20260403NIPPC Comments.pdf

RECEIVED
Gregory M. Adams (ISB No. 7454) APRIL 3, 2026
Richardson Adams, PLLC IDAHO PUBLIC
UTILITIES COMMISSION
515 N. 27th Street
Boise, Idaho 83702
Telephone: [phone]
Fax: [phone]
[e-mail]
Irion Sanger(ISB No. 12488)
Sanger Greene, PC
4031 SE Hawthorne Blvd.
Portland, OR 97214
Telephone: [phone]
Fax: [phone]
[e-mail]
Attorneys for Northwest & Intermountain Power Producers Coalition
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER ) CASE NO. IPC-E-26-03
COMPANY'S APPLICATION FOR )
APPROVAL OF THE 2032 ALL- SOURCE ) NORTHWEST & INTERMOUNTAIN
REQUEST FOR PROPOSALS TO ) POWER PRODUCERS COALITION'S
MEET CAPACITY RESOURCE NEEDS IN ) COMMENTS
AS EARLY AS 2031. )

TABLE OF CONTENTS
I. INTRODUCTION AND SUMMARY............................................................................... 1
II. COMMENTS...................................................................................................................... 3
A. General Concerns: Idaho Power's RFP Application Presents Circumstances that Are
Materially Different from Expectations During Development of the IPUC's RFP Rules
and Calls Into Question Whether those Rules Contain Sufficient Detail to Reasonably
EnsureUnbiased RFPs.................................................................................................... 3
B. Imputed Debt: The Commission Should Require Idaho Power to Remove the Proposed
Imputed Debt Bid Adder for Independently Owned Resource Bids............................... 6
C. Independent Evaluator: The Commission Should Require Retention of an Independent
Evaluator Employed by the Commission...................................................................... 12
D. Price/Non-Price Scoring Allocation: The Commission Should Require Use of the Same
Price/Non-Price Points Weighting for Bids as Idaho Power's Last RFP75%
Price/25%Non-Price..................................................................................................... 16
E. Benchmark Bids: The Commission Should Require that Benchmark Bids Be Submitted
and Scored Prior to the Third-Party Bids...................................................................... 18
F. Capturing the Benefits of Expiring Tax Credits: Idaho Power's RFP Should Accept,
and Clarify the Treatment of, Bids for Wind and Solar Projects that Must Be Placed in
Service by the End of 2030 for Purposes of Qualifying for Expiring Tax Credits....... 19
G. Technology-Based Bid Ranking: The Commission Should Require Idaho Power to
Rank Bids Without Regard to Resource Type for Purposes of Developing the RFP's
Shortlist. ........................................................................................................................ 21
III. CONCLUSION................................................................................................................. 22

I. INTRODUCTION AND SUMMARY
The Northwest& Intermountain Power Producers Coalition("NIPPC")hereby submits its
comments to the Idaho Public Utilities Commission("IPUC"or"Commission")in this proceeding.
NIPPC is a trade association whose members and associate members include independent
power producers ("IPPs") active in the Pacific Northwest and Western energy markets. NIPPC
represents the interests of its members in developing rules and policies that help achieve a
competitive electric power supply market in the Pacific Northwest. Accordingly, NIPPC has
participated in numerous regulatory proceedings related to requests for proposals ("RFPs"),
bidding rules, and competitive markets. NIPPC appreciates the opportunity to comment on Idaho
Power's Application for Approval of its 2032 RFP.
This proceeding involves the first RFP application to be reviewed under the Commission's
recently adopted Procedure for Soliciting Large Supply-Side Resources (hereafter "IPUC's RFP
Rules").' However, Idaho Power's Application is concerning to NIPPC because,unlike its recent
past RFPs and the expectation of NIPPC at the time the IPUC's RFP Rules were adopted just three
months ago, Idaho Power proposes not to seek approval of the proposed RFP from the Public
Utility Commission of Oregon ("OPUC") or to comply with several key requirements of the
OPUC's RFP rules. Idaho Power's proposal is inconsistent with NIPPC's understanding that the
IPUC's RFP Rules were designed and intended to be applied concurrently with more detailed RFP
rules that already applied to each Idaho utility through neighboring states' regulation. As
explained further below, Idaho Power's apparent intent to sidestep the OPUC's RFP rules is cause
' In the Matter of Commission Staffs Application for Approval of an Oversight Process for the
Acquisition of Large Supply-Side Electrical Resources, Case No. GNR-E-25-01, Order No. 36898 (Jan. 2,
2026).
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IPC-E-26-03 —PAGE 1

for added scrutiny by the IPUC to ensure that the RFP is unbiased towards all bids and results in
the lowest cost, lowest risk resource acquisition.
Although Idaho Power asserts in its Application that its proposed RFP is consistent with
its recent past RFPs approved by the OPUC and found by this Commission to be reasonable,
NIPPC has identified very significant modifications from Idaho Power's 2026 RFP and 2028 RFP
that render the proposed 2032 RFP unreasonable and biased in favor of utility-owned resources.
For the reasons explained in more detail below, NIPPC recommends the IPUC require the
following modifications to Idaho Power's proposed RFP:
• Imputed Debt: The Commission should require Idaho Power to remove the proposed
imputed debt bid adder for independently owned resource bids, which would strongly
bias the RFP in favor of utility-owned resources and was previously criticized by IPUC
Staff and rejected as unreasonably biased by the OPUC upon review of Idaho Power's
past RFPs.
• Independent Evaluator: The Commission should require retention of an Independent
Evaluator employed by the Commission.
• Price/Non-Price Scoring Allocation: The Commission should revise Idaho Power's
proposal to use a non-transparent weighting of price and non-price factors in the
evaluation of bids by requiring use of the same points allocation as Idaho Power's last
RFP75%price/25% non-price.
• Benchmark Bids: The Commission should require that benchmark bids be submitted
and scored prior to the third-party bids.
• Capturing the Benefits of Expiring Tax Credits: Idaho Power's RFP should accept, and
clarify the treatment of, bids for wind and solar projects that must be placed in service
by the end of 2030 for purposes of qualifying for expiring tax credits.
• Technology-Based Bid Ranking: Idaho Power should rank bids without regard to
resource type for purposes of developing the RFP's shortlist to prevent arbitrarily
favoring resources types with a limited number of bids.
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IPC-E-26-03 —PAGE 2

II. COMMENTS
A. General Concerns: Idaho Power's RFP Application Presents Circumstances that Are
Materially Different from Expectations During Development of the IPUC's RFP
Rules and Calls Into Question Whether those Rules Contain Sufficient Detail to
Reasonably Ensure Unbiased RFPs.
At the outset, NIPPC reminds the Commission of the need for regulatory scrutiny of an
investor-owned utility's RFP to ensure that the RFP is fair and results in acquisition of the lowest
cost, lowest risk resource for ratepayers. As explained below, Idaho Power's Application puts the
Commission in the difficult position of acting on an extremely expedited basis to resolve
complicated issues that were left unresolved in the proceeding to develop the IPUC's RFP Rules
due to the expectation that the IPUC could leverage the benefits of the key requirements of
neighboring states' RFP rules that would still apply.
A key consideration in reviewing an RFP administered by an investor-owned electric utility
is that the utility has an inherent incentive to design the solicitation in a manner that favors utility
ownership of the generation resources. That is, investor-owned utilities are inherently conflicted
in the resource procurement process to select between a utility-owned option and an independently
owned option offered under a power purchase agreement, battery storage agreement, or similar
tolling agreement (collectively referred to as power purchase agreements or"PPAs"). The utility
will have an inherent incentive to bias the analysis or outcome of resource procurement in favor
of a utility-owned resource because of the utility's statutory right to have an opportunity to recover
its costs and earn a profit on its own capital investments, including generation facilities. Indeed,
the fiduciary duty of an investor-owned utility to its shareholders requires it to maximize return on
investment—which under traditional ratemaking is done by expanding rate base with new utility-
owned assets. In contrast, utilities only have an opportunity to recover their costs (but generally
no returns on investment) when they purchase power from IPPs in PPAs. Thus, due to standard
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IPC-E-26-03 —PAGE 3

ratemaking treatment, the utility has an inherent, economic incentive to favor a utility-owned
resource in a solicitation for a major generation resource.
On the other hand, ratepayers are harmed if resource procurement processes are not
transparent, fair, and competitive, and if utility-owned resources dominate as a result. The
logically expected outcome—absent persistent regulatory oversight—is that the utility is likely to
select its own generation resource over a lower cost,more reliable,and less risky PPA with an IPP.
Over time, a pattern of uncompetitive resource procurement can deter IPPs from investing time
and money to develop new projects and prepare bids to be submitted in RFPs. Thus, as this
Commission recently acknowledged, it is important to promote "robust RFPs" with market
competition.2 Doing so helps protect against utility-ownership favoritism to ensure that customers'
rates are kept low through the acquisition of generation resources with the least cost and risk.
Otherwise, ratepayers will ultimately pay more and assume more risks than they would with
genuine competition and diverse resource ownership.
In NIPPC's experience, strong competitive bidding requirements and oversight can
dramatically improve the odds of mitigating the risk of utility-ownership bias to enable acquisition
of the least-cost, least-risk resource. NIPPC noted that Idaho Power's adherence to the OPUC's
2 See In the Matter of Idaho Power Company's Application for a Certificate of Public Convenience
and Necessity to Acquire Resources to Be Online by 2023 to Secure Adequacy and Reliable Service to Its
Customers, Case No.IPC-E-22-13,Order No.35643,at 13-14(Dec.27,2022)("The Company's customers
should not bear the financial consequences incurred when Idaho Power fails to adequately plan for its
capacity deficiency and in turn acts reactively, forcing it to add resources that the Commission is unsure
are actually the least-cost resource because a robust RFP was not undertaken. We expect that in the future
the Company will better assess the capacity needs of its system and plan far enough ahead to ensure a
robust, competitive bidding process."); In the Matter of Idaho Power Company's Application for a
Certificate of Public Convenience and Necessity to Acquire Resources to be Online in Both 2024 and 2025
and for Approval of and Energy Storage Agreement with Kuna BESS LLC, Case No. IPC-E-23-20, Order
No. 36011, at 6 (Nov. 27, 2023) (emphasizing "the importance of selecting the least-cost, least-risk
resources to meet the Company's capacity needs, and the importance of conducting and maintaining
thorough and competitive RFPs regardless of the Company's shifting capacity needs").
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rules in its 2026 and 2028 RFPs had resulted in key improvements over its prior unreviewed and
unapproved RFPs and allowed for much more robust and fair procurement process.3 However, as
NIPPC explained in Docket No. GNR-E-25-01, the IPUC's RFP Rules are not sufficiently
detailed, on their own, to ensure a competitive outcome in utility procurements. NIPPC's
comments explained: "While the expressed intent of Staff s [proposed rules] is sound, the lack of
detail could leave parties litigating complex and controversial points on a case-by-case basis before
the Commission if other states' more detailed procurement requirements were not also being
applied to the utility by other states."4
Notably, Staff s proposal in Case No. GNR-E-25-01 expressly recognized that neighboring
states have detailed requirements that provide benefits to ratepayers and sought to "leverage"the
benefits of rules that will be applied by neighboring states without duplicating such processes.5
Thus, in light of Staff s agreement that other states' applicable procedures would still apply to the
Idaho utilities' RFPs, NIPPC agreed that it was not necessary to duplicate detailed rules and
procedures in Idaho that were reasonably expected to already be applied in other states for each of
the Idaho utilities.6
However,just three months after the Commission's order in Case No.GNR-E-25-01,Idaho
Power has proposed to sell its Oregon service territory and acquire a major new generation
resource through a solicitation that would not comply with the detailed OPUC RFP requirements
3 NIPPC's Comments, Case No. GNR-E-25-01, at 11 (July 24, 2025) (citing In the Matter of Idaho
Power Co., Application for Approval of 2026 All-Source Request for Proposals to Meet 2026 Capacity
Resource Need, OPUC Docket No. UM 2255, Order No. 23-260, at 2-9(July 17,2023)).
4 Id. at 8-9.
5 See Direct Testimony of Matthew E. Suess, Staff,Case No. GNR-E-25-01,at 13 (March 31,2025)
(proposing that because "other states will already require an IE in a Utility's RFP process. . . . Idaho can
leverage that IE's oversight"); see also id. (proposing flexibility on procedural timelines will enable the
process to"conform to other state's processes").
6 NIPPC's Comments, Case No. GNR-E-25-01, at 12 (July 24,2025).
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that were expected to complement the IPUC's RFP Rules. Further,Idaho Power proposes approval
of the RFP on an expedited basis,which provides stakeholders and the Commission very little time
to scrutinize Idaho Power's proposed RFP, fully adjudicate disputed points of fact and policy, and
make comprehensive changes—presenting the precise problem NIPPC posited would occur with
a lack of detailed RFP requirements. Idaho Power asserts that this RFP is substantively the same
as its prior RFPs approved by the OPUC and found to be reasonable by this Commission. But as
explained below, this proposed RFP has key differences that render it biased in favor of a utility-
owned resource and that consequently will not afford ratepayers the benefits of a truly competitive
solicitation. Accordingly, the Commission should carefully scrutinize the RFP and make the
limited,but important, modifications to the RFP recommended in the sections that follow.
B. Imputed Debt: The Commission Should Require Idaho Power to Remove the
Proposed Imputed Debt Bid Adder for Independently Owned Resource Bids.
Idaho Power proposes to resurrect a previously rejected imputed debt bid adder for bids for
independently owned generation resources that would strongly bias this RFP in favor of utility-
owned resources. The impact of the imputed debt bid adder could be expected to increase affected
bids' costs by approximately 200/o—all but ensuring utility-owned resources will prevail in this
RFP. As explained below and detailed at length the in the attached expert report from Michael P.
Gorman, Idaho Power's proposed use of imputed is a one-sided and arbitrary feature of the
proposed RFP, and it was previously criticized by the IPUC Staff and rejected by the OPUC. The
Commission should require removal of the imputed debt bid adder.
See Direct Testimony of Eric Hackett,Idaho Power, Case No. IPC-E-26-03, at 12 (Feb. 20,2026)
("The Company's proposed bid evaluation process is consistent with the selection process utilized in prior
RFP's, the most recent of which, the 2028 RFP, Commission Staff indicated they believed was a fair and
reasonable process.").
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Although Idaho Power makes no effort justify this feature of its proposed RFP in its
Application or its supporting testimony, the RFP document includes the following new statement
not included in Idaho Power's approved 2028 RFP or its 2026 RFP:
Contract structures in which IPC is not the owner of the project bring added costs beyond
the direct contract costs in the form of imputed debt. IPC will estimate the additional cost
of imputed debt for each third-parry owned asset and add this cost to the overall cost of a
project.'
No further justification for this proposed feature of the RFP is included with Idaho Power's
Application. However, Idaho Power confirmed in discovery that it proposes to use the same
general imputed debt methodology used in its unreviewed and unapproved 2022 RFP, which
resulted in a median bid adder of 18% to bids for independently owned generation resources in
that RFP, but which was later rejected for use in Idaho Power's 2026 and 2028 RFPs by the
OPUC.9 Idaho Power claims the imputed debt bid adder is necessary because ratings agencies
may impute debt to its balance sheet for successful PPA bids, potentially impacting its credit
ratings and ultimately imposing financial costs on the utility.10 However, Idaho Power proposes
no similar adjustment that comprehensively adjusts for the unique risk factors related to financing
and operating utility-owned generation resources.
This element of the RFP is inconsistent with the IPUC's RFP Rules' policy of equal and
fair treatment of all bid types in an RFP because it penalizes IPPs and not utility-owned projects
for the same speculative issue." NIPPC is aware of no direct precedent on treatment of debt
8 See Attachment 1,Comparison of Idaho Power's 2028 RFP to Idaho Power's Proposed 2032 RFP,
at 28.
9 See Attachment 2,Idaho Power's Imputed Debt Discovery Responses.
10 See Attachment 2,Idaho Power's Imputed Debt Discovery Responses(Idaho Power's Response to
IPUC Staff s Production Request No. 10).
11 See In the Matter of Commission Staff's Application for Approval of an Oversight Process for the
Acquisition of Large Supply-Side Electrical Resources, Case No. GNR-E-25-01, Order No. 36898,
Attachment A at 1 (Jan. 2, 2026) (stating that the "selection process should avoid bias", "should ensure
competition,transparency,confidentiality,and fairness through all stages of the procurement process",and
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IPC-E-26-03 —PAGE 7

