. Thus, reducing or eliminating CBM simply moves the need for capacity
from one bucket (serving load) to another bucket (planning margin), while having zero
impact on the Company's overallsystem need.
Finally, STOP B2H states that the Company has been selling 200 MW of the CBM
to BPA on a conditionalfirm basis since 2016.61 STOP B2H goes on to imply that such
a conditiona! firm sale violates the Company's OATT, and that STOP B2H intends to
pursue the issue through FERC's Enforcement Division.62
Section 15.4 of ldaho Power's OATT requires ldaho Power to offer conditional firm
transmission service to its transmission customers when insufficient capacity exists on its
system to grant the customer's full transmission service request. Idaho Power and BPA
60 STOP B2H's Comments at 36
61 /d. at 36.
62 /d. at 36.
IDAHO POWER COMPANY'S REPLY COMMENTS - 25
entered into these conditional firm service agreements and filed them with FERC in
2016.63
STOP B2H appears to be confusing conditional firm service, which is subject to
significant curtailment limitations, with firm sewice, which must be available in all but
emergency conditions. Because CBM is designed to serve as emergency support, the
Company appropriately allows efficient use of this reserve when not needed for
emergency purposes as required by FERC orders.
III. SOFTWARE SELECTION, VALIDATION AND VERIFICATION
Staff expresses concem regarding the software selection for the 2019 IRP and the
Company's post-hoc validation process. Staff believes that the Company would benefit
from using an approach in defining what is required of a capacity expansion modeling tool
to ensure the software is capable of meeting the requirements identified during the model
selection process.Ga Moreover, based on the information provided by the Company to
Production Requests, Staff remains concerned that the newest AURORA release may
not produce portfolios that are in the best interest of ldaho Power's customers.65
The Company acknowledges that the learning curve associated with transitioning
to capacity expansion software for the 2019 IRP resulted in additional time and analysis.
Throughout the 2019 IRP process, ldaho Power has gained experience that will be
leveraged in the 2021 lRP. The Company, however, notes the importance of the model's
ability to concurrently optimize resources for both ldaho Power's system and the broader
WECC to produce market prices and operating conditions that are representiative of
63 ldaho Power's agreements with BPA can be found in ldaho Power's FERC-approved OATT as Service
Agreement Numbers 324 and342.il Staffs Comments at 7.
65 /d.
IDAHO POWER COMPANY'S REPLY COMMENTS.26
specific modeled scenarios. This is an important distinction, as resources selected for
the WECC influence each portfolio's NPV for ldaho Powe/s system.
A. The AURORA Modelfor Resource Planning
The market for long-term capacity expansion software is limited. For the 2019 lRP,
the Company's software validation approach included a review of the AURORA model's
capabilities, the capability of competitor software options,66 and an in-house developed
software solution. Using pre-established software selection criteria,6T the Company
determined the following in its evaluation of the capabilities of the AURORA model:
. AURORA has all the capabilities needed to perform a robust 2o-year resource
planning analysis. This allows ldaho Power to utilize a single model to accomplish
this, rather than several models operating in piecemeal fashion.
. AURORA is used extensively for IRP planning by other utilities across the country
and by third-party consultants, making it a trusted, known, and verified solution in
the electric industry.
o Within ldaho Power, AURORA offers synergies, as it is a valuable and robust
resource for more than just the lRP. !t is used for rate cases, determining net
power supply expenses in the Company's annual power cost filing, evaluating
ffi As discussed in the Company's Response to Staff Production Request No. 7, ldaho Power reviewed and
evaluated several other third-party sofhrare providers including PLEXOS, ABB, and ADSS.
67 The software must include the ability to simulate the regional power market, adequately perform long-
term capacity expansions, have a run-time of less lhan 24 hours for most runs, have the ability to forecast
at hourly and sub-hourly time steps, adequately reflect resource operations on ldaho Power's system, and
include a fully fleshed-out dataset that includes resources and access to resources outside of ldaho Power's
system. Furthermore, the software should: have intemal error checks and a straightforward user interface
to reduce and manage errors in the results, provide reports and results that can be used efficiently in the
analysis, be understood and used by ldaho and Oregon Commission Staff, be used by other utilities to
provide consistency and allow for best-practice learning and collaboration, and be supported by a vendor
with a proven record of providing thorough and timely software support. See Company's Response to Staff
Production Request No. 56.
IDAHO POWER COMPANY'S REPLY COMMENTS - 27
large load requests, and determining PURPA pricing, among other regulatory
applications.
While the Company identified strengths and weaknesses associated with other
options, AURORA provided a product superiorto the alternatives. For example, PLEXOS
presented potential problems associated with setup and increased run times; ABB
required the setup, interface, and monitoring of multiple distinct tools; and ADSS is not
commercially available.
The Company also explored developing its own software to perform the capacity
expansion analysis. While the Company could develop an in-house modelto meet ldaho
Power's specific operating requirements, there are multiple drawbacks to such an
approach. First, in-house development requires additional resources and expertise to
develop, monitor, and maintain. The developed toolwould also make collaboration with
Staff, stakeholders, and other utilities more difficult, as ldaho Powerwould be the primary
user and sole source of technical support; therefore, facilitating the use of the mode! by
others would require additional Company time and resources.
Additionally, because IRP modeling effectively requires a long-term buildout of the
entire WECC, an in-house software option would require significantly more coordination
with other regional entities (assuming entities are willing to invest the time to support
ldaho Poweds models) to develop complex future outlooks for numerous future
assumptions, resulting in even more time and expense. And finally, the Company leamed
in discussions with other utilities that the use of in-house developed software required
significant time and effort to establish trust in the software, and for internal and external
parties to gain confidence in the verification and validation of the modeling.
IDAHO POWER COMPANY'S REPLY COMMENTS - 28
Because of the significant drawbacks associated with other third-party options and
in-house developed software, and given the benefits of AURORA previously mentioned,
ldaho Power determined that AURORA was appropriate for the 2019 IRP and remains
the superior option for the 2021 lRP.
B. Simultaneous Optimization
Although Staff expresses concerns around the newest AURORA release,os the
Company has confirmed that the cunent version of AURORA, which wil! be used for the
2021 lRP, can simultaneously optimize for the WECC and for ldaho Power's specific
system. This capability did not exist in the version used for the 2019 lRP, resulting in the
need to re-examine the IRP analysis and perform manual adjustments to the WECC
portfolios to optimize for ldaho Power's system.
ldaho Power has validated that improvements to the software alleviate the
concerns raised with the WECC specific optimization approach used in the 2019 lRP.
ldaho Power will continue to use post-hoc model validation and verification review
methods for the 2021 IRP to ensure the accuracy of the results. The Company will
discuss the updated version of AURORA at forthcoming meetings of the 2021 IRP
Advisory Council ('!RPAC").
IV. PORTFOLIO DESIGN AND ANALYSIS
A. Portfolio Modification and Selection
Staff lists two main concerns with the Company's portfolio selection process in the
2019 lRP. First, Staff believes that the Company configured the Long-Term Capacity
Expansion ("LTCE") to select portfolios based on the benefit to the WECC and not ldaho
ffi Staffs Comments at 7
IDAHO POWER COMPANY'S REPLY COMMENTS.29
Power's customers, and second, that the Company's process for manually adjusting and
combining portfolios was subjective, and not likely to produce the lowest cost portfolios
for ldaho Power's customers.6e
The Company acknowledges that there was a Iearning curve associated with the
capacity expansion software in the 2019 lRP, but believes the process presented in the
Second Amended 2019 IRP appropriately adjusted the WECC-optimized portfolios to
reflect the least-cost, least-risk portfolio for ldaho Power's system.
Staff expresses concern that configuring the LTCE model to use an objective
function that maximizes value for the entire WECC may not align with the needs of ldaho
Power.To To ensure that portfolios are optimized for ldaho Power's customers, Staff
believes that the Company should startwith an objective function that optimizes for ldaho
Power's system.71
Idaho Power concurs with Staff that the ideal solution is a software model
possessing an objective function capable of optimizing specifically for ldaho Power's
system within the broader WECC; however, as discussed above, this functionality was
not offered by the version of AURORA that was available when the 2019 IRP was
developed. Therefore, to address the issue of AURORA optimizing for the WECC as a
whole (rather than ldaho Power's system individually), ldaho Power performed a series
of manual adjustments to identify the least-cost, least-risk portfolio based on ldaho
Power's system needs.
6e ld. at 4.
70 ld.
71 ld. at6.
IDAHO POWER COMPANY'S REPLY COMMENTS .30
The LTCE in AURORA uses a load and resource balance analysis to ensure that
the planning margin is met. The load and resource balance analyses were developed
manually in all prior lRPs, while the Company allowed AURORA to perform the analysis
forthe 2019lRP through its LTCE functionality. Within AURORA, the resource selections
used to meet the planning margin are based on resource characteristics and cost. Once
a resource combination is chosen, the model performs the first iteration, resource
combinations are then adjusted, and multiple iterations are performed until the model
reaches an optima! solution. Optimality in the case of the LTCE model in AURORA is
cost-effectiveness within the parameters of demand and system needs for the entire
WECC.
This modeling was designed to produce 24 porlfolios under varying carbon cost
and natural gas forecasts, and with and without the B2H transmission Iine.72 Each run
resulted in a different resource selection for ldaho Power's system and a resource
selection for the rest of the WECC region (as part of optimizing for WECC as a whole).
That is, each run identified resources needed to cost-effectively serve the entire WECC
and identified a resource portfolio for ldaho Power as a subset of the WECC. However,
as previously discussed, these WECC runs were not necessarily optimized for ldaho
Power's specific system, creating the need for manual adjustments to identify the least-
cost, least-risk Preferred Portfolio.
It is important for AURORA to account for all WECC-wide resources because the
cost to serve ldaho Power's system depends on the resources selected for the WECC,
including the resources selected within ldaho Powe/s system. This dependency occurs
72 Second Amended 2019 IRP a|107
IDAHO POWER COMPANY'S REPLY COMMENTS - 31
because different WECC-wide resources impact market prices, which are calculated
within the AURORA model. Thus, different WECC resource selections outside of ldaho
Power's system result in variations to the NPV of ldaho Power's portfolio.
Notably, ldaho Power's average demand is approximately 2 percent of the
WECC's overall average demand.73 By optimizing forthe WECC as a whole, the resource
additions and retirements under these runs may not reflect the lowest cost for ldaho
Power's system. To correct for these non-optimal portfolio costs caused by the AURORA
LTCE designing for the WECC as a whole, rather than ldaho Power's system individually,
ldaho Power performed a series of manual adjustments to identify the least-cost, least-
risk portfolio based on ldaho Power's system needs.
While the objective function for the initial LTCE portfolios was to optimize for the
WECC (of which Idaho Power's system is part), the series of manua! adjustments
changed that objective function to identify the least-cost, least-risk portfolio specifically
for ldaho Power's system. The process for arriving at these ldaho Power-optimized
manually adjusted solutions is discussed in the sections that follow.
B. Manual Portfolio Adjustments
Staff believes the Company did not adequately explain the process for combining
WECC-optimized portfolios or explain why any combination of WECC-optimized
portfolios would result in least cost for ldaho Power's customers.Ta
When manually adjusting portfolios for ldaho Power's system, the Company
performed steps similar to the logic in the AURORA model. Resource combinations were
73 While there are some exceptions, optimized portfolios tend to add resources as they are needed and
generally only in the required quantities to serve load because overbuilding the system with additional
resources often results in higher portfolio costs.
7a Staffs Comments at 6.
IDAHO POWER COMPANY'S REPLY COMMENTS - 32
added in accordance to the planning margin requirements, and multiple iterations were
performed to identify the lowest cost portfolio. ln order to leverage leamings from the
model, the Company used the WECC-optimized portfolios as the starting point for
resource selections and then adjusted them accordingly. The base point as defined by
the WECC-optimized portfolios allowed the Company to select the most economical
resources as indicated by AURORA.
The robustness of the 24 initially developed portfolios and their relative
performance provided an indication as to which resource combinations are best suited to
meet the needs of ldaho Power's system. lt is important to note that while the LTCE
model developed portfolios to optimize for the entire WECC, the Company evaluated the
performance of each of these 24 porllolios solely based on the performance of ldaho
Power's system. To begin the manual optimization process, ldaho Power grouped the
WECC-optimized portfolios with similar resource buildouts and timing, both for B2H and
non-B2H portfolios, as shown in the table below:
Table 1: wEGC-optimized Portfolios selected for Manua! Adjustments
Category B2H Portfolios Non-B2H Portfolios
Planning Gas, Planning Carbon (PGPC)
Planning Gas, High Carbon (PGHC)
High Gas, High Carbon (HGHC)
P(13), P(14)
P(1s), P(16)
P(23), P(24)
P(1), P(2)
P(3), P(4)
P(11), P(12)
As an example, the table below shows the four WECC optimized portfolios that
were grouped to inform the PGPC manually optimized scenarios. The resource types
and quantities are very similar between the portfolios.
IDAHO POWER COMPANY'S REPLY COMMENTS - 33
Table 2: WECC Optimized Portfolios grouped to inform PGPC Manually Optimized
Scenarios
Non-B2H (MW)B2H (MW)
Portfolio 14
600
0
320
80
45
500
-1,026
Portfolio
Thermal
Wind
Solar
Battery
Demand Response
Transmission (B2H)
Coal Exits
Portfolio 1
933
0
320
90
50
nla
-1,026
Portfolio 2
933
0
320
80
50
nla
-1,026
Portfolio 13
711
0
200
50
45
500
-1,026
The groupings reflected a wide range of natura! gas and carbon price futures,
including B2H and non-B2H alternatives. These groupings allowed Idaho Power the
opportunity to evaluate a variety of portfolios for manual optimization, rather than a
nanower selection of portfolios that were somewhat similar in terms of resource selection
and timing-a critique of ldaho Power's manual adjustment process in the past.
The selection of a broader range of portfolios for manual optimization allowed the
Company to determine if further cost reductions were possible for ldaho Power's specific
system needs. Additionally, the variety of resource types included in the analysis
provided a reasonable Ievel of assurance that the least-cost, least-risk resource portfolios
were analyzed.
The Company's manual adjustment process focused on identifying optimal exit
scenarios for the Company's Jim Bridger coal units. The first three scenarios evaluated
three different sets of Jim Bridger exit dates to apply to the new portfolio groupings (Non-
B2H and B2H for Planning Gas-Planning Carbon ("PCPG'), Planning Gas-High Carbon
("PGHC'), and High Gas-High Carbon ("HGHC")). The guiding principles for adjusting
IDAHO POWER COMPANY'S REPLY COMMENTS - 34
portfolios based on these scenarios appear on page 115 of the Second Amended 2019
/RP, also set forth below:
. Applying the same modeling constraints used within the AURORA model
during the WECC optimization (e.9., Bridger unit exits could not be earlier
than the dates identified in Scenario 1);
o Utilizing the same resource types and approximate resource allocations
identified in the WECC-optimized LTCE portfolios;
. Resources were deferred and reduced where possible while maintaining a
planning margin of 15 percent; and
o No carbon emitting resources were added to the HGHC portfolios.
The following table and highlighted cells show how resources were adjusted in
manual optimization (Portfolios PGPC(1) and PGPC B2H (1)) compared to the WECC-
optimized portfolios included in the PGPC grouping (Portfolios 1,2, 13, and 14). For
instance, in PGPC B2H (1), below, additional solar-especially when paired with battery
storage-allows the Company to significantly reduce selection of thermal resources,
reducing overall costs.
Table 3: Resource Adjustments Between WECC-optimized and Manually
Optimized Portfolios Under PGPC Scenario 1
Non-B2H (MW)B2H (MW)
Portfolio
Thermal
Wind
Solar
Battery
Demand Response
Transmission (B2H)
Coal Exits
Portfolio 1 Portfolio 2
933 933
00
320 320
90 80
50 50
nla nla
-1,026 -1,026
PGPC (1)
933
0
320
80
50
nla
-1,026
Portfolio 13
711
0
200
50
45
500
-1,026
Portfolio 14
600
0
320
80
45
500
-1,026
PGPC B2H (1)
411
0
400
80
45
500
-1,026
IDAHO POWER COMPANY'S REPLY COMMENTS - 35
Other examples of adjustments (upward or downward) in the quantity of resources can
be found in Technical Appendix C by comparing the WECC-optimized portfolios (p. 46-
57) to the manually optimized portfolios (p. 58-69). The adjustments identified in Table 3
above were ultimately reflected in the manually optimized portfolios, reducing the costfor
ldaho Power's system. This process was utilized to manually adjust the PGPC, PGHC,
and HGHC portfolios for three Jim Bridger exit scenarios, yielding 18 new portfolios (three
scenarios applied to three different carbon/natural gas futures, both with and without
82H).
Once ldaho Power used manual optimization to identify the optimal (that is, least-
cost) exit scenario for Jim Bridger units, the Company performed a fourth manual
adjustment in an attempt to further refine the results of the first three scenarios, creating
eight additiona! portfolios (portfolios developed under this fourth scenario exercise are
denoted as "(4)" under each carbon/gas planning future with and without B2H). ln addition
to the guiding principles applied in the first three scenarios, the guiding principles on page
116 of the Second Amended 2019 /RP, set forth below, provided the sideboards for
portfolio adjustments in scenario four:
. Large-scale combined cycle combustion turbine ('CCCT") units can, in
some cases, be replaced with more scalable reciprocating gas engines,
allowing a phased approach to adding flexible resources that reduces costs.
. Demand response can be accelerated and/or expanded to defer some
types of resources.
. Depending on the portfolio builds, accelerating solar and battery resources
and alternating with flexible resources can result in portfolio savings.
IDAHO POWER COMPANY'S REPLY COMMENTS - 36
. Solar-plus-battery resources are often selected before solar-only resources
because they allow a higher contribution to peak.
The table below shows how the Company adjusted Non-B2H and B2H portfolios
PGPC(1) under the guiding principles described above. For instance, manual
adjustments created Non-B2H PGPC (4) by adding one 300 MW CCCT in 2035 and
additional reciprocating engines, as opposed to the two 300 MW CCCTs selected for Non-
B2H PGPC (1) in yearc 2029 and 2031. Testing the cost-effective adoption of flexibte
resources at different sizes-smaller reciprocating engines versus one large CCCT-was
an attempt to decrease portfolio cost while accelerating solar and battery resources and
reducing reliance on thermal resources.
Table 4: Resource Adiustments Between Manually Optimized PGPC Scenario 1and Scenario 4
Non-B2H (MW)B2H (MW
Portfolio
Thermal
Wind
Solar
Battery
Demand Response
Transmission (B2H)
Coal Exits
PGPC (4)
911
0
360
80
50
nla
-1,026
PGPC B2H (1)
411
0
400
80
45
500
-1,026
PGPC B2H (4)
389
0
440
80
45
500
-1,026
PGPC(1)
933
0
320
80
50
nla
-1,026
However, while the objective of the fourth scenario was to determine if an even
lower-cost resource portfolio could be developed by testing the introduction and removal
of certain technologies, the Company found that this fourth scenario exercise did not
produce a lower-cost portfolio compared to the prior three manually adjusted scenarios.
The Company believes that the process and examples in this section provide the
necessary insight into the systematic process the Company followed when making the
manualadjustments to the portfolios. ln total, the manual adjustment process yielded 24
IDAHO POWER COMPANY'S REPLY COMMENTS .37
additional portfolios that were further evaluated in the AURORA model to determine their
NPV, the results of which were shown in Tables 9.5 and 9.6 of the Second Amended
2019 tRP.75
C. Stochastic Risk Analysis
ln its comments, STOP B2H reiterates its claim that ldaho Powerfailed to consider
carbon risk in the stochastic analysis.To STOP B2H further claims that, in this Second
Amended 2019 lRP,ldaho Power structured the stochastic analysis to bias the analysis
against all portfolios that were optimized under a high carbon cost future.77
Contrary to STOP B2H's claims, ldaho Power looked extensively at carbon price
futures throughout the portfolio development process. STOP B2H suggests that ldaho
Power should have used stochastic risk analysis to evaluate carbon prices.78 ldaho
Power disagrees. The intent of stochastic analysis is to examine the risk associated with
unpredictable or uncertain variables, such as weather or water levels. ln contrast, there
are many real examples of carbon price curves from proposed and implemented policy,
making the range of carbon prices neither unpredictable nor uncertain. As a result, ldaho
Power believes that little would be gained from stochastic analysis of carbon pricing while,
in contrast, much can be learned from evaluating resource portfolios at various carbon
price curves, as the Company has done.
To that end, ldaho Power's LTCE modeling was performed under three natural gas
price forecasts and four carbon price forecastsTe to develop optimized resource portfolios
75 Second Amended 2019 IRP at117-118.
76 STOP B2H's Comments at 26.
77 ld. at27.
78 ld. al27.
7e Second Amended 2019 IRP at 106.
IDAHO POWER COMPANY'S REPLY COMMENTS - 38
for a range of possible future conditions. Various carbon price futures were further
analyzed on select portfolios during the manual portfolio development process. ln fact,
two of the three portfolio groupings selected for manual optimization were developed
under a high-carbon price scenario,8o precisely to account for a range of possible policy
futures. PIease see Chapter 9 of the Second Amended 2019 IRP for the full discussion
of carbon pricing in the portfolio development process and stochastic risk analysis.