imputation in an IPUC order,but the IPUC Staff has criticized Idaho Power's assertions regarding
imputed debt as justification for exclusion of third-party bids from an REP in the recent past.12
Although Idaho Power does not propose to bar third-party owned bids in this RFP, the likely
magnitude of its proposed imputed debt bid adder methodology—a 20% adder on top of the bid's
actual price—could have the same practical effect as excluding all third-party owned bids.
Further,there is ample precedent elsewhere compelling a conclusion that imputed debt bid
adders are unreasonable and bias an RFP in favor of utility ownership. The OPUC has consistently
disallowed the use of imputed debt.13 Indeed, as Idaho Power acknowledges,the OPUC reviewed
this very same proposed imputed debt bid adder when it was proposed for Idaho Power's 2026
RFP, and the OPUC rejected the adder as biased against third-party ownership of generation
resources.14 The OPUC's order identifies a number of reasons to reject use of the imputed debt
bid adder identified by its Staff, including: "the imputed debt adder could add up to 20 percent of
"should be designed to ensure . . . processes are open, competitive and accessible to all qualified
suppliers/contractors avoiding favoritism or discriminatory practices").
12 See In the Matter of Idaho Power Company's Application for a Certificate of Public Convenience
and Necessity to Acquire Resources to Be Online by 2023 to Secure Adequacy and Reliable Service to Its
Customers,Case No.IPC-E-22-13,Order No.35643,at 6-7(Dec.27,2022)(explaining that Staff criticized
Idaho Power's reliance on imputed debt risks as justification for limiting battery project bids to utility
ownership in its RFP, and commented that"while it may be true that the cost of debt would increase, such
increase would be minimal and, even if it resulted in a downgrade to the Company's credit rating, this
downgrade would only increase the interest rate by 0.14%. Staff further noted that any impact on interest
rates would only affect new debt issuances and if the Company were to issue all debt that has been currently
approved by the Commission,a 13%increase in interest rates would have an approximate 0.021%increase
in the Company's overall rate of return."(internal quotation omitted)).
13 See In the Matter of Portland Gen. Elec. Co. 's Request for Proposals for Capacity Resources,
OPUC Docket No.UM 1535,Order No. 11-371,at 7(Sept.27,2011)(rejecting Portland General Electric's
proposed use of imputed debt in an RFP);In the Matter of the Pub. Util. Comm'n of Ore.;An Investigation
Regarding Performance-Based Ratemaking Mechanisms to Address Potential Build-vs.-Buy Bias, OPUC
Docket No. UM 1276, Order No. 11-001, at 6 (Jan. 3, 2011) (stating: "we allow the utilities to raise the
impact on this practice on credit ratings and earnings in individual rate proceedings. We believe that this
issue is more appropriately addressed in the context of an overall examination of a utility's cost of capital").
14 In the Matter of Idaho Power Co., Application for Approval of 2026 All-Source Request for
Proposals to Meet 2026 Capacity Resource Need, OPUC Docket No. UM 2255, Order No. 23-260, at 5-6
&App.A at 8-11 (July 17,2023).
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a bid's total price" and thus "could disadvantage third-party bids by adding significant cost
compared to company resources"; it"would be based on company financial models that would not
be easily accessible, thus resulting in a less transparent and less competitive RFP process"; and
"assessing these types of calculations and review of the documentation involved in assessing an
imputed debt adder would be better suited to a rate case."15 In agreeing with its Staff and NIPPC,
the OPUC explained:
We do not find that Idaho Power's methodology is an appropriate adder to the costs of
PPAs. Among other things,we are concerned about how its proposed methodology fails to
take into account the other impacts on the agency's credit ratings from non-PPA resources
and are not convinced that it appropriately estimates how the impact of PPAs would
actually flow through to customers.16
In the OPUC proceeding, NIPPC submitted a report by a qualified expert, Michael P.
Gorman of Brubaker and Associates, Inc., in response to Idaho Power's proposed imputed debt
bid adder, which provided significant additional evaluation of the flaws with Idaho Power's
proposal. Because Idaho Power makes the same imputed debt bid adder proposal in this case,
NIPPC has attached the same report to these comments.17 As Mr. Gorman's report explains, Idaho
Power's imputed debt methodology relies on speculation as to whether any actual costs associated
with a PPA would flow through to ratepayers and completely overlooks the similar costs that are
likely imposed by a utility-owned resource. Indeed, any procurement of a large-scale generation
resource, including a utility-owned resource, is likely to have some impact on the utility's debt,
balance sheet, financial position, and ultimately its credit rating in the eyes of a ratings agency.
15 Id. at 5.
16 Id. at 6.
17 See Attachment 3,Expert Report on PPA Imputed Debt of Michael P.Gorman,OPUC Docket No.
UM 2255 (May 9,2023).
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Mr. Gorman's key findings included the following points regarding the risks of utility-
owned resources that are completely ignored in Idaho Power's one-sided imputed debt bid adder:
Idaho Power's proposal to include a PPA leverage cost adjustment to fully account
for the cost of PPAs is not balanced by making similar financial leverage cost adjustments
to reflect additional leverage costs associated with utility-owned resources.
Utility-owned resources have investment and operating risks that are greater than
those inherent in a PPA,in which case the third parry assumes the investment and operating
risks. For example,a PPA has far less financial risk to the utility compared to utility-owned
facilities for the following reasons:
1. A PPA poses little or no cash flow constraints on the utility while the resource is
initially being developed. Indeed, Idaho Power acknowledges that under a PPA, it
typically would not pay for the capacity and energy from the unit until the unit is
actually able to provide capacity and energy to Idaho Power.
2. For a utility self-build project, the utility can go through a period of cash
deficiency in the resource development stage if, prior to the unit being placed in
service and providing service to customers,the resource cost is not included in tariff
rates. This cash stress period during development can also impact the utility's
financial leverage and generally could result in the utility increasing the equity ratio
of its ratemaking capital structure to accommodate the weak cash flow experienced
during the development of a utility-owned resource. The utility cash flow would
not be stressed during the development of a PPA resource.
3. The PPA exposes the utility to less asset risk than a utility-owned facility.
Specifically,if a PPA failed to operate sufficiently and did not provide capacity and
energy, then the utility may not be obligated to pay capacity and energy payments
to a third-parry supplier under the PPA. In some instances, Idaho Power
acknowledges that the third-party supplier may be liable to Idaho Power for
replacement capacity and energy costs if it failed to perform under the PPA. Also,
to the extent there is significant prolonged damage to the resources underlying a
PPA, Idaho Power may be able to declare the third-party supplier to be in default
and can cancel its financial obligations under a PPA. The utility may be largely
protected from resource failure under a PPA but not under utility ownership.
4.Under a utility-ownership scenario,the utility has full asset risk for the generating
resource, and will still be obligated to make debt service payments for the funding
used to develop or acquire the utility-owned resource even if it has a catastrophic
event which removes the resource from public service and precludes full recovery
of the utility's costs and outstanding debt from ratepayers.
These resource asset development and operating risks would be considered by
credit rating agencies in developing the overall leverage risk and financial risk of Idaho
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Power in a credit rating review. These risks are unique to utility-owned resources, which
Idaho Power would need to manage in balancing a capital structure to maintain its financial
integrity and investment grade credit standing. These are all financial costs associated with
utility-owned resources which would not be risks or costs incurred under a PPA. Ignoring
these utility-owned financial costs to manage development and operating risks as an offset
to the PPA debt equivalent renders Idaho Power's proposed cost comparison of the various
resources inexact, imbalanced, and biased against PPA bids in the RFP.18
Mr. Gorman concluded that added financial costs for PPAs and utility-owned resources, if
accurately measured for all resource options, would be offsetting, and "it is fair and accurate to
simply not reflect these external,unknown financial costs in the comparison of resource options."19
In other words,Idaho Power's proposal is biased and one-sided by focusing solely on a speculative
cost that may, or may not, arise related to any given PPA while ignoring the corresponding cost
associated with utility-owned resources, and the more reasonable approach is not to include these
types of speculative and non-transparent financial costs in the RFP evaluation.
Notably, the Independent Evaluator in the 2026 RFP, London Economics, also concluded
that Idaho Power's imputed debt bid adder was unjustified and should be rejected.20 The
Independent Evaluator made similar points to Mr. Gorman's report, emphasizing the need to
"perform a holistic examination of all the risk (and risk-mitigating) factors of PPAs versus those
of utility-built and utility-owned options."21 Like Mr. Gorman, the Independent Evaluator also
pointed out that the risk of debt imputation by a ratings agency is greatly reduced in jurisdictions
where the utility has a high likelihood of rate recovery for its payments for energy and capacity
supplied by the PPA seller, which Idaho Power clearly has in both of its jurisdictions through its
18 Id. at 10-11 (footnotes omitted).
19 Id. at 1.
20 London Economics International's Independent Evaluator Report,OPUC Docket No.UM 2255, at
14-15 (March 2,2023).
21 Id. at 15.
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annual power cost recovery proceedings.22 This further underscores the speculative risk as to the
imputed debt cost as compared to the similar costs of a utility-owned resource, which also clearly
impose financing costs, including actual (not just imputed) debt, as well as significant additional
ongoing operational risks.23
In sum, Idaho Power's proposed imputed debt bid adder would strongly bias the RFP in
favor of utility-owned resources without any justification, and the Commission should therefore
require removal of the imputed debt bid adder from Idaho Power's proposed RFP.
C. Independent Evaluator: The Commission Should Require Retention of an
Independent Evaluator Employed by the Commission.
NIPPC recommends that the Commission require use of the same Independent Evaluator
(or "IE") as was used in Idaho Power's last two RFPs, London Economics, and that the
Independent Evaluator be contracted by, and report directly to, the Commission. An Independent
Evaluator is a key feature of an RFP where, as here, bids for utility-owned resources are allowed
in the solicitation, and it is appropriate here to ensure fair treatment for third-party bids.
In developing the IPUC's RFP Rules, Staff did not propose requiring use of an Independent
Evaluator based on its assumption that one would normally be required by neighboring states.
Staff explained, "[i]n most cases, other states will already require an IE, so Idaho can leverage that
IE's oversight. In the rare case that another state does not require an IE, and Idaho deems one
22 See id. at 15 (explaining,"S&P also multiplies the financial results by a risk factor that is inversely
related to the strength and availability of regulatory mechanisms used for the recovery of PPA costs.").
23 See, e.g., In the Matter of Idaho Power Co. 's Application for a Certificate of Public Convenience
and Necessity for the Bennett Gas Expansion Project and for an Associated Accounting Order, Case No.
IPC-E-25-29, Order No. 36958, at 2 (March 10, 2026) (explaining that "the Company represented that it
intended to finance the Project through a combination of available cash,operating cash flow,existing credit
facilities, new borrowings and debt issuances, and future equity contributions from its parent company,
IDACORP"(emphasis added)).
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necessary,the Commission can prescribe one as part of its RFP review."24 The final rules state that
"the Commission may require an Independent Evaluator to participate in the subsequent RFP
selection process."25 Thus, the Commission expressly contemplated requiring use of an
Independent Evaluator in appropriate cases, such as this case, where no Independent Evaluator
will be retained to comply with neighboring states' processes. And use of an Independent
Evaluator is a key feature of a fair RFP process that has long been employed by neighboring states
of Utah and Oregon. In Utah, the Independent Evaluator is retained by the Commission with
clearly defined duties, including providing input into RFP design, evaluating all models used in
evaluations, validating benchmark bid assumptions and calculations, and providing
recommendations and reports to the Commission on bid ranking,shortlist,and resource selection.26
Likewise, in Oregon, the Independent Evaluator's duties include independent scoring of bids for
utility-owned resources and some or all other bids, evaluation of the unique risks and advantages
of utility-owned bids, and preparation of reports on the RFP design and final shortlist, as well as a
closing report on the RFP.27
To be clear,NIPPC would not be recommending an IPUC-specific Independent Evaluator
if Idaho Power were again proceeding through the OPUC's RFP process with an OPUC-approved
Independent Evaluator. However, moving forward with an RFP without any Independent
Evaluator is not reasonable. Idaho Power proposes no Independent Evaluator be required on the
grounds that the RFP is essentially the same as the prior RFPs, and the Independent Evaluator is
an unnecessary expense. However, the proposed RFP is not the same as the prior RFPs, and even
24 Staffs Application, Case No. GNR-E-25-01, at 5-6 (March 31,2025).
25 In the Matter of Commission Staffs Application for Approval of an Oversight Process for the
Acquisition of Large Supply-Side Electrical Resources, Case No. GNR-E-25-01, Order No. 36898,
Attachment A at 2(Jan. 2,2026).
26 Utah Admin. Code § R746-420-6;see also id. at §§ R746-420-1(2)-(4),R746-420-3,R746-420-4.
27 Ore. Admin. Rule § 860-089-0450.
NORTHWEST & INTERMOUNTAIN POWER PRODUCERS COALITION'S COMMENTS
IPC-E-26-03 —PAGE 13

if the Commission makes adjustments to render it the same as prior RFPs, an Independent
Evaluator is still needed to ensure fairness to all bidders. Notably, Idaho Power states it does not
oppose retention of an Independent Evaluator if it can be retained without compromising the
procedural schedule for the RFP.28
Without an Independent Evaluator, the proposed RFP omits several key requirements and
procedures that occurred in Idaho Power's 2028 RFP, which Staff recently found fair and
reasonable.29 This is evidenced by Attachment 1 showing the changes made from the 2028 RFP,
which include the following changes proposed here from that RFP:
• No Independent Evaluator report on the draft RFP or evaluation of the scoring and
modeling metrics for appropriateness;
• No Independent Evaluator oversight of exclusion of bids for failure to meet minimum
bid requirements;
• No Independent Evaluator scoring of the utility-ownership bids,or any third-party bids,
and instead only Idaho Power's own internal "Evaluation Team"would score the bids;
• No Independent Evaluator monitoring and reporting on negotiations between final
shortlist bidders and Idaho Power; and
• No final shortlist or closing reports to be produced by the Independent Evaluator for
stakeholder and IPUC use in rate recovery and future RFP development dockets.30
NIPPC submits that as many of these key functions as possible should be retained for completion
by a truly independent and qualified third party in this RFP. While NIPPC understands there has
28 See Attachment 4, Idaho Power's Independent Evaluator Discovery Responses.
29 See In the Matter of Idaho Power Co.'s Application for a Certificate of Public Convenience and
Necessity for the Bennett Gas Expansion Project and for an Associated Accounting Order, Case No. IPC-
E-25-29, Order No. 36958, at 3 (March 10, 2026) (stating, "Staff believed the RFP process to be fair and
reasonable, noting the Independent Evaluator's confirmation of the final shortlist and Staff s own review
of the Company's levelized cost of capacity calculations").
30 See Attachment 1,Comparison of Idaho Power's 2028 RFP to Idaho Power's Proposed 2032 RFP,
at 5-6, 8, 13,20.
NORTHWEST & INTERMOUNTAIN POWER PRODUCERS COALITION'S COMMENTS
IPC-E-26-03 —PAGE 14

been a suggestion in discovery that Staff may be able to perform some of these functions,NIPPC
questions whether Staff has the resources and availability to perform these functions in the same
manner that a qualified independent firm would have. Normally, in NIPPC's experience, the state
commission's staff works closely with, and oversees the work of, the Independent Evaluator, but
the Independent Evaluator is the firm engaged in overseeing the RFP on a day-to-day basis. Thus,
NIPPC recommends retention of an Independent Evaluator. However,NIPPC is sensitive to Idaho
Power's immediate resource needs and does not wish to unreasonably delay the solicitation
process.
Given the expedited nature of this RFP, NIPPC recommends that the same Independent
Evaluator be retained as in Idaho Power's last RFP, London Economics, for purposes of
performing the same duties in the last two RFPs, except for preliminary review and comment on
the draft RFP, which it is already too late for an IE to do without dramatically altering the RFP
schedule. Specifically, NIPPC recommends the Independent Evaluator be responsible for:
reviewing Idaho Power's determination of bidder eligibility, independently scoring the bids,
reviewing the selection and ranking of the initial and final shortlists,production of a report supplied
to parties and the Commission regarding the final shortlist, monitoring of final negotiations, and
production of a closing report as it has done in the past two RFPs.
Additionally, as in Utah, NIPPC recommends that the Independent Evaluator be retained
by, and report directly to, the Commission. Under the Utah rules, the Utah Public Service
Commission contracts with the Independent Evaluator and passes on the invoices to be paid by the
utility once approved by that Commission.31 In contrast, under Oregon's rules, the Independent
31 Utah Admin. Code § R746-420-5.
NORTHWEST & INTERMOUNTAIN POWER PRODUCERS COALITION'S COMMENTS
IPC-E-26-03 —PAGE 15

Evaluator contracts with the utility and only reports to the OPUC.32 In both states, the costs for
the engagement are recovered through bid fees and utility rates, but NIPPC understands that the
utility's employment of the Independent Evaluator in Oregon RFPs is due to a unique government
contracting limitation in Oregon law that is inapplicable here. The best practice would be for the
Commission to engage the Independent Evaluator to ensure its independence from the utility, and
therefore the IPUC should establish that Independent Evaluators are to be retained and contracted
directly by the Commission when required in an IPUC RFP.
D. Price/Non-Price Scoring Allocation: The Commission Should Require Use of the
Same Price/Non-Price Points Weighting for Bids as Idaho Power's Last RFP-75%
Price/25% Non-Price.
NIPPC recommends that the RFP should transparently identify the allocation of scoring
points between a bid's price score and its non-price score, and that this RFP should use the same
75% price/25% non-price allocation used in Idaho Power's 2026 and 2028 RFPs. Idaho Power
proposes to delete the transparent description of the price/non-price points allocation from those
prior RFPs and to replace that method with an opaque and undefined method of weighting the
score between price and non-price characteristics.33 The lack of transparency with Idaho Power's
proposal is unacceptable and should be rejected by the Commission.
In principle, the bid scoring process should be structured in a way to ensure that the
selection process is objective, transparent, and aligned with the utility's goals of acquiring the
32 OAR 860-089-0200(1), (3).
33 See Attachment 1,Comparison of Idaho Power's 2028 RFP to Idaho Power's Proposed 2032 RFP,
at 27-30 (deleting description of the 75%/25% points weighting from the 2028 RFP); Attachment 6
(containing Idaho Power's Response to NIPPC's Interrogatory No. 15, which states with respect to the
proposed 2032 RFP: "The price evaluation does not include a numbered value for combination with the
non-price scoring. Rather,the price evaluation is based on relative pricing ranking of resources within the
same technology. Through the quantitative price evaluation and the qualitative non-price scoring, the
comprehensive set of the highest ranking and relatively lowest cost proposal become the initial shortlist.").
NORTHWEST & INTERMOUNTAIN POWER PRODUCERS COALITION'S COMMENTS
IPC-E-26-03 —PAGE 16

least-cost and least-risk resources. Typically, in RFPs, a bid is assigned a total score made up of
price and non-price scores. The price score reflects the bid's total cost or revenue requirement,
whereas the non-price score reflects a wider range of potentially more subjective project
characteristics, such as development status, interconnection viability, ability to finance and
complete construction, and permitting risks. The price and non-price scores are combined to form
a total score based on the percentages weighted to each score. To limit the risk inherent in
subjective evaluation, NIPPC typically recommends minimization of non-price factors, through
conversion to minimum bid criteria where possible, and utilization of a 70-80% price weighting
and a 20-30%non-price weighting, depending on the circumstances. There are often debates over
the most appropriate price/non-price weighting in RFP proceedings, but Idaho Power's proposal
to hide the weighting from all parties, including the Commission, is novel and completely
unreasonable.
In Idaho Power's 2026 and 2028 RFPs, the weighting was approved by the OPUC at 75%
price/25% non-price, and for consistency, NIPPC recommends use of the same weighting here.
That weighting was within a reasonable range and appropriately advantages bids that have been
more derisked,through advanced permitting, etc.,while still properly allocating most points to the
cost of the resource to ratepayers. Idaho Power provides no reasonable basis to hide the weighting
from bidders, stakeholders, and the Commission, and allowing it to do so risks both biasing the
RFP and establishing a bad precedent for future IPUC RFPs.
Notably,NIPPC's recommendation on this point is consistent with the IPUC's RFP Rules'
requirement that the RFP Selection Plan "should include scoring factors."34 Neighboring states
34 In the Matter of Commission Staffs Application for Approval of an Oversight Process for the
Acquisition of Large Supply-Side Electrical Resources, Case No. GNR-E-25-01, Order No. 36898,
Attachment A at 2 n. 1. (Jan. 2,2026).
NORTHWEST & INTERMOUNTAIN POWER PRODUCERS COALITION'S COMMENTS
IPC-E-26-03 —PAGE 17