D. Regulation Reserve
Staff recommends that the Company further examine how to appropriately
implement the regulation reserve requirements in the IRP modeling process and explore
any cost and reliability impacts from any reserve shortfalls.sl ldaho Power, as part of the
Second Amended 2019 IRP Action Plan, consulted with Energy and Environmental
Economics, lnc. ("E3") to conduct a Variable Energy Resource ("VER") lntegration Study.
The scope of the study included defining new regulation reserve requirements for the
2021 lRP. ldaho Power is in the process of reviewing E3's analysis to inform the
development of future integration costs and to help determine the regulation reserye
requirements for the 2021 lRP. ldaho Power commits to explore cost and reliability
impacts from reserve shortfalls as part of the 2021 IRP analysis.
E. Discount Rate
Staff correctly describes the changes to the discount rate that occurred between
the original2019 IRP and the subsequent amendments and agrees with the Company's
adjustment back to the after-tax Weighted Average Cost of Capital ('WACC"). ln the
80 See Second Amended 2019 lRP, Table 8.5 at 110
81 Staffs Comments at 17.
IDAHO POWER COMPANY'S REPLY COMMENTS.39
Amended 2019 lRP, the Company explaineds2 its rationale for changing back to using the
after-tax WACC, and the Company expects to continue using its authorized after-tax
WACC to discount the cost of modeled portfolios. This rate represents a good proxy for
the overall long-term cost of capital to the Company in financing its operations.
V, SUPPLY.SIDE RESOURCES
A. Jim Bridger Unit Retirements
Sierra Club asks the Commission to ensure that PacifiCorp's Bridger coal exits not
be allowed to impose a risk on ldaho Power's Customers.s3 The Company understands
Sierra Club's concern and would like to clariff: the joint owners do not have a current
contractual mechanism to allow for either party to exit units at the Jim Bridger plant. As
such a contract is negotiated, ldaho Power will work with PacifiCorp to determine the
costs and details sunounding the exit of Jim Bridger units.
Idaho Power and PacifiCorp model the utilization of Jim Bridger units independently
through each company's resource planning process, which drives the Jim Bridger exit
dates found in each party's lRP. ldaho Power will continue to pursue exit timing that
provides the best combination of cost, risk, and reliability for customers.
B. Costs and Characteristics of Supply-Side Resources
Stating that the cost and characteristics of alternative generation resources is among
the most important aspects of the IRP process,sa ICL criticizes the resource cost data in
the IRP and urges the Commission to direct ldaho Power to issue a request for
information ("RFl') about projects specific to ldaho and ldaho Power's needs to determine
82 ldaho Power's Amended 2019 IRP at 4-5 (Jan. 31,2020)
83 Sierra Club's Comments al2-3.M ICL's Comments at 3.
IDAHO POWER COMPANY'S REPLY COMMENTS - 40
accu rate p rici n g a nd perfo rma n ce characteristics. 85
The Company agrees with ICL that future resource costs and characteristics are
critical to the analysis process. ldaho Power uses pricing information from several well-
established and publicly available sources, including the National Renewable Energy
Laboratory ("NREL') and Lazard, that collect pricing data and develop forecasts. ldaho
Power then takes this data and adjusts it to achieve location-specific data. For example,
the solar insolation values included in the 2019 IRP are specific to ldaho power's service
area. ldaho Power presented the cost and characteristics of alternative generation
resources to the IRPAC for feedback and the Company adjusted the numbers based on
feedback received.
The Company recognizes that some resource costs have become cheaper since
the 2019 IRP filing. Resource costs are never stagnant, and as such, it's common for
such costs to change after an IRP is filed. The purpose of the Second Amended 2O1g
/RP was to improve the analysis and ensure the Preferred Portfolio represented the best
combination of least-cost and least-risk given the inputs selected in the 2O1g lRp. lnputs
will be refreshed, and stakeholderfeedbackwillbe incorporated in the 2021lRp process.
With respect to ICL's recommendation to issue RFls to get Idaho Power-specific
resource estimates, the Company would note that it has extensive experience issuing
RFls and requests for proposal ("RFP"). RFls/RFPs are most often issued in advance of
resource selection and development, and not typically for the purposes of providing price
estimates for long-term resource planning because they take considerable time and effort
from the bidding parties. Further, it is important to note that most RFls/RFPs are time-
as H. at 4.
IDAHO POWER COMPANY'S REPLY COMMENTS .41
limited and near-term-that is, indicative pricing is provided for projects in the near term
(not for development many years in the future) and will only remain fresh for a short period
of time (e.g., 30-90 days). The Company believes that the latest public data, from sources
such as NREL, provide a good comparison across all resources being evaluated,
including resources where there may be no responses to an RFl. However, ldaho Power
is interested in ICL's perspective on the usefulness and lasting relevance of RFls for
resource planning and looks forward to discussion around this topic during the 2021 IRP
process.
C. Distributed Generation and Distributed Energy Resources
While Sierra Club provides recommendations to improve the Company's analysis
for distributed energy resources ("DERs") in the 2021 lRP, ICL broadly claims that the
2O1g '!RP does not obviously contain any forecast of continued growth of distributed
energy, neither in the load forecast or in the options of generation resources.'86 ICL asks
the Commission to direct the Company to incorporate a distribution-level analysis of
needs, constraints, and hosting capacity.sT Micron's comments focused on their
sustainability goals and is interested in the Company's plans to add additional solar and
battery storage over the planning horizon and is currently analyzing strategies to obtain
additional renewable energy.88
Sierra Club explains that DERs sited in ldaho could mitigate the risk of over-
reliance on out-of-state resources and, for the 2021 !RP, recommends ldaho Power study
6 ld. al4.
87 ld. at 4.s Micron's Comments at 3.
IDAHO POWER COMPANY'S REPLY COMMENTS .42
the potentia! to use storage and improved control processes on its distribution system to
hamess the benefits that Idaho-sited DERs can potentially provide.se
ldaho Power agrees with much of Sierra Club's assessment and has been
analyzing the incorporation of solar, storage, and solar-plus-storage projects for several
years as part of its Non-Wires Alternatives analysis when considering distribution system
upgrades. ln the 2019 IRP, a transmission and distribution deferral value for solar was
calculated and used to model the value of potential infrastructure deferrals from solar
installations on the distribution system.eo The Company looks forward to incorporating
the learnings from its storage and solar-plus-storage project studies into the 2021 IRP
analysis and will present the methodologies to the IRPAC and will work with Micron to
help achieve their sustainability goals.
Contrary to ICL's criticism, ldaho Power did include the impacts of customer-sited
generation in the load forecast published in the 2019 IRP and included DER as selectable
resource options. As described in more detai! in Chapter 4 of the Second Amended 2019
/RPreport,rooftopsolarwasconsideredintwoformsaspartofthe20lglRP. lnaddition
to generic locations for solar photovoltaic arrays, the 2019 IRP analyzed select areas that
are reflective of a target siting for solar capacity within Idaho Power's system. These
select areas were limited in size at 0.5 MW, with a total of 10 MW for the 2O-year planning
period.el
To reflect the impact of an increasing number of customers installing on-site
generation (namely, solar), the 2019 lRP longterm sales forecast was adjusted
8e Sierra Club's Comments at 7.s SecondAmended 2019 IRP at50-51
e1 ld. at 47.
IDAHO POWER COMPANY'S REPLY COMMENTS - 43
downward.e2 To calculate the impact, ldaho Rate Schedules 6, 8, and 84 (customer-
owned generation) customer billing histories were compared to billing histories prior to
the schedule change. The resulting average monthly impact per customer (in kWh) was
then multiplied by forecasts of ldaho Rate Schedule 6, 8, and 84 residential and
commercial customer counts to estimate the future energy impact on the sales forecast.
The forecast of net metering customers was a function of historical trends and current
policy considerations. The resulting forecast of customer-owned generation customers
multiplied by the estimated use-per-customer sales impact, resulted in a monthly
downward adjustment to the sales forecast by class. At the end of the 2O-year forecast
period in the 2019 lRP, the annual residential sales forecast reduction was about 38 aMW,
and the commercial reduction was less than 4 aMW.
In recent years, the number of customers transitioning to net metering service has
risen, especially for residential customers. While the cunent population of on-site
generation customers at the time of the development of the 2019 IRP was one-half of 1
percent of the population of retail customers, recent adoption of solar is relatively strong
in ldaho Power's service area and those higher values will be reflected in the 2021 IRP
load forecast.
Lastly, as ICL recommends,e3 ldaho Power plans to include additional DER
opportunities in the 2021 IRP analysis and will present those ideas in the 2021 IRPAC
meetings.
D. Battery Storage
Sierra Club and lCL are critical of the 2019 IRP's assessment of battery storage
s2 Second Amended 2019 lRP, Appendix A at 32.
e3 ICL Comments at 6.
IDAHO POWER COMPANY'S REPLY COMMENTS .44
technology. Sierra Club believes the AURORA modelfailed to include appropriate levels
of storage thus introducing bias toward lowering expected West Coast wholesale market
pricesea and ICL cited that the Company did not include or quantify the potential grid
services that various storage technologies can provide.es
The Company views storage solutions as an important part of ldaho Power's future
and will continue to evaluate optimal storage, both to integrate new and existing resources
and to provide ancillary services.
Regarding the perceived lack of storage added through the LTCE in AURORA, as
pointed out by Sierra Club,eo ldaho Power would note that the Preferred Portfolio inctudes
80 MW of battery storage. This amount was adopted because the model economically
selects resources to meet demand. The Company did not manually add or remove
resources outside of the ldaho Power system in the model. With respect to the modeled
amounts of storage in the lRP, Table 5 (below) shows the extensive amounts of storage
solutions available for selection in the 2019 lRP.
Table 5: Storage Options Modeled in 2019 IRP
Category Total Potential (MW)
Lithium lon Battery
Lithium lon Battery Paired with Solar
Lithium lon Battery Paired with Solar
Lithium lon Baftery Paired with Solar
Hydro Pumped Storage
Total Lithium Ion Battery
Tota! Hydro Pumped Storage
Total Solutions
% Sierra Club's Comments at 3-4.
s5 ICL's Comments at 4.s Sierra Club's Comments at 3.