Utah and Oregon both require transparency on the points allocation as well.35 The applicable rules
require transparency on this point because,as noted above,non-price scoring criteria are inherently
subjective and susceptible to unfair or unequal treatment during evaluation. Transparency limits
the risk of apparent or actual favoritism to certain bids over others in the RFP.
In sum, the Commission should require a transparent points allocation of 75% price/25%
non-price.
E. Benchmark Bids: The Commission Should Require that Benchmark Bids Be
Submitted and Scored Prior to the Third-Party Bids.
NIPPC recommends that the Commission require Idaho Power to adhere to the safeguards
of its past two RFPs with respect to submission and scoring of benchmark bids by requiring those
bids be submitted and scored prior to the third-party bids. Specifically, Idaho Power deleted the
following sentences that existed in the 2028 RFP and which NIPPC recommends be reinstituted
for this RFP:
IPC's Benchmark Bids will be submitted to the IE no later than seven(7) days prior to the
opening of bids from the market (Third-Party Bids). Third-Parry Bids shall not be opened
until the IE and IPC's Evaluation Team have reviewed, evaluated, validated, and scored
any and all Benchmark Bids. The Benchmark Bid scores will be assigned using the same
scoring and evaluation criteria that will be used to score Third-Party Bids.36
Scoring the benchmark bids prior to the third-party bids is standard practice to prevent the
utility from biasing the RFP by adjusting its benchmark bid to beat the bids submitted by third
parties, and to preclude the appearance that the utility could do so if it chose, which could deter
participation of third-party bidders. To ensure fairness, the best practice is to require the
35 See Utah Admin. Code § R746-420-3(7)(c)(requiring RFP to include"price and non-price factors
and weights"); Ore. Admin. Rule § 860-089-0400(1) (requiring RFP to include "all scoring criteria and
metrics").
36 Attachment 1, Comparison of Idaho Power's 2028 RFP to Idaho Power's Proposed 2032 RFP, at
5.
NORTHWEST & INTERMOUNTAIN POWER PRODUCERS COALITION'S COMMENTS
IPC-E-26-03 —PAGE 18

benchmark bids be submitted and locked down prior to the third-party bids and that any
opportunity to change bid prices or characteristics after that time be made available to all bidders.
In Idaho Power's 2026 RFP proceeding, Idaho Power itself stated to the OPUC Staff. "To ensure
unbiased evaluation, the internal Bid Team bids will be due ahead of the market bids."37 This
important feature of the RFP should not be discarded.
F. Capturing the Benefits of Expiring Tax Credits: Idaho Power's RFP Should
Accept, and Clarify the Treatment of, Bids for Wind and Solar Projects that Must
Be Placed in Service by the End of 2030 for Purposes of Qualifying for Expiring Tax
Credits.
Idaho Power's proposed RFP contains ambiguity that should be clarified with respect to
the treatment of wind and solar projects that must be placed in service by the end of 2030 for
purposes of achieving eligibility for expiring tax credits. NIPPC recommends that the RFP should
unambiguously clarify that Idaho Power will accept such bids and should further clarify that Idaho
Power will begin accepting, and potentially paying for, the energy delivered from such a facility
to the extent necessary to achieve placed in service status in 2030.
This issue arises because the federal tax credits for wind and solar projects remain available
for certain projects that are successfully placed in service by the end of 2030.38 This creates a
potentially significant class of wind and solar projects that are likely to be able to capture the value
of the tax credits if they are placed in service prior to the end of 2030 just months prior to Idaho
37 Attachment 5, Idaho Power's Benchmark Bid Discovery Response.
38 Under applicable law and Internal Revenue Service ("IRS") Guidance, a"safe harbor" eligibility
exists for projects that begin construction by July 4, 2026 and are "placed in service" by the end of the
fourth calendar year after construction began—leaving December 31, 2030 as a key placed-in-service
deadline. See IRS Notice 2025-42 at 1-2, 5-12 (Aug. 15, 2025), available at: https://www.irs.gov/pub/irs-
drop/n-25-42.pdf. If construction begins by July 4, 2026, but is not complete by the end fourth calendar
year thereafter, the project's only option is to attempt to establish qualification under IRS's criteria for
excusable disruption to construction,but this is a facts and circumstances test that may be difficult to rely
upon. Id.
NORTHWEST & INTERMOUNTAIN POWER PRODUCERS COALITION'S COMMENTS
IPC-E-26-03 —PAGE 19

Power's identified resource need and target initial delivery date of April 1, 2031. Such a wind or
solar project placed in service by the end of 2030, and thus eligible for the substantial tax credits,
would be able to bid a significantly lower price than a similar project not placed in service until
April 1, 2031, and potentially other technology types as well. Thus, it is reasonable to expect that
ratepayers may be able to benefit from a significantly lower cost resource by enabling wind and
solar facilities bidding into the RFP to capture available tax credits.
However,Idaho Power's proposed RFP does not clarify whether Idaho Power would accept
bids from projects that must be placed in service prior to 2031 for tax purposes or whether Idaho
Power would accept, and potentially pay, for the test energy that necessarily must be delivered
prior to April 2031 to capture the value of the tax credits. Idaho Power's proposed RFP strongly
suggests Idaho Power will not even accept such bids into the RFP. The RFP's section titled
"Eligible Proposals" lists the requisite "First Delivery" as "Between April 1 and May 31 of the
respective year (2031 or 2032),,,3' but the Bid Eligibility Checklist merely states: "All proposals
must have a First Delivery date of May 31, 2032 or earlier."40 Further, while potentially subject
to negotiation, the proposed RFP's form power purchase agreement, battery storage agreement,
and build transfer agreement each state that the developer/seller may not achieve commercial
operation in any calendar quarter prior to the calendar quarter of the scheduled commercial
operation date, which appears to preclude commercial operation in the final quarter of 2030 given
the RFP's earliest delivery date of April 1, 2031.41 Although a bidder has inquired of Idaho
39 Idaho Power's Application,Direct Testimony of Eric Hackett,Ex.No. 1,at 11-13 (Feb.20,2026).
40 Id. at Ex.No. 1 at 35.
41 See id. at Ex.No. 1 at 86(Power Purchase Agreement§4.2.11: "Seller shall ensure that the Facility
does not achieve Commercial Operation in any Calendar Quarter prior to the Calendar Quarter in which the
Scheduled Commercial Operation Date falls.");id. at Ex.No. 1 at 368(same for Battery Storage Agreement
at § 4.2.13); id. at Ex. No. 1 at 204 (Build Transfer Agreement at § 1.1, "Substantial Completion Date"
includes: "Developer shall ensure that the Project does not achieve Substantial Completion in any Calendar
Quarter prior to the Calendar Quarter in which the Guaranteed Substantial Completion Date falls.").
NORTHWEST & INTERMOUNTAIN POWER PRODUCERS COALITION'S COMMENTS
IPC-E-26-03 —PAGE 20

Power's treatment of such bids through Idaho Power's RFP website, Idaho Power's response has
not clearly clarified the point that it will accept deliveries from a successful bidder prior to 2031
or that it will pay for such energy, even if at a potentially reduced price.42 Without that clarity,the
RFP may deter such bids from being submitted.
In sum, capturing the economic benefit of expiring tax credits is a clear potential benefit to
Idaho Power's ratepayers, and therefore NIPPC recommends that the RFP be clarified to remove
all ambiguity and encourage such bids into the RFP. Specifically, NIPPC recommends that the
RFP should unambiguously clarify that Idaho Power will accept such bids and should further
clarify that Idaho Power will begin accepting,and potentially paying for,the energy delivered from
such a facility to the extent necessary to achieve placed in service status in 2030.
G. Technology-Based Bid Ranking: The Commission Should Require Idaho Power to
Rank Bids Without Regard to Resource Type for Purposes of Developing the RFP's
Shortlist.
NIPPC recommends that Idaho Power revise the RFP to the extent necessary to discontinue
the practice of ranking bids by resource type for purposes of developing the shortlist. Idaho Power
appears to propose to rank the bids' price scores against only the bids with the same resource type
(e.g., wind bids ranked only against other wind bids), similar to the practice it employed in the
2026 RFP and the 2028 RFP.43 However, as the OPUC Staff commented at the shortlist approval
stage of the 2028 RFP,this practice can favor and automatically advance bids with few other bids
42 See https://www.idahopower.com/about-us/doing-business-with-us/request-for-resources/ (Idaho
Power states: "Idaho Power is not seeking new resources in earlier years based on the identified needs.
However,the requirement as defined in Exhibit C—Bid Eligibility Checklist only requires that the COD is
prior to May 31,2032.Proposals with COD dates prior to April 1,2031,will be evaluated as a 2031 proposal
based on the then-current deficiencies. Idaho Power is resource-sufficient through 2030 and adding
additional resources prior to 2031 may not be prudent.").
43 See Attachment 1,Comparison of Idaho Power's 2028 RFP to Idaho Power's Proposed 2032 RFP,
at 28 ("IPC's proprietary price scoring model ranks each bid relative to each other within the same
technology where feasible.").
NORTHWEST & INTERMOUNTAIN POWER PRODUCERS COALITION'S COMMENTS
IPC-E-26-03 —PAGE 21

with the same technology, and instead the utility could rank price bids across technology by
"develop[ing] a bid price that reflects the net benefits of each bid regardless of technology type."44
In NIPPC's experience, Idaho Power's recent practice of ranking bids by resource type is not the
norm in regional utilities' RFPs, and NIPPC is concerned this practice can lead to anomalous
results. NIPPC understands that Idaho Power may prefer to automatically advance bids for
technologies with one or very few bids to the portfolio modeling stage for further evaluation.
However, NIPPC is generally concerned with heavy reliance on portfolio modeling in RFPs
because it lacks transparency and can be impacted by faulty, or potentially even biased, modeling
assumptions. Reducing price bids to a technology neutral metric for purposes of ranking and
advancing bids reduces the reliance on portfolio modeling. Therefore, NIPPC recommends that
all bids' price scores be ranked against each other in this RFP.
III. CONCLUSION
NIPPC respectfully requests that the Commission require the modifications to Idaho
Power's RFP discussed above.
44 See In the Matter of Idaho Power Co., Application for Approval of 2028 All-Source Request for
Proposals to Meet 2028 Capacity Resource Need, OPUC Docket No. UM 2317, Order No. 25-327, App.
A at 8-9 (Aug. 20,2025) ("Staff believes some changes to the ranking process should be considered in the
future. Currently, the Company ranks projects by technology type, which leads to some projects being
placed on the[Initial Shortlist] automatically,since they are the only proposal of a specific technology type.
It may be desirable to develop a bid price that reflects the net benefits of each bid regardless of technology
type. For instance, Portland General Electric develops the net benefits of each bid by subtracting the
levelized costs of a bid from its energy(MWh),capacity(avoided capacity cost),and flexibility(responding
to forecast errors, enabling fast ramping, and meeting reserve requirements)value in its latest RFP.").
NORTHWEST & INTERMOUNTAIN POWER PRODUCERS COALITION'S COMMENTS
IPC-E-26-03 —PAGE 22

Respectfully submitted this 3rd day of April, 2026.
/s/ GreZoa M. Adams
Gregory M. Adams (ISB No. 7454)
Richardson Adams, PLLC
515 N. 27th Street
Boise, Idaho 83702
Telephone: [phone]
Fax: [phone]
[e-mail]
Irion Sanger(ISB No. 12488)
Sanger Greene, PC
4031 SE Hawthorne Blvd.
Portland, OR 97214
Telephone: [phone]
Fax: [phone]
[e-mail]
Attorneys for Northwest & Intermountain Power
Producers Coalition
NORTHWEST & INTERMOUNTAIN POWER PRODUCERS COALITION'S COMMENTS
IPC-E-26-03 —PAGE 23

CERTIFICATE OF SERVICE
I HEREBY certify that I have on this 3rd day of April, 2026, served the foregoing
Petition to Intervene by electronic mail to the following:
Monica Barrios-Sanchez Tim Tatum
Commission Secretary Connie Aschenbrenner
Idaho Public Utilities Commission Idaho Power Company
P.O. Box 83720 1121 W. Idaho Street
Boise, ID 83720-0074 PO Box 70
[e-mail] Boise, ID 83707-0070
ttatum@.idahopower.com
Jeffrey R. Loll [e-mail]
Deputy Attorney General
Idaho Public Utilities Commission Eric L. Olsen
P.O. Box 83720 Echo Hawk& Olson, PLLC
Boise, ID 83720-0074 505 Pershing Ave., Ste. 100
[e-mail] P.O. Box 6119
Pocatello, Idaho 83205
Donovan Walker [e-mail]
Idaho Power Company [e-mail]
1121 W. Idaho Street
PO Box 70 Lance Kaufman, Ph. D.
Boise, ID 83707-0070 Deborah Glosser, Ph. D.
[e-mail] 2623 NW Bluebell Place
[e-mail] Corvallis, OR 97330
[e-mail]
Ed Jewell [e-mail]
Deputy City Attorney
Boise City Attorney' s Office
150 N. Capitol Blvd. Austin Rueschhoff
P.O. Box 500 Thorvald A. Nelson
Boise, ID 83701- 0500 Richard A. Arnett
[e-mail] Holland&Hart, LLP
[e-mail] 555 17th St., Ste. 3200
Denver, CO 80202
Katie O'Neil [e-mail]
Energy Program Manager [e-mail]
Boise City Dept. of Public Works [e-mail]
150 N. Capitol Blvd. [e-mail]
P.O. Box 500 [e-mail]
Boise, ID 83701- 0500
[e-mail]
By: /s/ Gregoa M. Adams
Gregory M. Adams (ISB No. 7454)
NORTHWEST & INTERMOUNTAIN POWER PRODUCERS COALITION'S COMMENTS
IPC-E-26-03 —PAGE 24

List of Attachments
Attachment 1: Comparison of Idaho Power's 2028 RFP to Idaho Power's Proposed 2032 RFP
*Provided as Idaho Power's Response to NIPPC's Production Request No. 1
Attachment 2: Idaho Power's Imputed Debt Discovery Responses
*Idaho Power's Responses to NIPPC's Interrogatory Nos. 6 & 7; OPUC Docket
No. UM 2255 Idaho Power Response to NIPPC Information Request No. 1; and
Idaho Power's Response to IPUC Staff's Production Request No. 10
Attachment 3: Expert Report on PPA Imputed Debt of Michael P. Gorman, OPUC Docket No.
UM 2255 (May 9, 2023)
Attachment 4: Idaho Power's Independent Evaluator Discovery Responses
* Idaho Power's Responses to NIPPC's Interrogatory Nos. 12 & 13
Attachment 5: Idaho Power's Benchmark Bid Discovery Response
* OPUC Docket No. UM 2255 Idaho Power's Response to Staff Data Request
No. 3
Attachment 6: Idaho Power's Price/Non-Price Allocation Discovery Response
* Idaho Power's Response to NIPPC's Interrogatory No. 15

Attachment 1 :
Comparison of Idaho Power's 2028
RFP to Idaho Power's Proposed
2032 RFP
*Provided as Idaho Power's Response to NIPPC's Production Request No. 1

�I RR
DRAFT 202
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Zycus Event: XXXXXXXXX Idaho Power Company
Draft RFP Posted: XXXXX P.O. Box 70
RFP Issued: XXXXX Boise, ID 83707
RFP Response Due: XXXXXX

DRAFT FOR FILING
2.20.2026

Table of Contents
I. Bissfa1Fner 3
2. Pu;pese R
2.1. BACKGROUND 3
2.2. THE SOLICITATION R
2.3. REGULATORY CONTEXT 4
2—Ar IPC SELF BUILD RESOURCES AND BENCHMARK RESOURCES S
2.5. INDEPENDENT EVALUATOR S
2.6. CONFIDENTIALITY 6
2.7 SOLICITATION PORTAL NRESTofCTION ON COMMUNICATIONS 7
2.8. SCHEDULE 7-
3. PxGpesaTSyerAfkatiens l9
3.1. ELIGIBLE PROPOSALS 9
gam. ALTERNATIVE PROPOSALS ii
3.3. TRANSMISSION ALTERNATIVES 12
4. ReseurEe R�^Sedrropposals.AddTtionaTSpesificiatfARr, Rrr�,'�-'RrAr--GVa 4
4.1. MINIMUM REQUIREMENTS 1-2
4.2. DELIVERY AND RESOURCE STATUS 1-2
4.3. OWNERSHIP AND AGREEMENT TYPES 12
n n INTERCONNECTION STUDIES AND COST ESTIMATING i3
T.T. INTERCONNECTION CI[cc�IvlVCc1 Iv1V
4.5. RID SUBMISSION PROCESS i6
Rod PpfimOt+eA PArm and SeleEtable Pertfelie �§
ii Rid Entry Ferm i6
Heu„ Renewe-PrepdQEt+e„Template 1�&
Rid S� tal i6
4.6. EVALUATION PEES i6
n EXCEPTIONS TO THE DRAFT FORM AGREEMENTS i7-
T.1. EXCEPTIONS vivo �v THE�
n Q EXCEPTIONS TO THE TECHNICAL SPECIFICATIONS iS
T.o. EXCEPTIONS v�vo �v �
n o EXCEPTIONS TO THE DRAFT FORM LETTER OF CREDIT ,S
T..... EXCEPTIONS icnvv i c�i THE
S. I��etP-:rc�ase PFGpQsals Additional-Spes+fTc tfens and IRRU,ictenws 39
S MINIMUM REQUIREMENTS i9
5.2AGR€€MENTTYP€S i9
S BID ATTRIBUTES ig
Page i

S.A. BID IDSUBMISSIONOE€SS 19
Bid Definition Form 19
II Red Entry Form 20
H I B F( Irhr° rF ;;I 20
A(Attie ral Regq'd'rFe.M-CRt-r,f r All Bid Packages -8
6_1 CONTENTS OF WRITTEN BID PROPOSAL—
ROP SA 20
6.2. BID NAMING 20
6.3. BID`rnv WRITTEN DOCUMENTS 29
6.4. R F P EXHIBITS 20
6.5. FIRM BID 21
6 TAXES 21
6.7. DATA AND C—YBER SECURITY 21
6.8. PURCHASING RESTRICTIONS/PROHIBITEDT€CHNOLOGY 22
6.9.SSMA€L BUSINESS-AND-SMALL DISADVANTAGED BUSINESS PROr_Rnnn 22
6.10. INSURANCE 23
6.11. �FINANCIAL AND CREDIT INFORMATION 23
� rcNCc�rc
6.12.CLARIFIC-ATION OF BIDS 23
643 ADDENDA TO RFP 23
r. �F(€€114�icic'r FAar-r�cge fRUA"• r..J nr,r....., .I 23
7.1. THE EVALUATION PROCESS 23
7.2. PHASE 1—INITIAL SHORTLISST 24
7.3. PHASE FINALSsHORTLISST 27
7.4. ADDITIONAL RIGHTS 29
7.5. ACCEPTANCE AND REz€CTION OF BIDS 39
7.6AGR€€MENT N-GOTI�^TIOONS 39
7.7. EXCLUSIVITY 30
'8.Pk1RL!C!T" 39
:7 9COMMISSION APPROVALM
9. ENTIRE RFP 20
1. Disclaimer..................................................................................................................................2
2. Purpose......................................................................................................................................2
2.1. BACKGROUND .............................................................................................................................2
Page ii