IDAHO POWER COMPANY'S REPLY COMMENTS - 45
180
30
20
30
500
260
500
760
Adoptable Resource
Blocks (MW)
5
10
20
30
500
With each new lRP, ldaho Power will refresh resource cost curves. lt is possible
that battery storage will become a more economic resource to meet Idaho Powe/s needs
as technologies advance and, therefore, will be selected more frequently within the least-
cost, least-risk portfolio.
ldaho Power received feedback from ICL and other stakeholders regarding
additional value streams that battery storage can provide. ln 2O20, the Company formed
an internal team of subject matter experts to evaluate other benefits of storage technology
beyond renewables integration. The findings from this team will be presented to the
IRPAC and the Company plans to apply additional value streams for storage technologies
in the 2021 lRP.
E. Adiustments to Natura! Gas Plants
STOP B2H raises concerns over ldaho Power's decision to incorporate start-up
costs in the modeling for naturalgas peaker plants-a change identified in the IRP review
process and applied in modeling the Second Amended 2019 lRP.e7 ln support of the
change, the Company provided the following explanation in the 2019 IRP Review Report,
which was submitted alongside the Second Amended 2019 IRP:
Natural Gas Peaker PIant Start-Up Costs: The maintenance costs
associated with natural gas peaker plants were captured only as a variable
cost applied directly to the run time of the unit. Startup costs were not
included, which resulted in more frequent dispatch of the peaker plants and
for shorter durations than expected. After identifying the issue, startup costs
were entered, resulting in a reduction in peaker dispatch and more
accurately reflecting a logical and expected outcome.es
STOP B2H claims that including plant start-up costs means that ldaho Power
deliberately adjusted the AURORA mode! to justify future gas replacements, as
e7 STOP B2H's Comments at 28-31.
s8 SecondAmended 2019 IRP Review Report at 6.
IDAHO POWER COMPANY'S REPLY COMMENTS - 46
alternatives to the more expensive peaking plants.ee STOP B2H further states that this
modification goes against Executive Order 2g-g4,to0 and that the Commission should
therefore refuse to acknowledge this lRP.101
STOP B2H is mistaken. Modeling for natural gas peaker plants was adjusted to
more accurately reflect the real costs incurred when dispatching a peaker plant. This
change was prompted by the Company's review process, during which time the Company
discovered that gas peaker plants were not dispatching in the model as expected.1o2
Faced with this anomaly, the Company's subject matterexperts carefully reviewed natural
gas peaker plant Operation and Maintenance ("O&M") costs-specifically start-up
costs-then updated, tested, and documented the adjustment to the model. Rather than
modifiTing the Company's AURORA model to justify new gas facilities, the Company's
more nuanced analysis disfavors natural gas peaking plants by accounting for the more
costly start-up process associated with peaking dispatch.
F. Market Purchases
Sierra Club expresses concem that ldaho Power is relying on others for a large
portion of the energy required to serve customers stating that such a reliance seems
highly unrealistic and should be carefully examined when reviewing portfolio altematives
in the 2021 lRP.103 The Company respects Sierra Club's observations and would like to
clarify that the 2019 IRP analysis did limit the amount of transmission capacity that can
es STOP B2H's Comments at 31.
100 On March 10,2020, Oregon Governor Brown issued Executive Order 20-04 (EO 20-04) directing certain
state agencies to take specific actions to reduce and regulate greenhouse gas emissions to mitigate the
impacts of climate change.
1ol STOP B2H's Comments at 31.
102 Second Amended 2019 IRP Review Report at 54-55.
103 Sierra Club's Comments at 6.
IDAHO POWER COMPANY'S REPLY COMMENTS - 47
be counted toward meeting the Company's planning margin. These transmission
capacity assumptions will be reevaluated in the 2021 lRP.
To more fully develop a thoughtful regiona! energy exchange, Idaho Power is
engaged with other utilities in the Northwest to create the framework for a regional
resource adequacy program. The focus of the program is to ensure adequacy of
resources and market availability in the future. A properly designed regional resource
adequacy ptan provides coordinated planning on a regional basis. Through effective
management of resources, partnering utilities can defer investment in dispatchable
resources while having a more accurate picture of regional resource adequacy needs,
driving correctly sized and timed investments.
VI. DEMAND.SIDE RESOURCES
Demand-side resources, or demand-side management ('DSM') resources,
including energy efficiency ('EE") and demand response ("DR"), are important aspects of
ldaho Power's resource planning process and were included in the 2019 lRP. ldaho
Power has a mature portfolio of both EE and DR programs available to all customer
segments, and the Company has achieved steady gains in its DSM offerings over time.
A. Energy Efficiency
1. EE Savinos Have Grown Steadilv Over Time.
STOP B2H claims ldaho Power's energy savings have remained relatively static
since 2015 and actually have declined since 2010.104 STOP B2H is incorrect. ln 2019,
ldaho Power achieved its highest EE savings since the Idaho Energy Efficiency Rider
104 STOP B2H's Comments at 47
IDAHO POWER COMPANY'S REPLY COMMENTS .48
was established an 2002.105 ldaho Power has seen steady growth, with energy savings
growing from 162,533 MWh in 2015 to 203,041 MWh in 2019-a 25 percent increase
since 2015. These savings were achieved over a period with significantly declining
DSM alternate costs, which decreased by more than one-half between the 2011 IRP
and 2019 lRP. This data point proves that the Company has continued to support
cost-effective EE even when energy savings assumptions for a variety of measures
reduced over time. Figure 2 is from the Company's 2019 DSM Annual Report,
highlighting savings achievement from 2002 through 2019 and, in particular, showing
the steady growth in savings achievement since 2013.
Figure 2: Annual energy savings and energy efficiency program expenses,
2002-2019 (MWh and millions [$l)106
r Market Transformation (NEEA) (MWh)
r ldaho Power Program Savings (MWh)
-EE
expenses (no DR)
2@2 2003 2004 20{J5 20iJ6 20r)7 2(x)8 2009 2010 201',t 2012 2013 2014 2015 2016 2017 2018 2019
Further, the following chart from the NWPCC illustrates regional trends in EE
lrom 2004 to 2019 and shows that, not only has regiona! EE savings potential
ros In fhs Mafter of ldaho Power Company's Application for a Determination of 2019 Demand-Side
Management Expenses as Prudently lncurred, Case No. IPC-E-20-15, ldaho Power Company's 2019
Demand-Side Management Report at 1 (Mar. 13,2020).
106 Qsss No. IPC-E-20-15, ldaho Power Company's 2019 Demand-Side Management Report at 5.
IDAHO POWER COMPANY'S REPLY COMMENTS - 49
$45
$40
$5 E'
3$,E
o
$25 g
oo
$20 fi
o$15 tr
G''6
$10 E
o$5btrUJ
$o
250,000
2m,000
1s0,000
100,000
50,000
0
.C
==oo,'t(!
at)
aD
oElJJ
decreased since 2016, but the regional savings achieved by utilities have remained
the same or declined since 2010. ln contrast, ldaho Power's savings have rebounded
since 20'13, with savings steadily increasing in recent years, unlike the rest of the
region.
Figure 3: Northwest Power Council's Regionat Energy Efficiency Targetstoz
The region's ulility-funded savings have exceeded tre Council's annualefricioncy hrgets from 200&2017, with
201&2019 the only shortfalls.
2oo{ z{no 2oo. g*,, '11,,,* 'to 2018 2o1E
2. ldaho Power's EE Tarqets Are Consistent with lndustrv Standards.
STOP B2H further asserts that the Company's EE targets are set too low,
thereby impacting resource forecasting needs.108 In response to stakeholderfeedback
and the Company's commitment to pursue all cost-effective EE, ldaho Power modified
its EE potential as part of the 2019 IRP to include utilization of the AURORA model. The
model could screen and potentially select EE bundles, above the EE amounts already
identified as achievable economic potential in the third-party Potential Study (described
1o7 NWPCC, What have the region and Council achieved? (202'l), available at
httos ://www. nwcouncil.orq/energy/enerov-tooics/energv-efficiencv.
1oB STOP B2H's Comments at 48.
IDAHO POWER COMPANY'S REPLY COMMENTS.50
350
300
2&g
c;2ma
*,m=€
r00
50
0
in more detail below). The AURORA model did not select any of the higher-cost EE
bundles.
The Company's historicalapproach to EE savings potential in the !RP is consistent
with industry standards. The achievable economic potential is based on a rigorous
assessment of the available EE potential in ldaho Power's service area, conducted by an
experienced third-party consultant using industry-standard methods. For the 2019 IRP
and the forthcoming 2O21 lRP, ldaho Power has contracted with Applied Energy Group
(.AEG"), which has significant experience and expertise in developing EE potential
studies. AEG has done this precise work for many utilities and, also, has prior experience
developing potential studies for ldaho Power.
To perform the Potential Study analysis for the 2019 lRP, AEG used the following
approach:
1. Performed a market characterization to describe sector-level energy use for
the residential, commercial, industrial, and irrigation sectors for the base
year of the study. This included using Idaho Power data and other
secondary data sources, such as data from the U.S. Energy lnformation
Admin istration ("ElA").
2. Developed a baseline projection of energy consumption and peak demand
by sector, segment, and end use for the time period of the study.1oe
3. Defined and characterized several hundred EE measures to be applied to
al! sectors, segments, and end uses.
10e Sector refers to the customer type (i.e., residential, commercial, industrial, inigation), while segment
refers to the customer electricity type (e.g., home type, school, retail or industrial Standard lndustrial
Classification code).
IDAHO POWER COMPANY'S REPLY COMMENTS - 51
4. Estimated technically achievable potentia! of EE measures in terms of
energy and peak demand impacts from those measures for the time period
of the study.
5. Determined the achievable cost-effective EE using avoided cost information
from ldaho Power as the threshold value of EE.
The Company is expanding on its experience with EE bundling and EE selection
through AURORA as part of the 2021 lRP. lnitial discussion with stakeholders through
the EE subcommittee indicates a preferred approach of including achievable economic
potential from the Potential Study with additional, selectable-by-AURORA bundles.
ldaho Power looks forward to working closely with the IRPAC to further refine how EE
potential is modeled in the 2021 lRP.
B. Demand Response
STOP B2H notes that ldaho Power's DR capacity has decreased since 2012
and claims that this decrease demonstrates that the Company's DR efforts are "half-
hearted" and that the Company seeks to avoid clean-energy commitments.ll0
While STOP B2H is correct that DR capacity decreased since 2012, STOP B2H
overlooks the reason for the decrease. To be clear, ldaho Power's DR programs were
designed specifically to avoid or delay the need to build new supply-side peaking
resources within very Iimited peak hours and days. In 2012, the Company's analysis
showed that there would be no capacity deficit in peak hours over the next several
110 STOP B2H's Comments at 46, 50
IDAHO POWER COMPANY'S REPLY COMMENTS - 52
years.111 Upon Commission authorizatlon,ll2 ldaho Power therefore temporarily
suspended two of its three DR programs to avoid spending customer money on a
resource that was not needed. ln a subsequent proceeding opened to examine the
Company's DR programs, the parties and the Commission agreed that the Company
would continue operating a cost-effective resource, maintain program participation
until the programs are needed, and minimize ongoing costs to customers.113 While
STOP B2H criticizes the Company for relying on the 2013 settlement agreement, the
Company believes that its compliance is appropriate.lla ldaho Power would like to
point out that its 2019 DR capacity as a percent of system peak remains significantly
higher than most utilities in spite of a decrease. The figure below compares ldaho
Power's DR capability compared to other investor owned electric utilities.
ttt In t1s Matter of the Application of ldaho Power Company for Authority to Temporarily Suspend its A/C
C_ool Credit and lnigation Peak Rewards Demand Response Programs, Case No.'lp}-E-,12-2q Order No.32776, p.2 (Apr. 2,2013).