2.2. REGULATORY COMPLIANCE ........................................................................................................2
2.3. THE SOLICITATION AND NEED.....................................................................................................2
2.4. IPC SELF-BUILD RESOURCES ........................................................................................................4
2.5. CONFIDENTIALITY........................................................................................................................6
2.6. SOLICITATION PORTAL AND RESTRICTION ON COMMUNICATIONS...........................................6
2.7. SCHEDULE....................................................................................................................................7
2.8. ANNOUNCEMENT PLAN ..............................................................................................................8
3. Proposal Specifications...............................................................................................................9
3.1. ELIGIBLE PROPOSALS...................................................................................................................9
3.2. ALTERNATIVE PROPOSALS.........................................................................................................12
3.3. TRANSMISSION ALTERNATIVES.................................................................................................13
4. Resource-Based Proposals:Additional Specifications and Instructions.......................................13
4.1. MINIMUM REQUIREMENTS.. ................................................................................13
4.2. DELIVERY AND RESOURCE STATUS............................................................................................13
4.3. AGREEMENT TYPES....................................................................................................................13
4.4. INTERCONNECTION STUDIES AND COST ESTIMATING..............................................................15
4.5. BID SUBMISSION PROCESS........................................................................................................17
i Bid Definition Form and Selectable Portfolio ................................................................................17
iiBid Entry Form...........................................................................................................................17
iii Forecasted Hourly Renewable Output......................................................................................17
ivBid Submittal .............................................................................................................................18
4.6. EVALUATION FEES.....................................................................................................................18
4.7. EXCEPTIONS TO THE DRAFT FORM AGREEMENTS....................................................................19
4.8. EXCEPTIONS TO THE DRAFT FORM LETTER OF CREDIT.............................................................19
4.9. TECHNICAL SPECIFICATIONS......................................................................................................20
5. Market Purchase Proposals:Additional Specifications and Instructions......................................20
5.1. MINIMUM REQUIREMENTS.......................................................................................................20
5.2. AGREEMENTTYPES....................................................................................................................21
5.3. BID ATTRIBUTES.........................................................................................................................21
5.4. BID SUBMISSION PROCESS........................................................................................................21
iBid Definition Form........................................................................................................................21
iiBid Entry Form...........................................................................................................................21
iiiBid Submittal .............................................................................................................................21
6. Additional Requirements for All Bid Packages ...........................................................................22
Page iii

6.1. CONTENTS OF WRITTEN BID PROPOSAL...................................................................................22
6.2. BID NAMING..............................................................................................................................22
6.3. BID WRITTEN DOCUMENTS.......................................................................................................22
6.4. RFP EXHIBITS REQUIREMENTS...................................................................................................22
6.5. FIRM BID....................................................................................................................................23
6.6. TAXES.........................................................................................................................................23
6.7. DATA AND CYBER SECURITY......................................................................................................23
6.8. PROHIBITED TECHNOLOGY AND TRADE SANCTIONS................................................................24
6.9. SMALL BUSINESS AND SMALL DISADVANTAGED BUSINESS PROGRAM ...................................25
6.10. INSURANCE................................................................................................................................25
6.11. FINANCIAL AND CREDIT INFORMATION....................................................................................25
6.12. CLARIFICATION OF BIDS.............................................................................................................25
6.13. ADDENDA TO RFP......................................................................................................................25
7. Bid Evaluation, Negotiation and Approval.................................................................................26
7.1. THE EVALUATION PROCESS.......................................................................................................26
7.2. PHASE 1—INITIAL SHORTLIST....................................................................................................26
7.3. PHASE 2—FINAL SHORTLIST......................................................................................................30
7.4. ADDITIONAL RIGHTS..................................................................................................................32
7.5. ACCEPTANCE AND REJECTION OF BIDS.....................................................................................33
7.6. AGREEMENT NEGOTIATIONS ....................................................................................................33
7.7. EXCLUSIVITY...............................................................................................................................33
7.8. PUBLICITY...................................................................................................................................33
7.9. COMMISSION APPROVAL..........................................................................................................33
8. ENTIRE RFP...............................................................................................................................34
Page iv

Page v

EXHIBITA—Bid Definition Form (Excel workbook)
EXHIBIT B—Bid Entry Form (Excel workbook)
EXHIBIT C—Bid Eligibility Checklist(Excel workbook)
EXHIBIT D—Non-Price Scoring MA4i)(Sheet(Excel workbook)
EXHIBIT E—PFOpesed Market P---r." "e4+n+LsTransmission Paths and Delivery Points
EXHIBIT F.1-F.4—Draft Form Agreements and Term Sheets for Resource—Based Proposals
EXHIBIT G—RESS Tec-hnac-al Spe, for;atoom
€XVVILJIRIT 1—WiR d Tor-hn al Spermifirmatiens-
€Y HSrRIT I—r-;;,;_Perp d r.,nvPr-+ihle to Hy dFagen Specification;;
Gvu� Mutual Non-Disclosure Agreement
EXHIBIT-LH—Counterparty Financial Questionnaire
EXHIBIT MI—Draft Form Letter of Credit
Fxhmhmt hi—Red Format and RequffiFeme4#s
P OEXHIBIT J—Levelized PVRR Scenarios
rmullhobet P—Ren cn h iTrc'ri-�k R'.d
vc-vic's
ExhibitQ EXHIBIT K—Forecasted Hourly Renewable PF96l ctien TemplaLeOutput (Excel workbook)
€ATM R—Supplemental 2029EXHIBIT L—Cyber Security Questionnaire
EXHIBIT M—Gas-Fired Resources—Fuel Questionnaire
EXHIBIT N—Bid Format and latpr
Page vi

Page 1

1. Disclaimer
The information contained in this Request for Proposals (RFP) is presented to assist interested parties in deciding
whether er not submit a bid. Idaho Power Company (IPC), an operating company subsidiary of IDACORP, Inc.,
is issuing this RFP to solicit formal bids from qualified companies (each a Bidder) and does not represent this
information to be comprehensive or to contain all of-the information that a Bidder may need to consider+e
^r^'^r*^ "� when submitting a bid. None of IPC, its affiliates, or their respective employees, directors,
officers, customers, agents, and consultants makes—or will be deemed to have made—any current or future
representation, promise, or warranty—express or implied—as to the accuracy, reliability, or completeness of
the information contained herein, or in any document or information made available to a Bidder—whether or
PEA-the aforementioned parties knew or should have known of any errors or omissions, or were responsible for
their inclusion in, or omission from,this RFP.
No part of this RFP and no part of any subsequent correspondence by IPC, its affiliates, or their respective
employees, directors, officers, customers, agents, or consultants shall be taken as providing legal,financial,
or other advice, or as establishing a contract or contractual obligation. IPC reserves the right to request from
Bidders information that usnot explicitly detailed in this document, obtain clarification from Bidders concerning
bids, conduct contract development discussions with selected Bidders, conduct discussions with members of the
Evaluation Team,and other support resources as described in this RFP.The requirements specified in this RFP
reflect those presently known. IPC reservices the right to vary, in detail,the requirements and/or to issue
addenda to the RFP. In the event it becomes necessary to revise any part of the RFP, addenda will be provided
to Bidders included in the current and applicable stage of the RFP.
IPC will, in its sole discretion and without limitation, evaluate bids and proceed in the manner IPC deems
appropriate. IPC reserves the right to reject any and all, or portions of any bid submitted by Bidders for failure to
meet any criteria set forth in this RFP or otherwise, and to accept bids other than the lowest cost bid.
This RFP has been prepared solely to solicit bids and is not a contract offer.This RFP is not binding on IPC.
The only document that will be binding on IPC is an agreement duly executed by IPC and the successful Bidder
(if any) after the completion of the evaluation process and the award and negotiation of an agreement.
IPC reserves the right to reject any and all bids submitted by Bidders.The issuance of this RFP does not obligate
IPC to purchase any product or services offered by Bidder or any other entity. Furthermore, IPC may choose,
at its sole discretion,to abandon the RFP process in its entirety. Bidders agree thal-they submit bids without
recourse against IPC;,IDACORP,Inc...,,1 any affiliate of IDACORP, Inc.'s affiliates, or any of their respective
employees, agents, officers, or directors for failure to accept an offer for any reason. IPC-apse may decline to
enter into any agreement with any Bidder,terminate negotiations with any Bidder, or abandon the RFP process
in its entirety at any time,for any reason, and without notice thereof. Bidders thatwho submit bids agree to do
so without legal recourse against IPC, its affiliates or their respective employees, directors, officers, customers,
agents or consultants for rejection of their bids or for failure to execute an agreement for any reason. IPC and its
affiliates shall not be liable to any Bidder or other party in law or equity for any reason whatsoever for any acts
or omissions arising out of or in connection with this RFP. Bidder shall conform in all material respects to all
applicable laws, ordinances, rules, and regulations and nothing in this RFP shall be construed to require IPC or
Bidder to act in a manner contrary to law. Except as otherwise provided in the rules and orders of the Idaho
Public Utilities Commission (IPUC) and the Public Utility Commission of Oregon (the-OPUC), (jointly the
Commissions), by submitting its bid, a Bidder waives any right to challenge any evaluation by IPC of its bid.
Budde Bidders whose bid may be selected in response to this RFP acknowledges that it assumes full legal
responsibility for the accuracy,validity, and legality of the work provided in conformance with this RFP. By
Page 2

submitting its bid, a Bidder waives any right to challenge any determination of IPC to select or reject its bid. IPC
reserves the right to accept the bid in whole or in part, and to award to more than one Bidder. Furthermore,
Bidder understands that any"award" by IPC does not obligate IPC in any way. IPC will not be obligated to any
part unless and until IPC executes a definitive agreement between the parties.
Bidder will absorb all costs incurred in responding to this RFP, including without limitation, costs related to the
preparation and presentation of its response.All materials submitted by the Bidder immediately become the
property of IPC.Any exception will require written agreement by both parties prior to the time of submission.
In responding to this RFP, the Bidder shall adhere to best business and ethical practices.The Bidder shall adhere
to IPC's Supplier Code of Conduct, also available at idahopower.com.
The Bidder is specifically notified that failure to comply with any part of this RFP may result in disqualification of
the bid, at IPC's sole discretion.
This RFP, in its entirety, is draft and subject to final approval by the^P"G". '-'~h^ 12a-wer��•'�.,;�„ot+fy patentio
-bidders rind nc-eFper-ate any updates Gs applic-alale upon appFeval by the OPI fr- ON 9C Gal;#2 Afe I 9A4 2 2
Page 3

regulatory approval.
Page 1

i
2. Purpose
2.1. BACKGROUND
IDACORP, Inc...,is a holding company formed in 1998. Comprised of regulated and non-regulated
businesses, its origins lie with Idaho Power Company(IPC), a regulated electric utility that began
operations in 1916.Today, IPC is the largest regulated electric utility in the state of Idaho and
!^^,�'sIDACORP, Inc.'s chief subsidiary. IPC serves ever 630more than 650,000 residential,
business, agricultural and industrial customers.The company's service area covers approximately
24,000 square miles, including portions of eastern Oregon. Learn more about IPC at idahopower.com.
IPC currently serves its customers by supplying low-cost, reliable, and clean energy. Affordable, clean
hydropower is the largest source of energy for customers. Power generation comes from a diverse set
of resources that continues to meet a growing demand. For a more detailed description of current
generation resources, please visit-- idahopower.com/energy-environment/energy/energy-sources/.
IPC's service territeryarea continues to experience customer growth and an increasing peak demand
(load) for electricity. IPC anticipates sustained load growth that will require the procurement of new
resources to meet energy requirements and peak summeF demand and maintain system reliability as
identified in the most recent 2023 integ*a ^r' Resource (IRP).2025 Integrated Resource Plan (IRP).
The addition of new resources to meet peak demand is critical to ensure IPC can continue to reliably
meet the growing demands on its electrical system and serve its customers.
2.2. REGULATORY COMPLIANCE
Regulatory approval of this RFP is required.'The RFP is resource-agnostic and solicits bids from all
feasible resource types with sufficient lead time to meet the desired commercial operation date. IPC is
releasing this RFP solicitation to meet the objective of determining the least-cost and least-risk
resource to satisfy the system needs.The selection will be conducted through a fair, transparent, and
confidential evaluation process as defined throughout this RFP.
Execution of any agreement may ultimately be subject to regulatory approval. For the IPUC,this could
include, but is not limited to, a request for a certificate of public convenience and necessity(CPCN)
from IPC. IPC reserves the right to: 1) inform the IPUC that IPC could not reach agreement with the
Bidder of a selected resource; 2) request IPUC approval of any agreements it enters with successful
Bidders (e.g., CPCN applications): and 3)terminate any agreement if IPC fails to receive IPUC approval
of submitted agreements or applications. Bidder shall provide any and all information and
documentation reasonably requested by IPC to support such applications and requests.
24-.2.3. THE SOLICITATION AND NEED
IPC is issuing this RFP to solicit formal bids from Bidders for two types of electric energy and capacity
products.The first type is unit-contingent energy where capacity is delivered from specific electric
resources (Resource Based°repQsals`�esecond-type is#;;n energy(W-9 TSe,"Ted-Ile G er equivale„t
'See IPLIC's Procedures for Soliciting Large Supply-Side Resources(Order No. 36898)and Oregon Administrative
Rule 860-089-0100.
Page 2

i
The eligible types of bidS aFe described furthe.r in Section 3 of this RFP -;;nr-1 include RprA--rpp R;;,;Prl
PFepesals ;neludi ^-Based Proposals).This product includes asset purchases, power purchase
agreements, and battery storage agreements with exclusive ownership by IPC of any and all
environmental attributes associated with all energy generated -and ""-ark^* Purchase preposals
anel „ in^f;.w, ^^^F^••^^RtFaets .The second type is firm energy contracts (WSPP Schedule C or
equivalent preferred)that meet the eligibility requirements of the Western Resource Adequacy
Program (WRAP)for qualifying contracts (Market Purchase Proposals).The eligible types of bids are
described further in Section 3 of this RFP. Details on the bid submission process and the bid evaluation
process are also described further in this RFP. Only bids submitted through this RFP will be evaluated,
regardless of the status of bids currently participating in the 2028 RFP.
IPC's annual capacity position developed to inform its 202.32025 IRP demonstrates thatthe
Gem company will have future resource needs.The 20232025 IRP identifies 138 megawatts (MW)
of-the potential need for incremental peak capacity needs in '^'4and 555 ".M.A.'of-and supply-side
FeseuFee addaitiens in the Pr^feirred Pert{-he in '^'4PUFtheF,resources. Recent regulatory filings for
resources have built off the 2023identified 2025 IRP the Gateway West WO ki'Av^ir
tFansmission line segment constructielp in late 220-28, which is prer-Iffircated A-In future resource leeatiens
dFivin^the need fer m1pli*i^na'+r.,n.-.,. issi^n Theneed and have shown an incremental perfect capacity
need of a total of at least 200 megawatts (MW) in 2031 and 2032 with a greater need likely in 2032.
The need identified is subject to change based on updated information regarding load and resources,
as well as contracts backing firm transmission.
IPC will be aceeptingaccept bids for energy or capacity k^ .ntal+^ its ,s+^,.... beginning On the
summer 2^'4 time-frame and beyend from Resource-=Based Proposals and Market Purchase
Proposals. �.A.Iholp- .'PC-- us en rneet*Rg needs in 2028, IPC is receiving prepo&4s
beyend 2022 as well apel will review ever the re,irs-e Aef. thp Pwfll A-.A.th P- MoSt Up
to date RequirerneRts fA-.r bids that v.feuldl -;;chieve -;; ee.rn.nn.e.rcial operation after 2028 are
found OnrExhibit R_S pplernent-,i 2029 and Later Bid Requirements.
1PC holds (or expects to es further information
on the transmission Fights on vaFieUS paths*"^+ee ld be used {^.r and delivery points for either type
of bid. Any information regarding transmission paths or available transmission capability is as of
Feseurces to support bids.These Fights aFe lusted in EXHIBIT E-Prepesed Market Purchase
" -,.the date of this RFP; up-to-date information is available on the Open Access Same-Time
Information System (OASIS). As part of any bid submitted, a Bidder must indicate whether er not the
bid is contingent on delivery of energy across transmission rights controlled by IPC.
he bids will be "^evaluated by a team of IPC staff and retained consultants with
relevant subject matter expertise (Evaluation Team` and be Feyiewed by an independent,,.,-,lWateF (19)
Sn T).
Page 3

i
The process of issuing and responding to this RFP, evaluation and selection of bids, and the
negotiation and approval of the agreement(s), is known as the Solicitation. Bidders wee are interested
in participating in the Solicitation and submitting a bid must first register via the third-party
solicitation portal, Zycus, fuFther described in Section 2.76 of this RFP.This RFP sets forth the terms
and conditions by which IPC will perform the Solicitation.The Bidder agrees to be bound by all the
terms, conditions, and other provisions of this RFP and any addenda to it that may be issued by IPC.
This RFP governs the Solicitation and supersedes any other written or oral form of communication
between Bidders and IPC concerning the Solicitation.
2-. ,.12.E CG;11-1 nTnvv C_C-)N T-Ex.T
FmA-.r the .'P'-'C, thos ceuld include, bUt is nn-t Iffirnited te, appreval of a certificate ef public convenience
not reach agreement with the
The Q_.P1_1C_ has rules on competitive bidding fer reseuFce acquisitions, where a company seek-s
to acquire reseurces or r_-A_.ntrac_-ts v.fffith a duration grp--Atp-.r than five years and a quantity greate.r than
R'
2.4. IPC SELF-BUILD RESOURCES ^NO RENGunan vK RESGO RGE-5
In addition to bids from Bidders, a separate team of IPC staff and retained consultants (Internal Bid
Team) may submit Resource--Based Proposal(s) in response to this RFP (°^^ ;(IPC Internal Bid).
The Evaluation Team will treat the Internal Bid Team as a Bidder.The Evaluation Team will subject any
Ben IPC Internal Bid from the Internal Bid Team to the same requirements, evaluation
methodology, and other standards specified in this RFP for a bid from a third-party Bidder.
Furthermore,the Evaluation Team and the Internal Bid Team must comply with an IPC Standards of
Conduct Protocol (Separation of Function)to ensure the Evaluation Team functions independently
from the Internal Bid Team, does not provide access to any non-public information or undue
preference to the Internal Bid Team, and provides the Internal Bid Team and Bidders equal access to
non-public information related to the competitive bidding process for new generation resource
procurement.
" Rpnr-hmarl(An IPC Internal Bid may include a bid for a self-build project to be owned by IPC and will
be subject to the requirements described in this RFP. " rkAn IPC Internal Bid may also include
partnership arrangements or agreements between the Internal Bid Team and third parties that may
collaborate to submit a joint R.Pnrmhmark Rid ExhibitomBenchmark Rids deseriber thne.. �"ri a`,
^+.-that ^ he Y,.,,1^ a0.lahi^r ^ ,.ti ^f the third pa Ft„ BiddeFS IPC Internal Bid.
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i
1PG's BeRchmark BAs wil be submitted to the IF RO later than seven (7) days prior to the epeRing of
bids 4em the market (Third Party Bidsy Third Party Bids shall RE)t be opened URtil the IF a
Ev&ua&eR Team have reviewed, evaluated,validated, and scered any and all Benchmark Bids.The
BeRchmark Bid SCEnes VA.! be assigned using the same scoring and evahaheR crileria that"Al be used
to s e Third Party Bids
Market Purchase Ve'UMes and requests Market Purchase Proposals that NO
traRSMKSieR rights.
►n►n-PPENBcn►T cvn► ►►n rnv
OPUC Cempkitive BWdkg RuNs and that aH bids are evabated consistently and impartially.The A
deve4eped by IPG and tied with the QPUC and GeRSU't With 'PC on ehaRges to th
-,r„
• The A YAW participate On werisheps concerning the bled draft RIO and SMM, and Feview��
by G)P I(•S44 and ethers e g the DCD
• The A YAH also review stakeholder comments, provide feedback, and Suggest medi
be draft DCD prior to IP?s Ong of the final DCD with the G)P I('
• Prier to receipt of BeRehma? Bids and Third Party Bids,the IF will review the assurnybess-A
be used by IPC in its quaRtitative eva4uatieR of the bids, ORG'UdiRg these feF its
capacity expansion and pOdUGAR Go-St?MUKAORm
• The IF YAM prepare and WKS to the QPUC an assessment of the draft RIO (1E DFa
hhRg of the RFP with the QPUC for approval.The IF Draft RFP AssessmeRt Report and IF RFP
Assessment Report shall review the adequacy, accuracyj and cempleteRess of all solicitation
materials to ensure CeMpliaRee VAN the QPUG competitive bidding mquiremen
eensisteney with a r, e d ind ustry standards and r, aeti-.,s
• The A shaN seem the Third Party Bids and f4e the eemespeRdbg Se
the QPUG, As desuked Win, WC YAH subm4t BeRehmark Bids, and the IF Will
scere the Benchma? BWs and Me seems with the QPUC prier to opening and sce-riag-K
C)AR 460_099 0400(S /h) and fHe a ritter, a r,t VAN the Q If'
• After !PC's selection of its FiRal Shertifs, the IE shall prepare the C1eSiRg Repert, whi
reasons and basis for 1P?s evaWatien and sebetien pFeeess including: 1) FaRkiRg Benchmark
Page 5

i
_a.n.d Thi.rd-Party Bids; 2) selecting and scering Benchmark and Third Party Buds; and 3) Fejecting
Q.,nPhrn;;rl. -,n.d Thir.d_Part. Bids
The QPLJC may require the IE te meniter IPC's negetiatiens;.vith bids Selected te the Final
Srrvrcri-sue
X&2.5. CONFIDENTIALITY
Bidder acknowledges and agrees all information obtained or produced in relation to this RFP is
the sole property of IPC and shall not be released or disclosed to any person or entity for any purpose
other than providing a bid to IPC, without the express written consent of IPC. Bidder agrees not to
make any public comments or disclosures, including statements made for advertising purposes,
regarding this RFP to the media or any other party without prior written consent of IPC. Bidder shall
forward any media or other inquiries regarding this RFP to IPC.
Bidders shall specifically designate and clearly label any bid material(s) or portions thereof,that-the
Bidder deems to contain proprietary information as "CONFIDENTIAL." IPC reserves the right to release
all bid materials, including those marked "CONFIDENTIAL,"to its affiliates and its affiliates' agents,
advisors, and consultants,for purposes of bid evaluation. IPC will,to the extent required by law,
advise each agent, advisor, or consultant that receives such claimed confidential information of its
obligations to protect such information. All information, regardless of its confidential or proprietary
nature, is subject to review by the Commissions and other governmental entities and courts with
jurisdiction,and may be subject to legal discovery.The Bidder acknowledges and agrees, IPC w+4may
provide a copy of the Bidder's materials to the Commissions and IE for review and compliance with
this solicitation. All Bidders whose bids are advanced to+h., In;+;-,I Sher+lir+negotiations will be
required to execute a Mutual Nondisclosure and Confidentiality Agreement(Confidentiality
Agreement) in the form of EXHIBIT KExhibit G—Mutual Non-Disclosure Agreement with IPC prior to
further discussion and evaluation of the bid by IPC.
2.,X2.6. SOLICITATION PORTAL AND RESTRICTION ON
COMMUNICATIONS
IPC has opened a web-based portal hosted on the Zycus sourcing platform (the Portal).The web link to
register within the Portal is zsn.zvcus.com/guest/genericRegister/IDA822.-Once registered,
instructions will be provided within the Portal to guide Bidder'sBidders on how to upload documents.
All information exchanged between the Bidder and IPC concerning the Solicitation must only be via
the Portal from the time the Portal is open until it is closed by IPC. All information, including pre-bid
materials, questions, and IPC's response to questions,will be posted in the Portal or on the Idahe
PeweFIPC website (public information) at idahopower.com/about-us/doing-business-with-us/request-
for-resources/.The Portal allows a Bidder to see only its own information and not the information of
other Bidders.
IPC has the chility+^can communicate with Bidders through the Portal. Other than written
communication through the Portal, Bidders are prohibited from communicating with IPC employees,
representatives, staff, or board members regarding the Solicitation during the period in which the
Portal is open. Restricted communication includes, but is not limited to, "thank you" letters, phone
Page 6

i
calls, emails, and any contact that results in the direct or indirect discussion of the Solicitation and/or
submitted bids.Violation of this provision by Bidders or their agents may lead to disqualification.
The Bidder is responsible for ensuring it has registered for, and posts documents to,the correct portal
hosted by Zycus.The Bidder registering for access to the Portal must be a representative of the Bidder
and counterparty with which IPC will engage in any future negotiations, and not consultants or
attorneys for the Bidder.
To ensure a competitive bid process, Bidders must not disclose its participation in this Solicitation
(other than by attendance at any meeting held by IPC with respect to the Solicitation) or collaborate
on or discuss with any other Bidder or potential bidding strategies or the substance of any bid(s),
including and without limitation, the price or any other terms or conditions of any bid(s).This does not
preclude parties from partnering in good faith to submit a competitive bid.
Questions or support needs regarding the Portal should be directed to:
[e-mail]. Any questions that are relevant to all Bidders will be provided in
response through the Portal.
2.4�.2.7. SCHEDULE
The key milestones for the Solicitation and their currently scheduled dates are provided in Table 2 1
belewJable 2-1.
Table 2-1—. Key Milestones for the Solicitation
No. Milestone Date
1 Draft RFP Filed with opucfor Regulatory Approval 2/29/202420 2026
1)154ibwte DFA AS RFP �T
2 PFeliminafyBiciclers Submit Bid Definition Forms Due(Notice of Intent) 7/0�4 10 2026
3 Approval of 2032 AS RFP 4 24 2026
4 Final AS RFP Released 4 27 2026
5 °FyBid Entry Forms Distributed to Bidders 7/�224 29 2026
Approval of 7078 AS DCD Q/9 Cv2vzT
oRal DCD nip+rwh-,+,.,J+o naa,k,4 o/�chmn
o7"r'o7'i'oz
6 Last Day for All-Source RFP Questions Q/�245 13 2026
Updated Bid Definition Forms Due(if applicablo o/2 hn2n
7 Benchmark Bids Due 9/23/20245 29 2026
Updated Bid Entry Forms Distributed to BiddeFs(of applicable) o/27hn7n
for Q.,..,-t,....-,.1,Rid Eyalwat* Rs o,...,..+ 828/7924
Page 7