112 Order No. 32776.
113 In the Mafter of the Continuation of ldaho Power Company's A/C Cool Credit, lrrigation peak Rewards,and Flexpeak Demand Response Programs for 2014 and Beyond, Case No. lpa-E-13-14, Order No.32923, p.6 (Nov. 12,2013).
114 STOP B2H's Comments at 47; Order No. 32923 at 7.
IDAHO POWER COMPANY'S REPLY COMMENTS - 53
Figure 4: Demand Response as a Percent of System Peak115
Demand Response as a Percent of System Peak
Finally, STOP B2H protests the lack of new DR for 10 years based on the
preferred Portfolio.116 ln the Second Amended 2019 lRP, a capacity deficit is not
identified until 2026, and that deficit is met through a resource with broader availability
than DR. The Company's IRP analysis indicated that, with the current level of DR on
the system (11 percent of ldaho Power's all-time system peak), additional DR capacity
does not serve as the lowest-cost resource until 2030'117
VII. FORECASTS
A. Load Forecast
The Company understands the significance of the role of peak forecasting in long-
term capacity planning and recognizes the critiques and recommendations by the parties
115 U.S. Energy lnformation Administration, Annual Etectric Power lndustry Repol!, Form EIA-861 detailed
data fites (Oci. 6, 2O2O), available at httos://www.eia.qov/electricitv/data/eia861/. Please note that the figure
includes data from investor-owned electric utilities only.
116 STOP B2H's Comments at 4748.
117 Second Amended 2019 IRP at15.
L8%
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L4%
L2%
lfrrrr,,rrrlllllllo%rr
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go
IDAHO POWER COMPANY'S REPLY COMMENTS'54
to improve the forecast as offered by Commission Staff, Sierra Club, and StopB2H. ln
the section that follows, the Company will provide a brief summary of its peak forecasting
model performance, then address each set of party comments in turn.
ln modeling peak, it is important to remember that the data must be adjusted to
remove the impacts of DR programs' peak reduction as an exogenous impact. Thus
adjusted, the Company's forecasting of system peaks as model output aligns wel! with
historic values as seen in the figure below.
Figure 5: Peak Forecast Adjusted for DR
MW
5,000
4,5m -Adual
DR Adj
-
100 Petcertle
--- 50Percentile
-0
Perc€ntile4.0m
3.500
3,0m
2.500
2.000
.5001 !t (o @ o $t rt (0 @ (f 6t rt (o @ o e\, tt (o @ c c{ rt q} ei e| st !t (!) Co otsEEEE EESEB E88aa EEEg g SSSBB BBEB(\t C.r C.r $r C{ (\t a{ e{ $a (\l N (\t N $r c\r N f.a Gl C.l Gt fr
Therefore, when considering the suggestions and critiques offered by parties in
their comments, it is important to first consider the performance of the current model when
evaluating whether the proposed changes will result in a more robust model with
improved accuracy.
1. Aqoreoation Modelinq and Sensitivitv Analvsis.
Staff recognizes that the Company made improvements to the peak load
forecasting methodology compared to the 2017 lRP, but believes that even more
IDAHO POWER COMPANY'S REPLY COMMENTS - 55
improvements can be made by using a non-linear model or generalizable linear model
that is more closely aligned to the underlying relationship between peak Ioad and
consumption drivers.l 1 8
The Company appreciates Staff acceptance of the Company's peak modeling
methodology as adequate for use in the 2019 IRP along with recognizing the Company's
willingness to improve its methodology. While the Company has @ncerns with certain
recommendations proposed by Staff, it is open to applying some modifications and
introducing a sensitivity analysis as further discussed below.
First, the Company is concemed that adopting a bottom-up approach as
recommended by Staff will not guarantee improved accuracy relative to the present
systemwide approach. This is primarily due to the fact that the present approach
leverages the rich system-level historical data, which allows the models to capture the
nuances of peak behavior. Additionally, the Company's approach to modeling peak load
considers several variables that consumption modeling does not, including average daily
peak day temperature, average daily peak day temperature trend, average system MW,
and multiple indicator variables (e.9., adjustments for impacts related to the 2001 energy
crisis).
A bottom-up approach would be based on advanced metering infrastructure
('AMl") data to "teach" a regression the individual unique class causation, including, but
not limited to, hourly data and temperature response. AMI data has limited history
constrained by the AMI implementation date, with the bulk of reliable AMI data occuning
in2O14. Another consideration is the fact that the system peak data includes peak losses,
118 Staffs Comments at 13.
IDAHO POWER COMPANY'S REPLY COMMENTS - 56
approximately 8 to 12 percent depending on service level, which would introduce the
additional uncertainty of line loss estimates under a bottom-up approach. Given the
relatively short timeframe of available AMI data and the added complexity of line loss
estimates, the Company does not believe a bottom-up approach would improve accuracy
relative to the curent systemwide peak forecasting model that is based on robust,
comprehensive data.
Aside from these concems, the Company agrees with Staff that class peak
dynamics are important to be aware of. Thus, based on Staffs recommendation, the
Company proposes that class-level AMI data be used to inform assignments of ctass
contribution to the system peak. The Company commits to include an analysis using the
class-level peak contribution approach in future lRPs. Further, the Company commits to
including sensitivity or probability bands of its system peak forecast in future lRPs.
2. Peak Load Forecast Maqnitude.
Sierra Club is also critical of the Company's peak load forecast, concluding that
the peak forecast over the next two decades is dramatically higher than what the
Company has experienced over a similar period in the past. Sierra Club recommends a
review of a more modest increase in projected future peak load growth in the 2921 1P<p.tts
When assessing peak values, it is important to make a historic comparison to peak
demand hours that have been adjusted for DR and adjust for any major changes in the
customer base (e.9., exclusion of Astaris). ln doing such and comparing the results with
the Company's forecast of peak over the term of the Second Amended 2019 /RP, the
forecast is reasonable as demonstrated in Figure 5 (above). !t is also important to note
11e Sierra Club's Comments at 6.
IDAHO POWER COMPANY'S REPLY COMMENTS - 57
that while historic values are a key driver, not every annual peak hour event was driven
by the same or similar weather conditions, which is central to the Sierra Club's criticism
of the Company's peak load forecast as shown in the figure below. Figure 6 is reproduced
directly from page 6 of Sierra Club's comments for reference.
Figure 6: Sierra Glub Figure on Peak Load
Figure 3 - Over.-estimates offitture peak load growth disadvqntoge ldoho-based qhematives
2019 lRPforecasts faster peak load growth over next 20 years
than actual peak load growth during prior 20 years
=
;oo;oo,o-
o
E
E:
4500
4200
3800
3400
3000
2600
22AO ililil nirilIilllllil]l
2000 2oo2 2oo4 2006 2008 2010 20 1220t4201620t82020202220242026 2028 2010 2032 2034 20362038
-Actual
Peak I Forecast Peak """' Lineor (Actual Peak )
The historical system peaks that are graphed are historical actual system peaks,
which appear to have an unweighted trendline extended into the future, which is then
compared to the Company's peak forecast. As discussed above, adding a trendline
through actual peaks-where each historical year's peak has its own probability of
occurrence-has little meaning and can lead to confusing results and misinterpretation.
For IRP planning purposes, the Company plans to 50th percentile conditions plus a 15
percent planning margin. Comparing the trend of average peak load growth unadjusted
for historical weather or precipitation to a forecast reflecting 50th percentile conditions plus
15 percent would always demonstrate that the trendline is less than forecasted peak.
IDAHO POWER COMPANY'S REPLY COMMENTS - 58
This result is due to an inconsistent comparison rather than any deficiency in the
Company's peak forecasting methodology. The depiction in Figure 5 (above) is a more
accurate method of comparison, in that it shows the actual historical peak adjusted for
DR compared to expected peak load at the O, s0th, and 100n percentite forecast. lt should
also be noted that Sierra Club's figure commences in 2000, which creates a trendline with
a different slope than a more robust consideration of history would indicate. To that end,
the statement that "the Company forecasts peak toad growth over the next two decades
at dramatically higher rates than the Company has experienced over a similar period in
the pas1"120 is not supported by Sierra Club's analysis.
It has also become clear that the Company's system has become "peakie/' over
time, meaning the growth in peak demand is outpacing the grovtrth in average energy
consumption. Figure 7 below demonstrates this trend: there has been quicker growth in
summer months as evident by the steeper slopes at higher temperatures.
12o ld. at 6
IDAHO POWER COMPANY'S REPLY COMMENTS - 59
Figure 7: Actual Monthly Peaks (DR-Adiusted) by Average Daily Temperature
Ml^,
4,OOO
3,500 o
3,OOO eao;
a ia
a aaaao
1,500 o
a '.a
1,Ooo
o'flO o'9O o'OO o '1O
soo
o
-40 -20 o 20 40 60 ao 100
Avg Daily Temp (systcm weiShted)
Whereas the Company does project consistent growth in average load in the future, this
dynamic directly impacts the faster, or "peakier," growth in annual hourly demand max of
the system relative to the average annual growth, or the summer relative to winter months.
A key consideration to this occurrence is the continued robust grovuth across all customer
classes, the impact of which has carried more so into summer versus winter load
demands.
3. lnferred Econometric Modelinq.
STOP B2H's comments provide significant criticism of the Company's load
forecast and the underlying methodology. STOP B2H suggests several methodologies
IDAHO POWER COMPANY'S REPLY COMMENTS - 60
for conducting the load forecast that, it believes, would reduce the error in the Company's
forecasts.121
The Company has taken strides to incorporate considerations and feedback with
respect to its modeling processes. An important consideration for any modeling effort is
accountingforthelongterm analyticalnatureof the lRP. Forexample, a linearregression
model minimizes the potential to inaccurately extrapolate near term-trends-such as
short-term variability associated with inigation demand, for example, or unforeseen
changes in economic conditions-into the Iong-term future. Additionally, models such as
linear regressions are effective at considering longer-term rates of change. The
Company's present forecast methodology provides a long-term planning framework that
aligns retrospective comparisons to weather-adjusted groMh, while accounting for the
specific factors that impact ldaho Power's future load.