i
No. Milestone Date
it Completes Reply Comments on Benchmark Bid 9/16/2024
T-h!Fd Party&ds Due 946c 2024
�7"i'c7'i'c'rt
Open AS DCD Rid,; 9/97 2024
�T
8 Bid Eligibility Screening Completed 9/2�T6 10 2026
IC Submits Report en Bid Eligibility Scr...niR.. 9/30/2024
�T
9 Initial Shortlist 10/11/2024
6 26 2026
it Completes Review and Submits Report Of'Ritial Sh rtert !I/i 2024
�T
10 IPC Notifies Bidders Selected to Initial Shortlist ,,/�T6 30 2026
11 Final Shortlist Priee/Preduction Update /„/ - 17 2026
WC Res Request F r Ackne..,i edge.nent F Pnal Sh rt i art 1/10/202
12 IPC Notifies Bidders Selected to Final Shortlist ,/=,ig�2-G�Z 31 2026
13 IPC Begins Preliminary Contract Negotiations ,/=,iB�2-G�g 17 2026
14 Contract Execution 3/1�-510/31/2026
15 WiRRORg Bid Guaranteed Commercial Operation Date Bee Fe Sum..e
2@2-gM2L 31.
2031 2032
This schedule and documents associated with the Solicitation are subject to change. IPC will endeavor
to notify Bidders of any changes to the Solicitation but shall not be liable for any costs or liability
incurred by Bidders or any other party due to a change or for failing to provide notice or acceptable
notice of any change. Bidders should factor this schedule, and any changes thereto, into their project
development timelines and bids.
Bidders should carefully review this RFP for questions, clarifications, defects, and questionable or
objectionable materials. Comments and questions concerning clarifications, defects, and questionable
or objectionable material must be submitted through the Portal and must be submitted on or before
the date and time specified in the above schedule. IPC may not respond to questions submitted after
this date.All questions and their applicable responses will be provided to Bidders via the Portal.
2.8. ANNOUNCEMENT PLAN
The draft RFP, and the filing for regulatory approval serves as the Announcement Plan to prepare for
the release of the Final RFP. Bidders should review the RFP in its entirety with a particular focus in this
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Section 2 to ensure anticipated communication and Final RFP release information is understood.The
RFP is posted to IPC's Request for New Resources page at idahopower.com/about-us/doing-business-
with-us/request-for-resources/.All Bidders who register according to Section 2.6 will also receive the
RFP and applicable exhibits and workbooks for inclusion and participation.
3. Proposal Specifications
A bid must demonstrated the specifications stated in this section are satisfied.
3.1. ELIGIBLE PROPOSALS
The proposals eligible to be bid in response to the RFP are aligned with two types of electric energy
and capacity products.
The first type, Resource--Based Proposals, are unit-contingent energy and capacity delivered from
electric resources that support the 20232025 IRP capacity and energy needs, as those capacity and
energy needs may be updated during the course of this RFP. All pFepesed Resource--Based Proposals
must be located within the IPC Balancing Authority(BA) area or demonstrate transmission rights to
the IPC BA. Additional requirements for Resource--Based Proposals are found in Section 4.
The second type, Market Purchase Proposals, are firm energy(preference for WSPP Schedule C or
equivalent)that meet the eligibility requirements of the Western Resource Adequacy Pregram (WRAP)
.WRAP for qualifying
contracts.Additional requirements for Market Purchase Proposals are found in Section-5.
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Table 3-1—.Resource Based Proposal Scope Summary
Scope Item Description
Ownership and Asset Purchase Agreements (which may include Build-Transfer Agreements
Agreement Types (BTA)) —Asset acquisition of the proposed facility and related assets,
where the Seller assumes development and construction risk.
Power Purchase Agreements (PPA) — Power purchase for energy, capacity,
and all environmental attributes from a facility.
Asset Purchase n..r....ments (which nq inelude Qu-i'd Transfer n.,r..,,r.-.. nts
�oTrcs ,
h v�p+I,�� C II development, +r� tier d f' L
YPITeTi C1'YlZ�CT eI-CTJjQITfeT ' 'fC�I"fJCTCI CCT� I"fGTTSITTC.
Battery Storage Agreements (BSA) — purehasePurchase of capacity and the
charging/discharging of a standaleneenergy from battery faeilityfacilities.
Any hybrid proposals that include multiple resource technologies co-located
utilize using the same point of interconnection will also require operational
agreements that establish protocols related to scheduling and dispatch
(for example solar+B S-S4battery energy storage system (BESS)).
Term IPC is not prescribing a specific term requirement but prefers terms consistent
with the life of the asset.
First Delivery 9n A_.r befeTeApFil1, 2028�112C well aeeept,satege;Tze, and evaluate preJects
.,i+h later first deli. eFy dates -,r,.J v ,ill .deter. .i.ne n. eds h.,.,eRd+herM M P r A
2928 as deseri-hed in € it R SupplerneRtal 202-9
RegUir^r. ents' Between April 1 and May 31 of the respective year(2031 and
2032 .
Resource Status Existing (which can deliver incremental capacity that is not otherwise already
contracted with IPC) or proposed new late-stage development with pending r
executed LGIA/SGIA.
Peak G..par;ity and For dispatchable generation (e.g., storage and gas-fired generation)to be
€neFWgji patch dispatehe L IPC fer itswill have the right to dispatch the facility across the
Rights full range of the proposed capacity(0-100%), contingent on the capabilities of
the generator(e.g., minimum dispatch level, ramp rates)
Interconnection IPC Transmission System or Non-IPC Transmission Systems with all necessary
transmission rights to the IPC BA area
Delivery Point Within the boundary of the BA, or outside with all necessary transmission
rights to the BA
Other gidslf the facility generates environmental attributes, bids must include all
environmental attributes, including Renewable Energy Certificates (REQ.)f
any. Bidders will be responsible for ensuring RECs are bundled, and that they
are established through Western Renewable Energy Generation Information
System (WREGIS).
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Proposed pricing for Asset Purchases shall include Operating and Maintenance
(O&M), Long-Term Services Agreement (LTSA), and warranty costs for the
proposed term.
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Table 3-2—. Market Purchase Proposals
Scope Item Description
Contract Structure Agreement for purchase of firm energy and capacity(prefer WSPP
Agreement Schedule C or equivalent) meeting Western Res •�^
Adequaey PFegFam (WRAP4 eligibility requirements,, inelud`ng
FeseWee eifieity,tFan,-missio and ether r nts for
qualifying contracts. Agreement may take the form of a confirmation
under a mutually agreeable master agreement (e.g.,WSPP or other),
or a mutually agreeable standalone agreement. C^^ Exhibit E
PFE)Pesed Market Purchase Velumes.
Term IPA' iS Ret ^ rihing eifie ter. . r nt but prefers 3 years
or more preferred.
Delivery Months Either or both summer(June—September) or winter(November—
February) preferred. IPC will consider other proposals.
First Delivery On r h.,f.,r., Aril 9 2029 (IPC will accept, .--,+egeriz and evaluate
hi.Js ,.,i+h later,d-t e s -,.,.d , ,ill ,d +.,rrnine r e d s h,,.,en d+he
of 2029 as applic A Between April 1 and May 31 of the respective
year(2031 and 2032).
Pricing Index-based preferred, but IPC will consider other proposals. Pricing
should not include costs of regulatory structures not applicable in
Idaho or Oregon and should be based on a product with sinking in
Idaho or Oregon.
Peak Ga ri+••product C,,,, C..hihi+ E PFep se d nA-.Fket P urehas V l mesCapacity with
callable energy. Prefer flexibility to shape energy deliveries and
quantities into specific days or hours. IPC will consider other
proposals.
Energy See Exhibit CProposed nA-,rL.,+ D,1rr-h VAI,imp,;
Interconnection IPC Transmission System, or Non-IPC Transmission Systems with all
necessary transmission rights to an eligible Point of Delivery as listed
Delivery Point Delivery to an eligible Point of Delivery as listed in Exhibit E-
PFep,,se d Marl..,+ Nur,-hase Velum es—Transmission Paths and
Delivery Points.
3.2. ALTERNATIVE PROPOSALS
IPC may also accept other proposal types that meet the ewners_hpintent and electrical functionality
criteria outlined in this RFP. Bidders who submit a proposal not specifically identified in this RFP must
fully describe how their bid can meet the general desires and intent of the RFP. Proposal types that
are not eligible include but are not limited to; energy or capacity that is not electrical (e.g., thermal
energy storage without conversion to electric energy); renewable energy credits without the
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associated energy(Unbundled RECs); and financial instruments used to mitigate variable cost
exposure without associated energy or capacity(Financial Firming).
3.3. TRANSMISSION ALTERNATIVES
As part of IPC's integFated Resource DlanIRP processes, in addition to supply-and demand-side
resources, IPC is directed to give equal and balanced treatment to transmission resources.Therefore,
IPC will also accept bids for transmission ownership, service, or long-term rights that may meet energy
and capacity needs identified above.
4. Resource—Based Proposals: Additional Specifications and
Instructions
4.1. MINIMUM REQUIREMENTS
IPC has specified minimum requirements for participating bids (the Minimum Requirements)for
Resource--Based Proposals.These requirements are listed in€XH+BI Exhibit C-Bid Eligibility Checklist.
^{+^r 'F rpwopuf And rensultatiOR, ^ ^Non-conforming bids will be notified and givell the 0PP0FtURitW
to eei:Feet their hop]wmthm
business days; etherwise,the hop] will he disqualified and removed
from censoderatwe.n. Consistent y.futh n-AIR R-6-n- C)89 0400(2)(e), non price score criteria that seek to
Req irem^ further evaluation.
4.2. DELIVERY AND RESOURCE STATUS
IPC prefers bids from resources with proof of generator interconnection status and ability to deliver,
such as a pending or executed Generation Interconnection Agreement(LGIA or SGIA), progress or
status of the interconnection study, and/or understanding of contingent queue projects that may
hinder deliverability.
4.3. 10o141Acvcu112 n AID AGREEMENT TYPES
As reflected in the-Table 3-1 , Bidders are encouraged to offer bids under any of three
dofferomidentified structures: 1) a PPA with exclusive rights for IPC to any and all capacity and
environmental attributes associated with the energy generated, with IPC having full commitment and
dispatch control of dispatchable resources; 2) an asset purchase,which may include a Q,,;'r T,-.,^rf^,-
-(BTA)whereby the Bidder develops the project, assumes responsibility for construction,
but ultimately transfers ownership of the asset to IPC or an agreement for the purchase of an existing
asset; and 3) a Battery Sterage A reement 4BSA)with exclusive rights and dispatch control for IPC to
the capacity and the charging/discharging of a standalene battery. PeF °,�PPA bids, IPC prefers term
lengths that match the life of the asset wthat will help in cost comparisons between Bidders.
However,thp-tp-.rrn A-f the PPA is Ret a weighted seere and vWill net advantage or disadvantage the bid
epeFatien by April 1, 2028, E)F existing Feseuicees with remaiRiRg q_pt loft-that 7
are net alreadw
seRtracted ydwth IPC fer deliveFy afterl 1, 2929.
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Bidders are encouraged to eORf+gUrepropose resources tothat maximize energy delivery and flexibility
to support IPC's needs during hours that are most valuable to IPC. Information concerning the hours
that are most valuable to IPC can be found in Appendix Q of IPC's 2023 IRteg aced Resource 2025
IRP, starting on page 9213.
Bids for new resources (a Project)to be owned by IPC must assume the parties will execute a BTA.
Under a BTA,the Bidder is responsible for all aspects of the development and construction of the
Project, including but not limited to, permitting, design, development, engineering, procurement,
construction, interconnection, and all related costs up to achieving the to-be-agreed upon milestone,
which will not be earlier than mechanical completion or later than the date the Project is placed into
service for tax purposes.After reaching the milestone,the Bidder will transfer ownership of the
Project assets to IPC in exchange for a purchase price. Bids that contemplate the transfer of 100%
equity interests in a single-=member LLC are acceptable.After purchase,the Bidder will remain
responsible for the completion of the Project pursuant to a Construction Completion Management
Agreement. agreements,
of the °r, ect d,yel pmeRt nstructie and . rats R phases. IPC may elect to enter other types of
agreements proposed by the Bidder, including an Engineering Procurement Construction (EPC)
agreement, operation and maintenance service agreements, or other arrangements that generally
achieve the desired results.
Bids for existing resources(a Plant) not delive 4ggalready contracted to deliver to IPC after Apr+l1,
242-gMay 31 of the respective year,to be owned by IPC, must assume parties will execute an asset
purchase agreement and an O&M agreement.
te EXHIBIT A.A — Draft PA-P.m. A-f fer refereanc--e. In sueh eases that the Bidder is ,
diffiscretoe.n. Biffirdr-1per-;hall deliveF the required letter ef. c.redit n.A- I.-Ater than 30 days following any such
notice of awaFd.
PPAs are contracts where IPC purchases all electric power generated by a facility at a set contract price
over the term of the agreement.The Bidder is responsible for permitting, design, development,
engineering, procurement, construction, interconnection, and all related costs up to achieving the to-
be-agreed upon commercial operation date.The Bidder will maintain ownership, operation, fuel
supply requirements, if applicable, and compliance of the facility through the contract term.All
environmental attributes associated with the electric generation will be for the benefit of IPC.
A BSA is similar to a "rental" agreement where IPC pays a fee to the Bidder over the term of the
agreement in exchange for the production and power generation to the benefit of IPC.The Bidder is
responsible for permitting, design, development, engineering, procurement, construction,
interconnection, and all related costs up to achieving the to-be-agreed upon commercial operation
date. After commercial operation,the Bidder maintains ownership of the facility and is responsible for
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maintenance and compliance through the contract term. IPC will provide the energy to charge a
storage facility in exchange for full dispatch control and ownership of the power generated. All
environmental attributes associated with the electric generation will be for the benefit of IPC.
Beginning at execution of the applicable agreement, the Bidder will be required to post cash collateral
or a letter of credit in the amounts specified in the applicable agreement and commensurate with the
purchase price or contract value (e.g., 10-20%of purchase price during the construction and post-
construction period under a BTA).
4.4. INTERCONNECTION STUDIES AND COST ESTIMATING
The Bidder is responsible for understanding the IPC Generator Interconnection Processes or other
Transmission Providers — including surplus interconnection service — considering the durations and
costs of those processes in its bids, and successfully executing those processes to achieve coordination
with IPC and delivery of the proposed resources to IPC on or before the dates identified in its bid.
A Bidder proposing to interconnect a resource on to IPC's system must demonstrate it has submitted a
Generator Interconnection (GI) request and us rneetlngMeets the requirements of the GI request
process, and that all known incremental costs to deliver energy from the resource to IPC's load have
been included in the bid (including the ^+^r^^,,^ +;^ facility types and rest estimates def r^,�
below). . Similarly, a Bidder proposing to interconnect to another Transmission Provider's system
must demonstrated it has submitted a GI request and any required transmission service request(s)
to the relevant Transmission Providers and that it is meeting the requirements of those processes.
this-R€P
The Transmission Provider function within IPC, separate and apart from the Evaluation Team,
performs studies for GI application requests.The studies are performed to determine the feasibility,
cost,time to construct, and injection capability for the interconnection of an electric generating
resource. Information concerning GIs can be found on IPC's website at Generator Interconnection —
Idaho Power, including information on Public Utility Regulatory Policies Act of 1978(PURPA) Qualifying
Facility(QF) interconnections, Non-PURPA GIs, and Facility Connection Requirements. IPC posts the
results of these studies on its Open AEsess Same Time Information System (OASIS}website.
Bidders must provide the GI request identifier(s) (the queue position) associated with its resource in
its bid. If the resource identified in the bid was in the queue but has since withdrawn,the Bidder
should provide that queue position even though it is no longer active.
The interconnection facility types and cost estimating Feq irements are specified below.
Interconnection Facilities
0 Interconnection Customer's Interconnection Facilities (ICIF) are all facilities and equipment
(including the generation tie line) located between the resource and the Point of Change of
Ownership. Bidder must submit resource-specific cost estimates of ICIF as part of its bid and
consider the cost of ICIF in its pricing.
• Transmission Provider Interconnection Facilities(TPIF) connect the Interconnection
Customer's Interconnection Facilities to the Transmission Provider transmission system and
facilitate the metering, relaying and communications, etc.TPIF are all facilities owned,
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controlled, or operated by the Transmission Provider from the Point of Change of Ownership
to the Point of Interconnection.These are facilities that the Transmission Provider will own,
and the Bidder will fund.The Bidder must submit resource-specific cost estimates of TPIF as
part of its bid and consider the cost of TPIF in its pricing. In the absenGesabsence of an
estimate, IPC will develop an estimate based on the i^f^r"'a+ien Y eyed^d in T""l^ ^ , -heleyV
or ether available information. If an interconnection study has been performed by the
Transmission Provider that includes an estimate of TPIF,then the costs from that study should
be used i^ ';^„ ..f these estimates.
Tahip 4-1_Cs+i.. atpd Cnl;t far TDIC
Voltage TPIF Estimated Gent(2023 $ 990s)
13$ 14 $3,008
345 ham` $5,008
Network Upgrades
• Station Network Upgrades (SNU) are either new switchyards or additions to existing
switchyards or substations that are built to interconnect the generator to the IPC transmission
or distribution system. SNUs become a component of the integrated IPC transmission or
distribution system and are incorporated into IPC tariffs. Bidders are required to provide cost
estimates of SNUB.
• Delivery Network Upgrades (DNU) are upgrades to IPC's transmission or distribution network
that will be required for individual resources and groups of resources.These upgFa es will be
^Fated i^+^ 1D'"s_DNUs become a component of the integrated IPC transmission or
distribution system and are incorporated into IPC tariffs. Bidders are required to provide cost
estimates of DNUs.
Based on information available from the GI request and/or studies and estimates performed by the
Transmission Provider(s), separate and apart from the Evaluation Team (if available), the Evaluation
Team will determine bid-specific SNUs and DNUs and associated reimbursable costs to include in the
evaluation of a bid.The Evaluation Team's development of bid-specific SNUs/DNUs does not take the
place of the IPC Open Access Transmission Tariff(OATT) GI and transmission studies;and does not
remove the Bidder's obligation to submit GI or transmission requests to the Transmission Provider(s).
With respect to transmission service, for resources that will be owned in full or in part by IPC or for
which IPC will have an executed contract for the purchase of the generation, IPC anticipates that-it will
designate the resource or executed contract as Network Resources of IPC under the OATT upon
commercial operation of the resource or first delivery date under the contract. Projects that are
seeking to interconnect to IPC's system aa^d h, �^ ^^+ req este 'must request Network Resource
Interconnection Service (NRIS) m ay n ed addi+ie naI cents - H,_^,_ +^ acce .,+f^r-ad-H_iti E)n a 1 , pgra
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4.5. BID SUBMISSION PROCESS
A-The Bid Package is considered the aggregate of the information upleadedprovided by a Bidder to the
o^rtal The Bid Package and will include data entered into forms on the Portal and subse^u^^*' , data
uploaded to the Portal by the Bidder-ate, including other written documents that are uploaded to the
Portal (Information).The Portal is designed to accept*most of the Information as data
entered into the forms with data entry restricted to only certain eligible types and values.The purpose
,s te ensu,zThis ensures Information is entered consistently across all Bidders and bids such thatso IPC
can consistently,fairly, and quickly organize the Information, evaluate the bids, and minimize the
amount of written (e.g., PDF, .docx) documents that IPC must review and interpret.
i Bid Definition Form and Selectable Portfolio
Any potential Bidder interested in participating in the RFP must first register in the Portal.
Once registered,the bid submission process begins with completion and submission to IPC of
an€XH+BI Exhibit A—Bid Definition Form (BDF) located in the Portal for each bid that a Bidder
intends to submit.The BDF request-sincludes preliminary ' information about the
bid(s) and associated resources including a narrative description and basic bid parameters.
Within the BDF, a Bidder may identify bids that include two or more resources,that if
executed by IPC together, may result in a lower total price or greater benefit to IPC than if the
resources were not transacted on together(Selectable Portfolio). An example of a Selectable
Portfolio is a solar resource, wind resource, and a storage resource where the Bidder would
not offer or contract any one of the individual components, but rather all three are
contingent.Another example is a 100 MW solar PPA bid and a 100 MW solar asset purchase
bid from a 200 MW solar project. If a Bidder desires to combine, or make contingent, multiple
bids of various structure, ownership, term, or resource types,then the Bidder will indicate
within the BDF the combination of bids that make a Selectable Portfolio. A Selectable Portfolio
will be evaluated as a complete bid such that if it were selected,the entire Selectable Portfolio
would be reviewed for further evaluation. Only the submitted bids will be evaluated
throughout the RFP and it is the Bidder's responsibility to detail the parameters of such. IPC
will not accept additional "options" after the bid due date and during the evaluation.
ii Bid Entry Form
IPC will review the submitted BDF and subsequently respond to the Bidder with an
€XH+BITExhibit B—Bid Entry Form (BEF)that is relevant to the bid(s).-h including a unique "Bid
ID" number for reference.The BEF requests complete technical, commercial,financial, and
pricing Information for purposes of subsequent bid evaluation. IPC will provide each Bidder
with Bid Fee instructions to accompany the BEF.
iii Forecasted Hourly Renewable Pre-d-u-c-tion Te''plategg ut
In addition to the BEF, IPC will provide EXHIBIT QExhibit K — Forecasted Hourly Renewable
o * ^ T^,,..plaLe-Output that is relevant to the bid(s).-The Forecasted Hourly Renewable
o ^d etie T^,,..p4t-eOutput will provide the format for the hourly forecasted P90 and P50
energy production profiles of any proposed intermittent renewable resources. Failure to
provide this exhibit may result in disqualification of the bid.
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iv Bid Submittal
Bidders will submit the BEF, Forecasted Hourly Preductien TemplaLeRenewable Output, and
ancillary Information as defined in the RFP to the Portal.The BEF requires certain cost data as
inputs to the price score model.Any bids that are incomplete or do not meet the minimum
requirements will be deemed ineligible and removed from further evaluation.
He Orly Reny .,-,hIp Dreg ctien Template .,h r these fer., s a pFevided to the Bidder.
Bidders are strongly advised to carefully review all exhibits relevant to their bids prior to uploading a
Bid Package to the Portal. If and when a Bidder is selected for negotiation of an agreement, IPC will
reuse the Information submitted in the Bid Package to populate the relevant portions of the
agreements for that Bidder.
4.6. EVALUATION FEES
A Resource--Based Proposal Bidder is required to submit to IPC a non-refundable fee with each bid
submitted (Evaluation Fee).The purpose of the Evaluation Fee is to encourage submission of
well-developed and viable bids and to offset the cost to IPC for evaluation of bids. For each bid
submitted,the Bidder may submit a sub-bid at a reduced Evaluation Fee as described below.
Bidders must use the following guidance for the purpose of determining and submitting the Evaluation
Fees, due with each bid and sub-bid.
Bid Fee Example
A single site and resource type $9,9-2-910,032 Site Alpha, 200 MW Solar PV, PPA, 35-yfyear
(can include multiple structures, and
terms, and price) Site Alpha, 200 MW Solar PV, Asset
Purchase
Same site and resource type but +$4�645,016 Site Alpha, 400 MW Solar PV, Asset
different capacity or initial delivery year Purchase
Different site = different bid $�910,032 Site Bravo, 150 MW BESS, 20-yfyear, BSA
Different resource = different bid $9-,Kg10,O32 Site Alpha, 300 MW Wind, Asset Purchase
unless the different resource is part of, (different bid = $9-,KS10,032)
and required, as part of the or
Selectable Portfolio Site Alpha, 300 MW Wind, Asset Purchase
contingent on Site Alpha, 200 MW Solar PV,
PPA, 35-yryear as a Selectable Resource only
(not a different bid)
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IPC may deem a bid that does not satisfy the requirements for a single bid as multiple bids, each of
which would require a separate Evaluation Fee. If IPC deems a Bidder's bid to be multiple bids, IPC will
notify the Bidder and allow the Bidder to elect to pay the incremental Evaluation Fee or to revise its
bid to comply with IPC's requirements for a single bid.
4.7. EXCEPTIONS TO THE DRAFT FORM AGREEMENTS
Bidders must provide bids and pricing that are consistent and compliant with€XHIBI Exhibit F—Draft
Form Agreements and Term Sheets for Resource Based Proposals.To the extent that the validity of a
Bidder's bid and/or the Bidder's ability to execute an agreement is contingent upon material changes
to the language in the draft form agreements,the Bidder should specifically identify the terms they
propose to change in the form of a redline markup or issues list and submit the redlinerevisions with
its bid.To the extent that a Bidder wishes to propose changes to the draft form agreements that, if
accepted by IPC,would reduce the Bidder's proposed pricing the proposed changes should specifically
identify in the redline or issues list, such changes and the associated price reduction.To the extent
practicable, Bidders should develop exhibits, schedules, attachments, and other supplemental
documents required by the draft form agreements in the redline. Bidders proposing to sell existing
generation facilities should propose in the redline changes to the draft form agreements for the
proposed resource type reflecting the terms and conditions on which their bid is based. Note that not
every technology and contract structure is presented in the draft form agreements and, thus,
proposed contracts and terms should be provided for contracts that are substantively different to the
provided draft form agreements. For a Wind PPA, Bidders should review and redline the substance of
the€XHIBI Exhibit F—Power Purchase Agreement commercial terms with the inclusion of the
FY�TExhibit F—Wind Performance Guarantees.
The proposed changes must be specific and include a detailed explanation and supporting rationale for
jFhe ppoposed changer, mi-1-1 an_ include a detailed and'
General comments, drafting notes and footnotes,such as"parties to discuss"will
be disregarded and not negotiated. Exceptions to the draft form agreements requested by a Bidder
will be reviewed as part of IPC's qualitative evaluation of the bid.
n CY�'CDTIQA15 T/1 TL.IC
offid-deR that pFepese a FP-SA-1--ree fer 'PC ewnership must provide bids and priciRg that aFe
: ;
EXHIBIT 1—�Alwnrd TP-c--hnical Specifications; and EXHIBIT j—Gas Fired C_A_.nvP_r.tih1P W HydFE)geR
Specifieatiens).Te the exte—pt that the validity ef a R_iddle.r's -hid and/eF the Bidder's ability to exeeute
aR agreement is contingent upon material chaRges te the language OR the Technical Specificatiens,
the Bidde.r must specifically identify the specifications it PFOpeses tE) Change On the fA-.rrn A-f-A redIffinP_
FnaFkup to the Technical Specifleation anp-1 S-Uh.m.it the pp-rdline I.A.4th Ots -hod. T-A- the extent that a Bidder
wishes to prepese changes to the Technical Specification that, Of accepted by IPC, weUld reduce the
Bidder's proposed pricing,the BiddeF sheuld speeifleally identify in the Fedline, sueh ehanges -;;nd- the
0 ted price reduction TA thp extent practicable, Bidders should develop exhibits, schedt4es—,
c _ "parties as
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be reviewed as part ef 112C's qualitative &.oal,_,ataA_.n A-f thta hap] NA P that RAt PweFy techneleg
ided fer technelegies; that are si ibstantively different te thp provided technical speGifiGatiens.
prev
4.-X4.8. EXCEPTIONS TO THE DRAFT FORM LETTER OF CREDIT
Bidders thatwho propose a resource for IPC ownership must provide bids and pricing the
consistent and compliant with the EXHIRIT AAExhibit I—Draft Form Letter of Credit.-and
commensurate with the purchase price (10-20%of purchase price during the construction and post-
construction period).To the extents the validity of a Bidder's bid and/or the Bidder's ability to
execute an agreement is contingent upon material changes to the language in the draft form letter of
credit, the Bidder should specifically identify the terms they propose to change in the form of a redline
markup to EXHIBIT I—Draft Form Letter of Credit,and submit the redline with its bid.To the
extents a Bidder wishes to propose changes to the draft form letter of credit that, if accepted by
IPC,would reduce the Bidder's proposed pricing for the bid, should specifically identify in the redline
such changes and the associated price reduction.
The proposed changes must be specific and include a detailed explanation and supporting rationale for
.The pFepesed changes must be speeifie and include a detaHed explanation -;;Ad- SUPPOFting
far each. General comments, drafting notes, and footnotes,such as "parties to discuss," will
be disregarded and not negotiated. Exceptions requested by a Bidder will be reviewed as part of IPC's
qualitative evaluation of the bid.
4.9. TECHNICAL SPECIFICATIONS
Bidders proposing an asset purchase or BTA must provide bids and pricing that are consistent and
compliant with applicable technical specifications standard to the technology bid. Bidders should
submit technical specifications for review by IPC with their bid for evaluation.To the extent the
validity of a Bidder's bid and/or the Bidder's ability to execute an agreement is contingent upon
substantive language in applicable technical specifications,the Bidder must specifically identify the
key aspects of the specifications that have material or substantive price impacts.
5. Market Purchase Proposals: Additional Specifications and
Instructions
5.1. MINIMUM REQUIREMENTS
IPC has specified the Minimum Requirements for Market Purchase Proposals.These requirements
are listed in€XHIBI Exhibit C—Bid Eligibility Checklist. "f*^' 'FE ^d '*^* ^^ ^Non-
conforming bids will be notified and given the opportunity tocerrp-p-t th „- bid within five (5) h„-s,n SS;
days, otherwise,� the bed well be disqualified and removed from c s„l ration C nsist nt with OAR
bid have been converted into Minimum R quir Y,., further evaluation.
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►.2. AGREEMENT TYPES
IPC will consider bids for agreements consisting of confirmations under mutually-_agreeable master
agreements (i.e., WSPP or other), or mutually-_agreeable standalone agreements.
5.3. BID ATTRIBUTES
Additional description of the volumes and bid attributes Id;;h^ °^yf^r < seekin^IPC seeks are
listed in
€XHIBITExhibit E—Prep see M -I,,,+ o,,rc--h-,- )/ I,,m,,,.Transmission Paths and Delivery Points. IPC
anticipates it will designate the resource or executed contract as Network Resources of IPC under
the OATT upon commercial operation of the resource or first delivery date under the contract.
5.4. BID SUBMISSION PROCESS
,-The Bid Package is considered the aggregate of the information provided by a
Bidder+„+h., o rtal.The Bid o-,ek ., and will include data entered into forms on the Portal-a 4
subsequen , data uploaded to the--Portal by the Bidder, including other written documents that
are uploaded to the Portal-(Information).The Portal is designed to accept the tymost of the
Information as data entered into the forms with data entry restricted to only certain eligible types and
values. The p Frew ;s to eRS FeThis ensures Information is entered consistently across all Bidders and
bids such thatso IPC can consistently,fairly, and quickly organize the Information, evaluate the bids,
and minimize the amount of written (e.g., PDF, .docx) documents that IPC must review and interpret.
i Bid Definition Form
Any potential Bidder interested in participating in the RFP must first register in the Portal.
Once registered,the bid submission process begins with completion and submission to IPC of
an€XH+BI Exhibit A—Bid Definition Form (BDF) located in the Portal for each bid that a Bidder
intends to submit.The BDF requests preliminary information about the bid(s) including a
narrative description and basic bid parameters.
ii Bid Entry Form
IPC will review the submitted BDF and subsequently respond to the Bidder with an
E"�TExhibit B—Bid Entry Form (BEF)that is relevant to the bids-), including a unique "Bid
ID" number for reference.The BEF requests complete technical, commercial,financial, and
pricing Information for purposes of subsequent bid evaluation. IPC will provide each Bidder
with Bid Fee instructions to accompany the BEF.
iii Bid Submittal
Bidders will submit the BEF and ancillary Information as defined in the RFP to the Portal.The
BEF requires certain cost data as inputs to the price score model. Any bids that are
incomplete or do not meet the minimum requirements will be deemed ineligible and removed
from further evaluation.
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Bidders are strongly advised to carefully review all exhibits relevant to their bid(s) prior to
uploading their Bid Package to the Portal. If and when a Bidder is selected for negotiation of
an agreement, IPC will utilize the Information submitted within the Bid Package to populate
the relevant portions of the agreements for that Bidder.
6. Additional Requirements for All Bid Packages
6.1. CONTENTS OF WRITTEN BID PROPOSAL
A Bidder MUST prepare and submit as part of the bid a written narrative that fully describes the
bid and any details or nuances to fully explain the intent of the Bidder and the BEF.The narrative
should include a cover letter and introduction, company and project overview,a description
of each bid submitted in the BEF including substantive assumptions, responses to bid eligibility and
non-price factors,and project financing and contract terms according to
Exhibit N—Bid Format and Requirements.
6.2. BID NAMING
A unique name for each badproposal (Bid CedelD)will be provided to the Bidder and must thereafter
be used by the Bidder when referring to the bid and must be inserted into the file name of each
document for the bid uploaded by the Bidder.The purpose of the Bid CedelD is to allow IPC to more
easily identify and differentiate among bids and documents.
6.3. BID WRITTEN DOCUMENTS
Written documents must be text-searchable PDF (portable document format, non-zipped) and must
contain documents reproduced directly from the native document (i.e., Word, Excel, MicroStation,
AutoCAD). Scanned images and documents will be considered irregular and may be rejected.
6.4. RFP EXHIBITS REQUIREMENTS
Exhibits to this RFP summarize the Information that must be included within the Bid Packages and
uploaded by Bidders to the Portal. Bidders are directed to the individual forms in the Portal to ensure
review of all the current information and the specific type and level of detail that must be provided is
understood and are summarized below.+Table 6-1 ar-eincludes the required exhibits that must be
completed depending on the type of contract offered.
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Table 6-1,. Bid Package Requirements
Asset Market
Exhibit Purchase PPA/BSA Purchase
Proposal Narrative consistent with Exhibit N —Bid X X X
Format and Requirements — —
Exhibit B C D—Bid Entry Form X X X
Redlines Issues List to Exhibit F—Draft Form
Agreements and Term Sheets for Resource--Based X X
Proposals
Redlines Exhibit!_ LI I and I (Technical SpeciFieati.ns) X
Exhibit tH —Counterparty Financial Questionnaire X X X
Redlines to Exhibit MI —Draft Form Letter of Credit X X
Dr.,r,esal Narrative c i,s+.,.,+. ,i+h C..hihi+ AI Qirl I_Ae r.,-.-,+ X X
and Re .,+r
Exhibit$--K—Forecasted Hourly Renewable
X X
o.^ +i^ T r, a Output, if applicable
rI„ r,
Exhibit L—Cyber Security Questionnaire X X
Exhibit M—Gas-Fired Resource—Fuel
X X
Questionnaire, if applicable
6.5. FIRM BID
Each bid shall be firm, not subject to price escalation, and binding throughout the schedule of this RFP
from the date the bids are due under this RFP. Note, however,the hid evaluation process does have
an r ertunit y to update pFi,.ir . The bid must include all assumptions that influence the price and
validity of the bid, including, but not limited to tariffs and tax credits. IPC understands that future
changes in legislation and law could impact the validity of a bid. If a substantive change to legislation,
law, or similar has a material impact to the submitted pricing proposal, IPC will seek updates from all
biddersBidders, as applicable,throughout the evaluation process.
6.6. TAXES
Bidders are responsible for the payment of all sales, conveyance,transfer, excise, real estate transfer,
business and occupation, and similar taxes assessed with respect to or imposed on either party in
connection with a proposed agreement.
6.7. DATA AND CYBER SECURITY
A bid must comply with the provisions of Presidential Executive Order 13920 (E.O. 13920) issued
May 1, 2020, titled Securing the United States Bulk-Power System (BPS), which (among other things)
prohibits any acquisition, importation,transfer or installation of BPS electric equipment by any person
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i
or with respect to any property to which a foreign adversary or an associated national thereof has any
interest that poses an undue risk to the BPS,the security or resiliency of United States (U.S.) critical
infrastructure or the U.S. economy, or U.S. national security.
All design and implementation details must follow electrical industry best practices for cyber security
as well as all applicable regulatory requirements pertaining to the security of electric system assets.
Any additional IPC-specific requirements will be addressed during the RFP review and contracting
process, pursuant to E"�KExhibit G—Mutual Non-Disclosure Agreement. Bidder must state that
any and all equipment utilized in the proposed resource will not be procured through an Office of
Foreign Assets Control (OFAC) designated entity or otherwise be comprised of equipment prohibited
for use by electric utilities in the U.S.
PURCHASING RESTRICTIONS/Bidder must provide a written response and associated documents in
response to Exhibit L—Cyber Security Questionnaire of this RFP.
6.8. PROHIBITED TECHNOLOGY AND TRADE SANCTIONS
Pursuant to Section 889 of the John S. McCain National Defense Authorization Act for Fiscal Year 2019
and Federal Acquisition Regulation (FAR) 52.204-25 (Augu4Aug. 2020), Bidder agrees, represents,
and--warrants that Bidde Contractor shall not supply or deliver to fREOwner any"covered
telecommunications equipment or services" as a substantial or essential component of any system or
critical technology of any system.-As defined in FAR 52.204-25(a), "covered telecommunications
equipment or services" includes equipment, systems, products, or services made by any of the
following companies, or any subsidiary or affiliateAffiliate thereof(including companies with the same
principal word in the name, e.g., "Huawei" or"Hytera"): Huawei Technologies Company; ZTE
Corporation; Hytera Communications Corporation; Hangzhou Hikvision Digital Technology Company;
or Dahua Technology Company. "Covered telecommunications equipment or services" may include,
but are not limited to, video/monitoring surveillance equipment/services, public switching and
transmission equipment, private switches, cables, local area networks, modems, mobile phones,
wireless devices, land Iine--telephones, laptops, desktop computers, answering machines, teleprinters,
fax machines, and-routers. "Covered telecommunications equipment or services" do not include
telecommunications equipment that cannot route or redirect user data traffic or permit visibility into
any user data or packets that the equipment transmits or handles.
To the extent that the systems, products, or services to be provided by Bidder under this Agreement
may be procured by WCOwner in support of or to satisfy+RG�sOwner's obligations under agreements
with a federal governmental entity, Bidder further agrees that FAR 52.204-25 (Aug+MAu . 2020---h
except for paragraph (b)(2)thereof—,shall be incorporated by reference into any futuice
agreementthis Agreement and is binding on Bidder, and that Bidder does not use any equipment,
system, or service that uses covered telecommunications equipment or services and will not supply
any covered telecommunications equipment or services to IPC.- Bidder further agrees that, if it
identifies covered telecommunications equipment or services used as a substantial or essential
component of any system or as critical technology as part of any system during contract performance,
or Bidder is notified of such by a -,-"c^^*.r;c*^+Subcontractor at any tier or any other source, Bidder
shall immediately notify IPC and reasonably cooperate with IPC's requests for information.
Bidder shall not in performance of the work use or allow use of, nor directly or indirectly import or
supply to IPC as part of the work, any products, systems, equipment, materials, supplies, or related
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i
software or technology from (whether directly or indirectly): (a) any individual, entity, region or
country prohibited by Trade Control and Sanctions Laws, including the prohibition against imports(i)
from a national or resident of, any country subject to U.S. comprehensive sanctions or similar export
restrictions (e.g., Cuba, Iran, Syria, North Korea and the Donetsk, Luhansk and Crimea regions of
Ukraine); or(ii) anyone on the U.S. Treasury Department's list of Specially Designated Nationals,
Sectoral Sanctions Identifications List or Foreign Sanctions Evader's list,the U.S. Department of
Commerce's Denied Persons List, Unverified List or Entity List, or other export/import control lists; or
(b)for any purpose prohibited by Trade Control and Sanctions Laws.
Notwithstanding any consent of IPC given pursuant to Section 3.23.1, under no circumstances shall
Bidder use any Chinese manufactured unmanned aerial vehicles (drones), including but not limited to
those manufactured by Shenzhen DJI Sciences and Technologies Ltd. or Autel Robotics, in the
performance of this Agreement.
6.9. SMALL BUSINESS AND SMALL DISADVANTAGED BUSINESS
PROGRAM
IPC is committed to the implementation of a Small and Disadvantaged Business Program. It is the
intent of IPC that small business concerns and small businesses owned and controlled by socially and
economically disadvantaged individuals have the opportunity to participate in the performance of
contracts awarded by IPC. Consequently, IPC requests that Bidders indicate their eligibility as a small
business based upon the regulations in Title 13, Code of Federal Regulations, Part 121. If in doubt,
Bidders should consult the Small Business Administration Office in their area.
6.10. INSURANCE
Bidder is directed to the€XHIBI Exhibit F—Draft Form Agreements for Resource Based Proposals for
details concerning the specific insurance requirements that must be met.
6.11. FINANCIAL AND CREDIT INFORMATION
Bidder must provide a written response and associated documents in response to the Counterparty
Financial Questionnaire. Details are further described in EXHIBIT Exhibit H—Counterparty Financial
Questionnaire of this RFP.
6.12. CLARIFICATION OF BIDS
While evaluating a bid, IPC may request clarification or additional information from the Bidder about
any item in its bid. Such requests will be sent via the Portal or via email by IPC and the Bidder must
provide a response the PA-4a' back, respectively, to IPC within five (5) business days, or IPC may
deem the Bidder to be non-responsive and either suspend or terminate further evaluation of its bid.
Bidders are encouraged to provide an alternate point of contact to ensure a timely response to
clarification requests.
6.13. ADDENDA TO RFP
Any additional responses required from Bidders as a result of an addendum to this RFP shall become
part of each bid. Bidders must acknowledge receipt of and list all addenda where indicated in the BEF.
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7. Bid Evaluation, Negotiation and Approval
7.1. THE EVALUATION PROCESS
The bid evaluation and selection process are designed to identify the combination and size of
proposed resources (the Pertfelie that will maximize customer benefits and will satisfy projected
resource capacity and energy needs while maintaining reliability.The portfolio optimization models
used to identify the proposed resources are the same that IPC uses to evaluate proxy resources in the
20232025 IRP (and subsequent IRPs). IRP portfolio optimization process details can be found in t#e
company's most recent 2023IPC's 2025 IRP report iR sect^^Sections 9 and 10.
1 PC will separate and pricruti7--pe bidds that can ceriflearm We m Peet the summer peak in 9-0-28- and desire a
commercial operation date by April 1, 2028, separately from these that ce-crif1mirm t-c mpect- a later
commercial operation. TheSe bopd-,;that ce-Fifirm te Meet _a 1-atel,commercial epP_FatiA_.n rdate �.yffiil be
evaluated Subsequent to these Vhat r=an Meet the Summer peak 2028, as deseri-hp-d- imp F_wha_hm*-R--
Supplemental arid Later Bid RequiFements.
The Selection Plan, or bid evaluation process,is described below.
7.2. PHASE 1 - INITIAL SHORTLIST
Phase 1 of the bid evaluation process includes the screening, evaluation, and ranking of the bids,
including the IPC Internal Bids,to identify a subset that can be advanced tefor further evaluation (the
Initial Shortlist).This includes: 1) bid eligibility screening to ensure conformance with the Minimum
Requirements; 2) price;and non-price evaluation to score and rank bids; and 3) identification of the
t-bids for inclusion in the Initial Shortlist. The bids will be categorized by the commercial
operation date.
IPC will rely on the pricing and ^+"^" hmitted by Bid Information provided within the Bid
Package to screen, evaluate, and rank bids. During this phase of the bid evaluation process, IPC does
not anticipate asking for, nor accepting, updated pricing or updates to any other bid components (with
the exception of updates identified in Section 6.5). However, IPC wfl4 ay contact Bidders to confirm
and clarify information presented in each bid if necessary.
Additionally, if at any time during Phase 1, a Bidder determines its submitted bid is no longer valid,
the Bidder should notify IPC immediately and the bid will be withdrawn from further consideration.
Conformance to Minimum Requirements
Bids will initially be screened against the Minimum Requirements using€XHIBI Exhibit C—Bid
Eligibility Checklist-and �eensuTtteth the 11E. After f€rid EensuTtte, Bidders of non-
conforming bids will be notified and given the opportunity to eerrpr#*"^or hod within five (5) business
days; etherl.Vise,the bid will be removed from consideration.
R-i.d-r- �.ymll -he categorized aS f.A-1.1 A_;.v_r ba-red A-.A. the Bid- Eligibility Checkli-st fe-F further eval-atien and
category:
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Proposals %ha% P FGA-Ae le evil-p- me the preient as apart- of either the ld;ll:e
W-N.A/er GeRer2ter IRterr_taRRen Ceregi St'-w PFeness or the
T r-ans+t,n-nal Cluster study Pref`ess
1. Drer.esals th-,t r et the criteria of th., Q[o r J R deliver by April 1 2028
t,haR Ap T1, 2029
l4epesals that are net a Part of either the 1d_ahe Pe\A/er GAMerater
IRtprcaRRpct6aR Sprial StudyPracar3 ar thp Trat, ti• al cl�lwntw Stud
12i r-ppc and intend to enter the Cluster Study Pre/^eCC in March 2025a
Bid Requirement-s
Price and Non-Price Scoring, Ranking, and Initial Shortlist
Resource Based Proposals Non-Price Score (up to 100 points)
The non-price evaluation rubric for Resource Based Proposals is included in Exhibit D—Non-Price
Scoring Sheet. IPC's non-price scoring model evaluates whether bids are thorough and comprehensive,
whether the proposed resource is viable, and whether the Bidder is likely to achieve commercial
operation by the proposed date. Bidders must provide documentation, representation,warranties,
and other information as necessary to sufficiently assure IPC that any proposed project will complete
construction and achieve full commercial operation by the defined commercial operation date.The
non-price rubric is designed to be objective, intuitive, and self-scoring. Bidders are required to score
themselves by answering each of the non-price questions and providing supporting documentation.
Afte.r the ellagibility SC-Feening has been eempleted, eE)nfOFFn*ng bids miill be evaluated and given pFice
A maximum of 75 peints -;;rp- -alle-c-ated to price scoring and a maximum of 25 points to nOR price
technology group, and the highest scoring buds within each technelegy greup are r-.hA--,;P-.n te be the
Imiti-;;1 She.rflist. Rp--;;,-;A-.n-;;ble excess te, at a minimurn, meet the identified capacity and energy needs
spe
eifaed. ,ill ht.,The non-price questions are utilized to score and rank bids based on, among other factors,the
completeness of the Bid Package and adherence to the bid requirements,the ability to contract with
the project,the maturity of the project including site control, permitting, generator interconnection
status, and development progress and schedule, and the ability to deliver the project by the
commercial operation deadline.
If a Bidder is unable to demonstrate commercial viability, in IPC's sole discretion — specifically the
ability to meet the applicable in-service date —they will be removed from further evaluation. Each
question is weighted differently with a focus on current progress of the project.Weightings are
Page 27