Thus, while ldaho Power acknowledges STOP B2H's comments and suggestions,
the Company continues to believe that the inferred econometric models are the best
available means for long-term load grovuth forecasting, with their ability to factor in both a
rich history of data and to account for a range of factors impacting load growth. These
models are the industry standard for long-term load forecasting in the IRP context.
STOP B2H asserts that the increase in residential population has been perfectly
matched by a decrease in average residential use, resulting in "flat sales for thirteen
years." 122 STOP B2H is incorrect, as demonstrated by clear data. ldaho has been the
fastest growing state for three consecutive years, as determined by the U.S. Census
121 STOP B2H's Comments at 3742.
122 ld. at 37-38.
IDAHO POWER COMPANY'S REPLY COMMENTS - 61
Bureau.l23 Evidence of this trend can be found in the Company's weather-adjusted sales
to the residential class, which has grown in the range of approximately 1 to 2 percent per
year in recent years (see Figure 8 below). Beyond the net residential-related growth in
ldaho Power's service area, the foundationa! agricultural base of the Company's service
area continues to grow.
Figure 8: ResidentialAnnual Weather Adjusted Sales Growth
Groudr
RE[o
2.V/o
1.5Yo
1.8/o
0.5olo
0.V/o
2016 2s17 2018 2019
B. Natural Gas Price Forecasts
ICL is critical of the natural gas price forecast used by the Company because it
was proprietiary, and the Company could not provide the IRPAC with the underlying data
to vouch for accuracy of the forecast. To assure transparency, ICL recommends the
123 See U.S. News, "America's Fastest-Growing States' (Dec. 22, 2020), available at:
https://www.usnews.com/news/best-states/slideshows/these-are-the-10-fastest-growino-states-in-
america.
IDAHO POWER COMPANY'S REPLY COMMENTS - 62
Commission direct ldaho Power to use the publicly available forecast in reference case
of the U.S. Energy lnformation Administration's ('ElA") Annual Energy Outlook.l24
ldaho Power agrees with ICL that it is important to analyze which gas price forecast
source has a history of accurately forecasting future prices. The Company plans on
assessing this again for the 2021 lRP. By way of background, ldaho Power used the
publicly available EIA High Oiland Gas Resource and Technology ("E|AHO") forecast as
the planning case natural gas forecast in the 2017 IRP-an approach that was highly
criticized, even by ;g1.tzs As a result, the Company committed to continue evaluating
the natural gas price forecast process and to work with stakeholders to develop an
appropriate gas forecast for the 2019 lRP.
Based on the methodologies employed by ldaho Power's peer utilities and
feedback from 2019 IRPAC meetings-which recommended that ldaho Power employ a
third-party forecaster to eliminate any potential or perceived selection bias-ldaho Power
enlisted the service of a well-known third-party vendor by subscribing to S&P Global Platts
North American Natural Gas Analytics ("Platts").
Because the Platts data is not publicly available, in October 2018, a representative
from Platt's presented their forecast and associated assumptions. This presentation gave
IRPAC members the opportunity to ask questions and discuss the details of the forecast
with the vendor, an option not available when using an EIA forecast. Additionally, the
underlying data and methodology for the EIA forecast is not publicly available; simply the
output of the EIA forecast is not confidential. Therefore, in this regard the Platts forecast
124 ICL's Comments at 3.
rzs In fhg Matter of ldaho Power Company's 2017 lntegrated Resource Plan, Case No. IPC-E-17-11, ICL
Comments at 14 (November27,2017).
IDAHO POWER COMPANY'S REPLY COMMENTS .63
is more transparent than the EIA information, as demonstrated by a Platts representative
presenting to the IRPAC and facilitating an in-depth discussion of the underlying
assumptions and methodology. While the EIA model output is indeed public, ldaho Power
believes thorough review of the underlying assumptions and modeling technique would
be /ess transparent than a similar review of the Platts forecast.
To verifo the reasonableness of the PIatts forecast, Idaho Power compared it to
the EIA forecasts, and to Moody's Analytics and the NYMEX natural gas futures
settlements. A comparison of these various natural gas price forecasts is depicted below,
in Confidential Figure 9.
Figure 9: Confidential Comparison of Natural Gas Price Forecasts
As can be seen in Confidential Figure 9, the ElA "high" and "reference" cases are
both elevated, and do not reflect actual market prices. While the Moody's Analytics and
Platts forecasts converge around 2029, the near-term Moody's Analytics forecast was far
above where the market was trading at the time. Based on this comparative analysis and
feedback from the IRPAC during the process and given the robust natural gas forecasting
IDAHO POWER COMPANY'S REPLY COMMENTS - 64
methodology employed by Platts, the Company judged that Platts natural gas forecast
was reasonable and should remain the source of the natural gas forecast for future lRPs.
G. Glimate lmpacts on Loads and Generation
ICL notes a small improvement in ldaho Power's assessment of the impacts of
climate change on energy demands and generation sources in the 2019 IRP and
recommends the Commission direct ldaho Power to work with the scientific community
and the IRPAC to devise methods to include changing customer demands and generation
profiles in the IRP assessment process.126
The Company continues its efforts to better reflect climate change impacts for its
hydropower facilities and the peak load forecast. lt tracks the latest climate projections,
as well as studies that are being conducted to reflect relevant temperature, precipitiation,
and streamflow changes in the Snake River Basin. As mentioned in the lRP, ldaho
Power's hydropower system is situated downstream from federally managed irrigation
and hydropower projects on the Snake, Boise, Payette, Owyhee, and other tributaries.l2T
Due to the position of ldaho Power's hydropower facilities, any changes to federal
project operations as a result of climate change will impact ldaho Power's hydropower
system. Rather than create a separate climate change impact study for the Company's
hydropower system, ldaho Power has relied heavily on the River Management and Joint
Operating Committee ('RMJOC'), Second Edition, Part 1 report128 fRMJOC-ll Part 1"),
prepared for the RMJOC members.l2e The RMJOC-|I Part 1 report focuses on the
126 ICL's Comments at 3.
127 Second Amended 2019 IRP a|89.
128 httos://www.bpa.qov/p/Generation/Hvdro/hydro/cc/RMJOC-ll-Reoort-Part-l.odf.tzs fhg RMJOC members include BPA, the US Army Corps of Engineers, and the US Bureau of
Reclamation.
IDAHO POWER COMPANY'S REPLY COMMENTS .65
potential changes to temperature, precipitation, snowpack, and natural streamflow in the
Columbia and Willamette River Basins under a variety of future climate scenarios and
with multiple methods for responding to hydrological changes.
Going forward, ldaho Power plans to continue utilizing RMJOC-II regulation
modeling studies and findings as they become available. This maintains a consistent
framework for understanding the risks and uncertainties associated with climate change
impacts to hydropower throughout the Snake River Basin and allows ldaho Power's
projections to be informed by findings for the upstream and downstream federal system.
For the 2019 lRP, upstream reservoir regulation was not yet available from
RMJOC-||, so ldaho Power conducted its own internal climate risk analysis and has
summarized the key findings based on preliminary modeling using the available RMJOC-
!l Part I natural streamflow datasets. Since the filing of the 2019 lRP, the RMJOC-II Part
2 report13o focusing on climate change impacts to the federal hydropower system, has
been published. The results of the second report support the findings of the internal
analysis conducted by ldaho Power for the 2019 IRP.131 Specifically, both studies found
that inflow to Brownlee Reservoir is expected to increase in the winter to spring period
and liftle-to-no change is expected to occur in the summer to fal!, through the 2O-year IRP
planning period.
With respect to !CL's concerns regarding the Company's peak load forecasting
and temperature changes resulting from climate change, the Company believes that it
appropriately forecasts peak-hour demand as an integral part of the Company's system
planning. Peak-hour demands are forecast using a system of 12 regression equations,
rao https://www.bpa.oov/p/Generation/Hvdro/Documents/RMJOC-ll Part ll.PDF.
131 Second Amended 2019 IRP at89.
IDAHO POWER COMPANY'S REPLY COMMENTS - 66
one for each month of the year. For most monthly models, the regressions are estimated
using 25 years of historical data; however, estimation periods vary. The peak-hour
forecasting regressions express system peak-hour demand as a function of monthly sales
(stated in average MW) and average peak-day temperatures, as well as real electricity
prices and precipitation when statistically significant. The Company's three special
contract customers'contribution to system peak is determined separately using historical
coincident peak factors and are then added to determine the overall system peak
demand.132
The forecast of average peak-day temperatures is a key driver of the monthly
system peak models. The normal average peak-day temperature drivers are calculated
over the most recent 30-year period to capture recent climatological updates. ln addition,
the peak model develops peak-scenarios based on historical probabilities of peak day
temperatures at the 50th, 90th, and 95th percentiles of occurrence for each month of the
year. However, the system peak regression models for the summer months (June, July,
and August) were re-specified to reflect an increasing temperature trend during those
months. These weighted average peak-day temperatures are added to the regression
models to help determine the peak hour demar16.133 In sample testing, adding the
weighted average peak-day temperatures more accurately simulated actual historical
summertime system peaks. Trend variables were added to assist in informing the rising
average peak day temperature impact on summertime peak demand. The Company will
continue to work toward better reflecting climate change in its load and generation
132 Second Amended 2019 lRP, Appendix A at 15-16.r33 /d. at 16.
IDAHO POWER COMPANY'S REPLY COMMENTS - 67
forecast and looks forward to future work and discussions regarding climate change
across all components in its lRP.
VIII. LOAD AND RESOURCE BALANCE
Staff believes that the assumptions used by the Company to formulate its load and
resource balance ('L&RB") are mostly reasonable. However, based on its analysis of the
peak L&RB, Staff proposes several modifications for purposes of determining the first
capacity deficiency date, which would then be applicable to Public Utilities Regulatory
Policies Act ('PURPA') contracts, existing resources for contract renewals, market
purchases, non-owned reserves, and energy efficiency.l3a
Additionally, Staff recommends that the Company include the L&RB table in future
lRPs so that Staff and other stakeholders can readily access the information. The
Company agrees and commits to providing the L&RB table in future lRPs.
A. PURPA Gontract Renewals
Staff recommends that ldaho Power's L&RB should assume that all expiring
PURPA contracts will be renewed after the current contract term is complete, unless the
PURPA Qualifying Facility ("QF") notifies the Company that its contract will not be
renewed.13s The Company's Cogeneration and Small Power Production ('CSPP')
forecast includes all QF generation facilities under PURPA Energy Sales Agreements
('ESA") and non-PuRPA projects delivering generation to the Company pursuant to utility
Power Purchase Agreements ("PPA"). Within the CSPP forecast, ldaho Power assumes
that when QF ESAs expire they will be replaced with new ESAs. This assumption applies
to all resource types except for wind. ldaho Power understands Staffs reasoning for
lil Staffs Comments at 12
135 ld. at 14.
IDAHO POWER COMPANY'S REPLY COMMENTS - 68
recommending that QFs of all resource types could seek replacement ESAs when the
current contract's term expires, but ldaho Power does not agree that it is appropriate to
include an automatic replacement assumption for wind resources at this time.
The Company's assumptions for wind QFs, specifically that wind QFs will not
renew their ESAs has been in place for several IRP cycles. There are numerous factors
that ldaho Power has considered to form the basis of this assumption, including, but not
limited to, the high cost of repowering wind facilities, reductions and/or elimination of tax
credits applicable to wind projects, current integration costs for wind, and the notable fact
that none of ldaho Powe/s wind QFs have requested or entered into replacement ESAs.
Of the 32 wind QFs delivering generation to ldaho Power, the first ESA is
scheduled to expire in2025. Therefore, no wind QFs have indicated that theywil! request
replacement ESAs, and ldaho Power does not have any history or evidence that wind
QFs will seek replacement ESAs. ln contrast, ldaho Power has entered into more than
35 new replacement ESAs for existing hydro, biomass, and cogeneration QFs that had
been delivering generation to ldaho Power under previous ESAs.
Despite this track record of replacement ESAs, there have been four hydro, two
biomass and two cogeneration QFs under ldaho ESAs that did not seek replacement
contracts for projects that had been in operation and delivered generation to the
Company. ln 2019 and 2020, four more biomass QFs terminated their ESAs with ldaho
Power. All of these facilities had been included in the Company's CSPP forecast and
were assumed to continue delivering their output to ldaho Power pursuant to replacement
ESAs but failed to do so. Therefore, including replacement contracts for any resource
type carries some amount of risk as it relates to planning purposes.
IDAHO POWER COMPANY'S REPLY COMMENTS .69
Considering the aforementioned information and experiences, ldaho Power
continues to believe its assumptions regarding replacement ESAs in the CSPP forecast
are reasonable. The Company understands and recognizes that repowering of wind
facilities occurs in the industry. However, until ldaho Power has evidence to support
intent to or interest in repowering wind QFs, the Company does not consider it appropriate
to assume wind QF replacement ESAs in its CSPP forecast. As wind replacement ESA
information becomes available, Idaho Power is open to revising its assumption for QF
wind replacement ESAs in future lRPs. ln addition, ldaho Power agrees to perform
sensitivity analysis in its next IRP pertaining to wind replacement assumptions to evaluate
the impacts on resource planning.
B. Market Purchases
Staff believes that market purchases in the peak L&RB should not only consider
transmission capacity, but also market availability when determining the level of market
purchases for purposes of establishing the first capacity deficiency date in PURPA
contracts.ls Idaho Power agrees with Staff that market availability alongside
transmission capacity should be looked at when determining capacity deficiencies and
will review these concepts when developing the L&RB to be included in the 2021 lRP.
C. Non-Owned Reserves
Staff explains that non-owned reserves represent capacity sales through an OATT
to wholesale customerc in a utility's BAA forwhich a utility is obligated to provide reserves.
Currently, non-owned reserves are not included in the L&RB for purposes of establishing
the first capacity deficiency date in PURPA contracts. Staff recommends that the
136 Staffs Comments at 15
IDAHO POWER COMPANY'S REPLY COMMENTS - 70
Company include non-owned reserves in the peak L&RB as a decrease of existing
resources because the Company uses its own resources to provide non-owned
reserves.137 ln the 2019 lRP, the Company adopted a 15 percent planning margin,138
which is a common planning practice among utilities. This 15 percent planning margin is
calculated based on a 50th percentile load forecast and is intended to provide the
Company with sufficient margin to meet unforeseen increases in demand (e.g., extreme
weather) and unexpected resource outages. The 15 percent planning margin is also
intended to cover severe outage risks and contingency reserve requirements for ldaho
Power's native load customers and transmission customers.
Staff recommends that the Company factor in contingency reserve requirements
necessary due to transmission customers (the Company believes these contingency
reserves for transmission customers are what Staff was referring to as "non-owned
reserves"). The Company will be evaluating whether to continue to employ the 15 percent
planning in the 2021 lRP, whether to adjust the percentage, or perhaps whether to shift
to a LOLE or Effective Load Carrying Capability ('ELCC") methodotogy. The Company
agrees that contingency reserye requirements necessary as a result of transmission
customers should play a role in the L&RB evaluation.
D. Energy Efficiency
Staff explains that existing EE is currently included in the peak L&RB and, because
utilities are expected to pursue all cost-effective EE measures, it believes all cost-effective
EE measures should be included. Additionally, Staff recommends changing the label
137 ld.
138 SecondAmended 201I IRPal102.
IDAHO POWER COMPANY'S REPLY COMMENTS - 71
from "Existing EE" to "Energy Efficiency" to better define the resource category.13e
ldaho Power's L&RB already includes all cost-effective EE measures, not just
existing EE. !n the future the Company will provide better definitions of resource
categories and will change the labeling per Staffs recommendation.
IX. IDAHO POWER'S CARBON EMISSIONS
ln its comments, STOP B2H claims that Idaho Power is distorting its carbon dioxide
("COz") emissions history while hiding recent large increases in the carbon intensity of
existing gas-fired resources.la0 STOP B2H questions the baseline date for the
Company's voluntary emissions reduction goal and claims that the Company has quietly
embarked on a high-carbon operating strategy for its gas-fired resources as a result of
trading in the Energy lmbalance Market ("ElM'1.ur These claims are quite simply
inconect.
A. Emission Goal Baseline Year
By way of background, in September 2009, IDACORP's and ldaho Power's boards
of directors voluntarily approved guidelines that established a goal to reduce the COz
emissions intensity of ldaho Power's utility operations. The initial goal was to reduce
emissions 10 to 15 percent from 2005 levels.
STOP B2H states that "ldaho Power's choice of calendar year 2005 as the base
year against which progress toward carbon reduction is measured is duplici1eqs.r142
ldaho Power strongly disagrees. On the contrary, the date was selected consistent with
multiple greenhouse gases ("GHG")-reduction frameworks and pieces of legislation.
13e Staffs Comments at 15.
140 STOP B2H Comments at 23.ttt lgl. sll4t.
142 ld. at23.
IDAHO POWER COMPANY'S REPLY COMMENTS. T2
Perhaps the most notable was the American Climate and Energy Security Act of 2009
(more commonly known as the Waxman-Markey Bill), which would have been
implemented nationally and required, among other things, a 17 percent reductionby 2020
from 2005 levels.la3 At the time Waxman-Markey was written, and in subsequent national
and state-level efforts to select a baseline target for GHG reductions, the 2005 date was
selected not arbitrarily but because that year was a generational peak for national GHG
emissions.laa lt was then, and remains, a logical basis by which to set meaningful
emissions reduction targets. Considering the historical context, Idaho Power's initial
emissions reduction goal of 15 percent below 2005 Ievels mirrors other nationally debated
targets.
STOP B2H also states that the biggest indicator of emissions for ldaho Power "is
the amount and shape of the hydro rrno6."145 ldaho Power has always stated that
because ldaho Power's COz emissions intensity fluctuates with stream flows and
production levels of anticipated renewable resource additions, an average intensity
reduction goal to be achieved over several years is appropr1r1s.la6
Finally, it is worth noting that the Company has consistently demonstrated its
commitment to reduce GHG emissions-its voluntary emissions reduction target has
been extended and increased twice since its inception in 2009. And, in March 2019,
ldaho Power publicly set forth a goal to providing its customers with 100 percent clean
energy by 2045.147
143 American Climate and Energy Security Act of 2009, H.R. 2454, 11'tth Cong. S 702 (2009).14 See U.S. ElA, EIA projects total U.S. energy-related CO2 emrssions to be relatively flat through 2050
(Feb. 1 0, 2020) https://www.eia.oov/todavinenerqv/detail.php?id=42775.
145 STOP B2H Comments at 23.
146 IDACORP 2009 Annual Report at 54.
147 ldaho Power'Clean today. Cleaner Tomorrow.@", available at: https://www.idahopower.com/energv-
environ menUenerqv/clean-todav-clea ner-tomorrow/.
IDAHO POWER COMPANY'S REPLY COMMENTS - 73
B. Thermal FIeet Operation and the EIM
Next, STOP B2H claims that ldaho Power has "quietly embarked on a high-carbon
operating strategy for its gas-fired resources," and that "unfettered trading" in the EIM
appears to be the motive.las Specifically, STOP B2H asserts that the 2018 and 2019
operations of Langley Gulch profoundly changed, resulting in "gross inefficiencies" and
an increase in the carbon intensity of the plant.lae STOP B2H claims that the Company
has operated Langley Gulch in this way to maximize EIM participation, under the false
belief that EIM benefits accrue to stockholders while excess fuel costs are paid by
ratepayers.lso Based on these arguments, STOP B2H urges the Commission to
investigate utility abuses in the ElM.151 STOP B2H's conclusions and recommendations
are not supported by the facts.
1. ldaho Power Efficientlv Operates Lanqlev Gulch and lts Broader Thermal Fleet to
Serve Customers While Decreasins Overall Carbon lntensitv.
STOP B2H presents the emissions intensity of Langley Gulch from 2013 to 2019,
calculated with data contained in Idaho Powe/s FERC Form 1 report, to support its claims
that "ldaho Power is quietly embarking on a high-carbon operating strategy," and that
operations of Langley Gulch in 2018 and 2019 resulted in "gross inefficiencies" and an
increase in carbon intensity of the plant.152 Upon further review of STOP B2H's
calculations,ls3 the Company discovered differences between the 2018 and 2019 FERC
148 STOP B2H Comments at 24.
14s ld. at25.
25.
26.
24-25.
1s3 The Company validated that STOP B2H's calculations were performed correctly
IDAHO POWER COMPANY'S REPLY COMMENTS - 74
1go ld. al
151 ld. al
152 ld. at
Form 1 data and actual data collected through the Company's continuous emissions
monitoring system ('CEMS") and detailed gas billing records.lsa
When reporting actual emissions to various state and federal agencies, ldaho
Power uses data from the CEMS, not calculations performed on FERC Form 1 data. ln
review of the FERC Form 1 data points for Langley Gulch in 2018 and 2019, the Company
identified an error in the Quantity (Units) of Fuel Burned,lss a value used in STOP B2H's
analysis. The values for Langley Gulch in 2018 and 2019 were inadvertently overstated
because of manual-entry enor for the two months of August 2018 and July 2019 in the
FERC Form 1.
ldaho Power appreciates STOP B2H's carefulattention to the Langley Gulch plant
data, which allowed ldaho Power to discover this unintentional reporting error. As a result
of this error, the Companyfiled corrected FERC Form 1 pages on January 29,2021.