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outlined in Exhibit D—Non-Price Scoring Sheet.The maximum score possible for non-price questions is
100 points.
Resource Based Proposal Price Seem (up to 75 r..+or, Evaluation
IPC's proprietary price scoring model will calculate the delivered revenue requirement per kilowatt
cost of each bid, inclusive of any applicable carrying cost and the impact of tax credit benefits, as
applicable. In developing the revenue requirement cost for each bid, IPC requires certain cost data as
inputs to the price score model. IPC will convert Bidder provided cost inputs into a revenue
requirement stream based on Generally Accepted Accounting Principles (GAAP) and develop annual
levelized costs as described in Exhibit Q—I e"relized PVRR SeenaFme, _Levelized PVRR Scenarios.
c cv cn cc��--crcr��c cncmvr.
Contract structures in which IPC is not the owner of the project bring added costs beyond the direct
contract costs in the form of imputed debt. IPC will estimate the additional cost of imputed debt for
each third-party owned asset and add this cost to the overall cost of a protect.Any internal
assumptions for key financial inputs (i.e., inflation rates, discount rates, marginal tax rates, asset lives,
allowance for funds used during construction [AFUDC] rates, etc.) and IPC's carrying costs (i.e.,
integration costs, owner's costs, etc.)will be applied consistently to all bids, as applicable.
As stated under Interconnection Studies above, Bidders must provide known costs for interconnection
costs and transmission network upgrade costs as provided in applicable system impact study reports
or LGIAs. If this information is not available, IPC will model the bids with an anticipated cost based on
the location of the interconnection point. IPC will model bids with other uncertain terms and
anticipated cost or price contingencies as applicable.
IPC's proprietary price scoring model sceresranks each bid relative to each other within the same
technology where feasible. Each bid's n r I,il.,,. a t priee isnked to d t rY,in the bid's n
�A­r each techRelegy, a maximurn score ef 7-5 points is assigned tA- the bid v.fith the highest calculated
bid
rplatoup rr-Arp Thi- ri-PA bids using that same teehnelegy are reered An Q te 75 peint seale
according te thp-ir rp-lat-ve relationship te these of the highest and lowest performing buds.
Qeg^iiiirco Rased Market Purchase Proposals Non-Price Score (up to 1&100
points)
phieye -,I e ratien by these d date. Qi J d r
i
aAd by
Th. st'. I.
the ability to ce-Mract yVwth the project,the maturity of the project, and ability te CIP-livPer thp-
project by the cernmercial operation deadline.
Page 28