However, this minor manual-entry discrepancy is a far cry from validating STOP B2H's
faulty claim that ldaho Power has embarked on a "high-carbon operating strategy."156
There simply is no data or evidence to support such a claim.
The table below, shows reported emissions for Langley Gulch for 2013 to 2019
and the carbon intensity measured in lbs/MWh. 157 As can be seen from the data, the
plant's emissions in 2018 and 2019 are more, or less in line with the 2013 to 2017
timeframe, with variation from year-to-year driven by underlying factors such as customer
demand and weather.
ts+ The Company was able to validate that the emissions intensity calculated for the years2013-2017 using
FERC Form 1 data was reasonable and verified the CEMS values for 2018 and 2019 match the independent
detailed billing records within 1 percent.
15s Line 38 of page 402.1 of ldaho Power's FERC Form 1.
156 STOP B2H Comments at 24.157 Emissions data are publicly available on the EPA FLIGHT website at
httos://qhqdata.eoa.qov/qhoo/main.do.
IDAHO POWER COMPANY'S REPLY COMMENTS - 75
Table 6: Langley Gulch Emissions 2013-2019
Langley
Gulch 2013 2014 2015 2016 2017 2018 2019
Net Gen
(MWh)
CO2e
(met.tons)r58
CO2e (lbs)
Carbon
Moreover, the Company believes a better reflection of its operating strategy around
carbon emissions would be to examine all ldaho Power-owned thermal generation over
this same timeframe (2013-2019). From 2013 to 2019, generation from thermal
resources has declined and total COz emissions from those resources decreased by
almost 50 percent, as shown in the figure 10 below. This data clearly demonstrates that
the Company is not operating its thermal resources irresponsibly, contrary to STOP B2H's
claims.
158 EPA, Langley Gulch Power
https://ohqdata.eoa.qov/qhoo/service/facilitvDetail/2019?id=1007379&ds=E&et=&poouo=true.
1 ,131,020
423,711
934,121,745
826
1,501 ,436
563,878
t,243,136,716
828
1,295,859
483,257
1,065,398,047
822
1,049,182
389,632
858,990,500
819
1,662,770
619,276
1,365,268,255
821
1,420,178
1,185,779,',t18
537,861
835
1,350,692
505,743
,'t14,971,133
825
IDAHO POWER COMPANY'S REPLY COMMENTS - 76
Plant,
Figure 10: Emission Intensity of Idaho Power's Thermal Generation 2013-2019
(Jim Bridger, valmy, Boardman, Langley Gulch, Danskin, and Bennett Mountain
power plants)
Net Generation and COre Emissions of
ldaho Power-Owned Thermal Generation Resources
lt
(l,
No(J
16,000,000,000
14,000,000,000
12,000,000,000
10,000,000,000
8,000,000,000
6,000,000,000
4,000,000,000
2,000,000,000
0 I
20L9
9,000,000
8,000,000
7,000,000
6,000,000
5,000,000
4,000,000
3,000,000
2,000,000
1,000,000
0
E
=
c
.9
(!
(Uco(9
oz
2013 2014 2015 20L6 20L7 2018
Reporting Year
r CO2e (lbs)
-Net
Generation (MWh)
2. ldaho Power's EIM Participation Benefits Customers.
STOP B2H claims that ldaho Power's dispatch of Langley Gulch has allowed the
Company's shareholders to accrue EIM benefits, while excess fuel costs are paid by
customers.lse While ldaho Power acknowledges that participation in the EIM has an
impact on the dispatch of Langley Gulch, STOP B2H is incorrect that the benefits of EIM
participation accrue to shareholders instead of customers. The quantification of total
estimated EIM benefits is the cost savings of the EIM dispatch compared to the
counterfactual without EIM dispatch. Contrary to STOP B2H's claim, benefits of
participation in the EIM are not retained by shareholders.loo Rather, both the costs and
benefits flow back to customers and are realized as reduced net power supply expenses
("NPSE") reviewed by the Commission annually in the Company's power cost filing.
15e STOP B2H Comments at 25.
160 ld. at25.
IDAHO POWER COMPANY'S REPLY COMMENTS - 77
To better understand how the EIM has impacted Langley Gulch dispatch, it is
helpful to understand generally how the EIM works. The following is a basic summary of
the way in which resources are scheduled into the ElM. First, ldaho Power creates a load
forecast for the next clock hour. Second, the Company creates a generation plan to serve
the forecasted load. Third, the costs for all Idaho Power generation resources are
calculated. Fourth, these plans are submitted to the EIM for review and are required to
pass all necessary checks. Finally, the EIM reviews all plans submitted by all participants
and adjusts the dispatches of participating generation resources to minimize the total
generation cost needed to serve the actual load of the participants.
Langley Gulch is a participating EIM resource and can be moved up or moved
down from the planned dispatch by the ElM. The Langley Gulch plant may be instructed
to move down from planned dispatch by the EIM under the following conditions: (1) the
EIM found generation available at another participating resource thatwas less expensive;
(2) the Company's actual load was lower than projected; (3) ldaho Power's other
resources (i.e., wind and solar) generated more power than was projected; or (4) any
combination of the above. lf Langley is instructed to move upfor planned dispatch, then
(1) the EIM has found a participant that could utilize the remaining generation capacity;
(2) the Company's actual load was higher than expected; (3) ldaho Power's other
generation (wind, hydro) was lower than expected; or (4) any combination of the above.
The EIM makes economic dispatch decisions for each of the market's participants and
will not instruct resources to move unless it will result in cost savings. After the fact, each
market participant pays other market participants for the power it received as a result of
the EIM's dispatch instructions and subsequent changes.
IDAHO POWER COMPANY'S REPLY COMMENTS - 78
Thus, while operation of Langley Gulch has changed over time as ldaho Power
continues its path away from baseload coal-fired generation and through participation in
the ElM, the Company has continued to responsibly and efficiently operate its system in
the best interest of its customers.
For the reasons stated above, STOP B2H's claim that the Commission should
investigate abuses in the EIM is unfounded. The Company's NPSE are reviewed in detail
annually by both the ldaho and Oregon commissions.
X. REQUEST FOR EXTENSION TO FILE 2021IRP
As the collective review of the Second Amended 2019 IRP comes to conclusion,
ldaho Power reiterates its appreciation of the Commission's and parties' patience in this
docket. Although this extended process has taken more time and resources than
anticipated, Idaho Power is confident that this investment has resulted in an accurate and
more techn ical ly soph isticated resou rce plan.
Even as it seeks the Commission's acknowledgment of its Second Amended 2019
/RP, the Company has begun meeting with resource planning stakeholders to develop its
2021 IRP and intends to file it with the Commission by year end. To allow the Company
to continue seeking stakeholder input and yet maintain the timing of a biennial resource
plan, ldaho Power requests the Commission extend the requirement for Idaho Power to
file its 2021 IRP from the "last business day of June" in odd-numbered years set in Order
No. 30317161 1o the end of calendar year 2021.
ln advance of the 2021 IRP , the Company is conducting an economic and reliability
analysis to determine the optimal exit date from Valmy Unit 2. This study will be complete
161 In the Matter of ldaho Power Company's 2006 lntegrated Resource Plan, Case No. IPC-E-06-24, Order
No. 3031 7 at 2 (May 23,2007).
IDAHO POWER COMPANY'S REPLY COMMENTS - 79
in the first half of 2021. Given the imminence of this exit decision, ldaho Power also will
provide the results of such analyses and, if warranted, any associated rate-making
recommendations to the Commission in a separate stand-alone docket prior to filing the
2021 IRP later this year.
xl. coNcLUSloN
Based on the detailed and comprehensive analysis set forth in the Second
Amended 2019 lRP,ldaho Power has demonstrated that its preferred portfolio, which
includes the B2H transmission line as a Ieast-cost, Ieast-risk resouroe, meets the
resource need identified in this lRP. ldaho Power respectfully requests the Commission
accept and/or acknowledge the Company's SecondAmended 2019lRP as meeting both
the procedura! and substantive requirements of Order Nos. 22299,25260, and 30317,
and grant ldaho Power an extension of time to file its 2021 IRP until the end of calendar
year 2021.
DATED at Boise, ldaho, this 1Oth day of February 2021.
dL!-(',1-t"-*,
LISA D. NORDSTROM
Attorney for ldaho Power Company
IDAHO POWER COMPANY'S REPLY COMMENTS - 80
cERT|FICATE OF SERVTCE (rpc-E-l 9-1 9)
I HEREBY CERTIFY that on this 1Oth day of February 2021,1 served a true and
correct copy of IDAHO POWER COMPANY'S REPLY COMMENTS upon the following
named parties by the method indicated below, and addressed to the following:
Commission Staff
Edward Jewell
Deputy Attomey General
ldaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg No. 8,
Suite 201-A (83714)
PO Box 83720
Boise, lD 83720-0074
ldaHydro
C. Tom Arkoosh
ARKOOSH LAW OFFICES
802 W. Bannock Street, Suite LP 103
PO Box 2900
Boise, lD 83701
ldaho Gonservation League
Benjamin J. Otto
ldaho Conservation League
710 N.6th Street
Boise, lD 83702
STOP B2H Coalition
Jack Van Valkenburgh
Van Valkenburg Law, PLLC
PO Box 531
Boise, lD 83701
Jim Kreider
STOP B2H Coalition
60366 Marvin Road
La Grande, OR 97850
ldaho Sierra Glub
Julian Aris, Associate Attorney
Gloria D. Smith
ldaho Sierra Club
2101 Webster Street, Suite 1300
Oakland, CA 94612
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IDAHO POWER COMPANY'S REPLY COMMENTS - 81
lndustrial Customers of ldaho Power
Peter J. Richardson
Richardson, Adams, PLLC
515 N. 27th Street
P.O. Box 7218
Boise, lD 83702
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Dr. Don Reading
6070 Hill Road
Boise, lD 83703
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Micron Technology, lnc.
Austin Rueschhoff
Thorvald A. Nelson
Holland & Hart, LLP
555 17h Street Suite 3200
Denver, CO 80202
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aclee@ holland hart.com
o loa rqa noa ma ri@ hol la nd ha rt. co m
Jim Swier
Micron Technology, lnc.
8000 South Federal Way
Boise, lD 83707
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Stephanie L. Buckner
Executive Assistant
IDAHO POWER COMPANY'S REPLY COMMENTS - 82