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• GeRtract Risk
• Site CeRtFel
• Perri+its
�G4
n I Rr✓
Experierice
Safety
Deve'epment Schedule
Existing r enditiens (existing Feseurees nly)
If Bidder Unable te demeristrate cernme.rcial viability — specifically the ability te meet the
applicable in Servieen date — they will be Fe-Frievend frem fm irther eval,-atien Far* questien
weighted differently with -;;fe-e-U-S A-In eurrent pFegress ef a 49ject. Weightings are eutlined
F-whibut _R A-f thos UP.Thc maximum score pessible fer neri price questions us 25 peints.
Market D-2rch•+ce DrOPOSaIS DriCe C31FRI'MUG1
5.4-;;rket Purchase PFepE)sal pricing will bp Pw;h 1;#Pr] and r;;nkPPI hased en the price StFUGtUre
thp N4;;rl<pt Purchase Prepesals that meet Minimum Requiremerits will hP suhmittPH tA thp
Mirk re Prep lc Nnn-Drine Caere (up to 25 peent&
r��-rc��-I�gt��c-r�-v�oars��vrrn�
The non-price evaluation rubric for Market Purchase Proposals is included in
GYHIRITExhibit D—Non-Price Scoring )(Sheet. IPC's non-price scoring model evaluates whether
bids are thorough and comprehensive and meet the requested attributes as described in EXHIBIT E
Pr pesed Inn- kct o,-rch VA'-WnPl; Ri.d.deFEXhlbit E—Transmission Paths and Delivery Points. Bidders
must provide documentation, representation,warranties, and other information as necessary to
sufficiently assure IPC that any bid will meet the requirements.The non-price rubric is designed to be
objective, intuitive, and self-scoring. Bidders are required to score themselves by answering each of
the non-price questions and providing supporting documentation.The non-price questions seekare
utilized to score and rank bids--based on, among other factors,e-n-the completeness of P-FRthe Bid
Package and adherence to the bid requirements and the s ability to meet the requested attributes
described in WXWIRI Exhibit E—Prepesed Market Pi_1r.has;e Volumes-Transmission Paths and Delivery
Points.
Points are earned based on the s ability to meet each of the bid attributes requested an EXHIBIT
or pose d INA kct o,,.,.has Volumes.. If a bid offers attributes that could require Idahe PewerIPC to
incur additional costs (i.e., a bid of a WSPP Schedule B product could require Idahe-PeweFIPC to incur
additional Point-to-Point transmission costs),those costs will be estimated and included in the pricing
analysis. Each question is weighted differently with a focus on product type, contribution to identified
needs, shaping and flexibility options, Western Resource Adequacy °r^^:amWRAP eligibility, point of
delivery, and pricing structure.The maximum score possible based on pre-determined weightings is 25
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PGiRtS. This wRitial SCOruRg purposes. AS n.eted belew,the Market Purchase
Proposals that Meet Minimum RequiFemems v4ill be Sub.M.itted*-A- t-he I.R.12 PlaRning Team far fiwthp
arlalys�-,.100 points.
Final Ranking (up to 190 points)
To determine the initi-al bud pool to be further evaluated, !PC will Usc thp- c_-A_rn_hiRed price and ROR
eked bids by product and tech^^'^^ . Identification
of the Initial Shortlist and- by
Through the application of qualitative and quantitative considerations, the proposals in Phase I will be
assigned a proposal ranking and a recommended disposition.The comprehensive set of the highest
ranking and relatively lowest cost bids vdithi^ ^;;rh technology Gategor that combined meet the
requirements of the RFP will become the Initial Shortlist. After th.p IF completes ;+S r^•„^•., -RG-1 file.- ;+
report en the Initi-,I Ch.,r+list
i
IPC will notify the Bidders,through the Portal the QBidde sor email,that were selected for the Phase 1-
Initial Shortlist.This initial pool of bids will be made available as alternatives for further modelin>�.
7.3. PHASE 2 — FINAL SHORTLIST
Phase 2 of the evaluation process is the selection of the Final Shortlist. Q;,I,l^rs ^r,the In;+;-,I ChA-.r �+
Oil be required to pFevaplp WC ygmth any updates tE)thpor hod-; Onrl
w relevant price or schedule
Friedifieations, interconnection study results, or arly ether material change that would imp ,the
protects IPC is most likely to commence contract negotiations. IRP production ^s+ r ^d^I ^r Minimum
rr•^.d^I,; Al IRnRA •°„II hpmodeling tools will be utilized to help select the least-cost, least-risk
portfolios from the Initial Shortlist based on bid cost, performance data, and effective load carrying
capability (ELCC-).
IPC will perform a reliability assessment to ensure that the selected portfolio of resources can meet all
hourly load and operating reserve requirements with sufficient cushion to account for other system
uncertainties such as non-normal weather events.This process is described in the company's most
recently acknowledged 2-0-23 IRP un the Technical Appendix C in the "Leess; of Lead ExpectatiorlL,
seeder}IPC's 2025 IRP Appendix D: System Reliability and Regulating Reserves.
IPC does not anticipate updating the _, twen of the bid evaluation from Phase 1.
However, if at any time during Phase 2, a Bidder determines its submitted bid is no longer valid,
the Bidder should notify IPC immediately and the bid will be withdrawn from further consideration.
analysis.Original non price scores cor.A.-hiffined v.foith IRP modeling rp-SmUlt-S i.A.411 bc ce.nSide.red in A en-St And r*_ -
Any other factors not expressly included in the formal evaluation process but required by
applicable law, order by the Commissions, or other significant material industry or technology change
may be used by IPC — in censultatia;,vdith the IE to identify a subset of Bidders from Phase 1 that
can be advanced to further evaluation and negotiation (the Final Shortlist).
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.PFaGessing of god I pdatoc
Similar a Phase r�ri g a'llatiOR IDS' uses its PFGPrieta FV w�er'e c to
vn�-Rrcrrt� cn-rrc����arrC-F�se.�klurorsr � r�--Fn-vFrrccar-�--rrrvcrc rr�v
PFGeess laid updates. ThP_ T Q_CdC 1r0 -A c IWAirhdart r
iRG'Udir,^ Pric-e- IRP Modeling, Sensitivity Analysis and Portfolio
Development
Consistent with the treatment of the capital revenue requirement in IPC's IRP modeling, IPC will
convert any calculated revenue requirement associated with capital costs (i.e., return on investment,
rP_*'_,rn ef inver-A.m.ent-and taxes, and the impaet of tax eredits, as applicable)to fiFst year Feal levelized
re-e-sts. Si.m.i.larly, all ether-hmd- e-A-StS _;;.re levelized- and f.e.r.rnatted- f.A-.r input inte te the IRP Pnedle[s-
Projected renev.fable Feseurce perfermance data (expected hourly capacity factAGIr
-;;Fe alse p ed ferinput inte the IRP .,-,.,dell
Red Resource IR.P Modeling, Sensitivity Analysis -and Portfolio Development
The IRP tp--;;M thp- AURORA rnedel te help select thp- le-ast-ce-st, least risk resource types based
en bid cost, performance dat-a -Anr-I F-I-C-C--;;.n.r-1 select the Fi.n.al. She.rtlist. WC u-Ses,AURG)RAte develop
Following the Initial Shertliffist -;;nr-1 bid updates, IPC will submit the peel of bids (including Marl
Purcha-re PFepesals that h;W.oe mpet the MMRMFnum QualAcatiens) te its IRP Planning Team te evaluate
reseurces feir the Final SheirfloSt.The- IIRP Planning Team vAll evaluate the peel ef rese-urce-S, using
AURORA,the production P-A-'-;t- M.A-r-I&I -USP-rd un the IRP. Censestent;Afffith thp-treatment ef capital revenue
with-eapotal cost , r^t„r^ ^ investment, r^t„rr. ^f;, ^�tr ^r+ and taxes, and the impact of tax
credits, as applicable)to first year-real-levelized costs. Similarly, all other bid costs are levelized and
formatted for input into the IRP models. For a 25-year PPA for example, IPC calculates the
present value of the revenue requirement (contractual payment stream over the 25 years)for the
project and r- calculates the levelized payment based on the contract life as demonstrated in
the example Exhibit 9J—Levelized PVRR Scenarios. Projected renewable resource performance data
(expected hourly capacity factor information)will also be processed for input into the IRP models.
Projected Effective Lead GarFying Capability (ELCC}for each bid will also be processed for input into
the IRP models.The IRP modeling tools will help select the least cost resource types based on bid cost,
performance data, and ELCC. IPC's Final Shortlist may ake-include high bids in excess of the
identified capacity limits if those projects have economic benefit.
IPC will evaluate portfolios under a range of different environmental policy and market price scenarios
(policy-price scenarios). In this way, IPC uses AURORAAurora to help optimize its selection of bid
resources to identify the lowest cost, reliable portfolio under multiple scenarios prior to undergoing
additional risk analysis and further consideration as part of the Final Shortlist process.T+e
^p- ^d ^ ^d
Page 31

i
Risk Analysis
IPC next uses AWROR Aurora to evaluate each portfolio and its ability to perform under dynamic
market conditions. In AkA9AAAurora a stochastic sensitivity analysis will be performed,which
assesses the effect on portfolio costs when select variables take on values different from their
planning-case levels.AURORAAurora measures the risk of each portfolio through its production cost
estimates. By holding a resource portfolio fixed and using Latin Hypercube stochastic simulations of
stochastic variables —including,for example, load, natural gas prices, and hydro generation —
"""RAAurora can measure the expected cost of each portfolio in an uncertain future. Stochastic
variables are selected based on the degree to which there is uncertainty regarding their forecasts and
the degree to which they can affect the analysis results (i.e., portfolio costs).The Latin Hypercube
design samples the distribution range with a relatively small sample size, allowing a reduction in
simulation run times.The Latin Hypercube method does this by sampling at regular intervals across
the distribution spectrum.The purpose of the stochastic analysis is to understand the range of
portfolio costs across the full extent of stochastic shocks (i.e., across the full set of stochastic
iterations) and how the ranges for portfolios differ.
Identification of Top-Performing Resource Portfolios
IPC will then summarize and analyze the portfolios to identify the specific bid resources that are most
consistently selected among the policy-price scenarios. Based on this data, as well as certain
qualitative and non-price criteria, and in ,l+.,+ieR yiath +h �� IPC may select one or more resource
portfolios for further cost-risk analysis.
Other Factors —Applicable Law and Statutory Requirements
Before establishing a Final Shortlist, IPC may take into consideration, i^ ce-R-ru'+a+ien with th^ 'E
other factors that are not expressly or adequately factored into the evaluation process outlined above,
particularly any factor required by applicable law or order of either Commission to be considered.
Final Shortlist Selection
IPC will summarize and evaluate the results of its cost-risk analysis, considering present value revenue
requirement results to identify the specific least-cost, least-risk bids. Based on these data and certain
other factors as described above, -;;Ad- in eeRsultatie-H ..,f+h the lE, IPC will establish a Final Shortlist.
After the Final Shortlist is established and approved, IPC wee-may engage in negotiations with the
selected Bidders`to finalize+heiF e ntFact(s) and prepare the ntract(s) for executffie-RL Selection of
a bid to the Final Shortlist does not constitute a winning bid. Only execution of a definitive
agreement between IPC and the Bidder, on terms acceptable to IPC, in its sole and absolute discretion,
will constitute a winning bid.
7.4. ADDITIONAL RIGHTS
IPC may, in ceerc,;natie., with not it and the lE, at anytime during the Solicitation:
1. Appoint evaluation committees to review bids, seek the assistance of outside technical
experts and consultants in bid evaluation, and seek or obtain data from any source that
has the potential to improve the understanding and evaluation of the responses to
this RFP.
Page 32

i
2. Revise and modify, at y tome before the deadline f r bid submittal the factors it will
consider in evaluating bids and to otherwise revise or expand its evaluation methodology-
as applicable and relevant.
3. Hold interviews and meetings to conduct discussions and exchange correspondence with
either all Bidders or only those with bids that IPC elects to select for detailed discussions
(IRitial cherflist d Bids) ;R erder to seek an improved understanding and evaluation of an
individual Bidder's bid.
4. Issue a new RFP.
5. Cancel or withdraw the entire RFP or any part thereof.
7.5. ACCEPTANCE AND REJECTION OF BIDS
IPC may or may not award an agreement after analysis and evaluation of the bids. IPC reserves the
right to reject any and all bids,to waive minor formalities and irregularities, and to evaluate the bids
to determine which — in IPC's sole judgment — represents the best value for the Prepesalsbids
requested.
7.6. AGREEMENT NEGOTIATIONS
In anticipation of an award,there w-i4 ay be a period of negotiations to finalize the agreement(s)
between the parties.An agreement, including all terms, conditions, exhibits and attachments, must be
executed by both IPC and the successful Bidder in order to create a binding enforceable agreement
between IPC and the successful Bidder.
7.7. EXCLUSIVITY
If and when a bid is selected for the Final Shortlist,from that date,the Bidder and/or its affiliates
shall not execute an agreement with any other party for the sale of the Project or Plant sUC#
thatso the Bidder would no longer be able to provide the associated bid for a period of s44y-(60)90
days.
7.8. PUBLICITY
The parties intend to issue joint public announcements, in the form of press releases, case studies,
and/or other materials, containing content mutually agreed to by the parties, upon execution of the
agreements. Neither party shall use the name, logo, or any other indicia of the other party in any
public statement, press release, other public relations, or marketing materials,the identity of the
other party or any underlying information with respect to the agreement(s) at any time without the
prior written consent of the other party,which it may withhold in such other party's sole discretion.
Prior to making any such permitted use, each party shall provide for the other party's review and
approval, any publicity materials.Any and all goodwill from use of IPC's name, logo, or indicia will
inure to IPC's sole and exclusive benefit.
7.9. COMMISSION APPROVAL
Execution of an agreement wi4may ultimately be subject to approval by the
Page 33

i
8. ENTIRE RFP
This RFP and all exhibits, attachments, datasheets, forms, and addenda within the Portal event are
incorporated herein by this reference and represent the final expression of this RFP. Only information
supplied by IPC in writing through the parties listed herein or by this reference made in the submittal
of this RFP shall be used as the basis for the preparation of B+dder3Bidders' bids.
Page 34

Attachment 2 :
Idaho Power's Imputed Debt
Discovery Responses
*Idaho Power's Responses to NIPPC's Interrogatory Nos. 6 & 7; OPUC Docket No. UM 2255
Idaho Power Response to NIPPC Information Request No. 1; and Idaho Power's Response to
IPUC Staff s Production Request No. 10

INTERROGATORY NO. 6: Imputed Debt. Reference Direct Testimony of Eric
Hackett, Exhibit No. 1 (Draft 2032 RFP) at p. 25, stating:
IPC will convert Bidder provided cost inputs into a revenue requirement
stream based on Generally Accepted Accounting Principles (GAAP)
and develop annual levelized costs as described in Exhibit J—
Levelized PVRR Scenarios. Contract structures in which IPC is not the
owner of the project bring added costs beyond the direct contract costs
in the form of imputed debt. IPC will estimate the additional cost of
imputed debt for each third-party owned asset and add this cost to the
overall cost of a project.
a. Please explain whether Idaho Power agrees that the proposal to use imputed debt
adders for all third-party ownership bids in this RFP is a significant change from
Idaho Power's 2026 and 2028 RFPs. In no, please explain why not.
b. Please explain why Idaho Power's application and its supporting testimony provide
no discussion in support of the proposal to use imputed debt adders in the 2032
RFP.
ANSWER TO INTERROGATORY NO. 6:
a. The imputed debt methodology and calculation for the 2032 RFP is generally
consistent with the imputed debt methodology that was proposed in the 2026 RFP.
Although imputed debt was not included in the evaluation of either the 2026 or
2028 RFP bids as directed by the OPUC, Idaho Power believes imputed debt is
an important financial consideration for third-party owned projects and should be
included in the evaluation of 2032 RFP bids.
b. Idaho Power's Application and testimony outline the Company's request in
accordance with Idaho Code §§ 61-501, 61-502, and 61-503 and Rules of
Procedure 52 and 201, and in accordance with the Procedures for Soliciting Large-
Supply-Side Resources. Both are intended to support the request in this case but
IDAHO POWER COMPANY'S RESPONSE TO NORTHWEST & INTERMOUNTAIN POWER
PRODUCERS COALITION'S FIRST SET OF PRODUCTION REQUESTS AND FIRST SET OF
INTERROGATORIES - 13

do not specifically address each individual component of the nearly 500-page 2032
RFP and associated exhibits which are also filed for review and approval.
The response to this Request is sponsored by Eric Hackett, Projects and Resource
Development Director, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO NORTHWEST & INTERMOUNTAIN POWER
PRODUCERS COALITION'S FIRST SET OF PRODUCTION REQUESTS AND FIRST SET OF
INTERROGATORIES - 14

INTERROGATORY NO. 7: Imputed Debt. Reference Idaho Power's Response to
NIPPC's Information Request No. 1 in Oregon Public Utility Commission Docket No. UM
2255, stating Idaho Power's use of imputed debt bid adders for PPA and BSA bids in the
2022 RFP resulted in a median percentage increase in bid cost of approximately 18% for
PPA and BSA bids.
a. Please confirm that Idaho Power did not use imputed debt bid adders in the 2026
RFP or 2028 RFP.
b. Please confirm that the proposed use of, and methodology for calculating, imputed
debt in the 2032 RFP is generally consistent with Idaho Power's proposed use of
imputed debt in the 2022 RFP. If the answer is no, please explain any differences
in Idaho Power's proposal in the 2032 RFP.
ANSWER TO INTERROGATORY NO. 7:
a. Idaho Power did not include imputed debt in the evaluation of the 2026 RFP or
2028 RFP bids as directed by the OPUC in Order No. 23-260 in Docket UM 2255.
b. The imputed debt methodology and calculation proposed in the 2032 RFP is
generally consistent with the imputed debt methodology that was proposed in the
2022 RFP. While bids received as a result of the 2022 RFP were evaluated with
and without imputed debt, it ultimately had no bearing on the results of the final
shortlist as the developer of the impacted project withdrew the bid from
consideration.
The response to this Request is sponsored by Eric Hackett, Projects and Resource
Development Director, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO NORTHWEST & INTERMOUNTAIN POWER
PRODUCERS COALITION'S FIRST SET OF PRODUCTION REQUESTS AND FIRST SET OF
INTERROGATORIES - 15

UM 2255
Idaho Power Company's Response to NIPPC's
Information Request No. 1
TOPIC OR KEYWORD:
NIPPC'S INFORMATION REQUEST NO. 1: Reference Idaho Power's Notice of Exceptions
Report Regarding the 2022 RFP, filed on February 17, 2023 at pp. 7-8 & n. 9, stating that Idaho
Power calculated the levelized cost of capacity for each bid by converting "all fixed costs
associated with the separate technologies of each project, including capital costs, depreciation
expense, tax expense, financing costs including both the return on Company-owned assets or
the imputed debt cost associated with a PPA, PPA, operations and maintenance expenses, and
property taxes and insurance, to an equivalent, comparable value." (emphasis added).
a. Please provide a non-confidential estimate of the magnitude of the imputed debt cost
attributed to a typical PPA and tolling agreement bid as a percentage of the overall
levelized cost of capacity for the individual bids. This request could be answered by
providing the median percentage impact of all bids, an average of the percentage impact
across all bids, or any other reasonable estimate that provides a non-confidential good
faith estimate of the impact of the imputed debt scoring element in the 2022 RFP for the
PPA and tolling agreement bids.
b. Please provide bid scoring materials or work papers that demonstrate the levelized cost
of return on Company-owned assets and/or levelized imputed debt cost (as applicable)
assigned to each bid as well as the overall levelized cost of capacity for the bid.
C. Please confirm that the use of imputed debt in the 2022 RFP is generally consistent with
Idaho Power's proposed use of imputed debt in the 2026 RFP subject to review in this
docket. If the answer is no, please explain any differences in Idaho Power's proposal in
the 2026 RFP.
IDAHO POWER COMPANY'S RESPONSE TO NIPPC'S INFORMATION REQUEST NO. 1:
a. The median percentage increase of imputed debt over the levelized cost excluding
imputed debt is approximately 18 percent for a battery storage (tolling) agreement (BSA)
and 18 percent for a power purchase agreement (PPA).
b. Please see the Confidential Excel spreadsheet attached to this request.
C. Yes, the company will use an imputed debt methodology in its evaluations of the 2026
RFP bids generally consistent with the methodology used for 2022 RFP bids; with the
following adjustments:
i. Imputed debt risk factors. The Company applied a 50 percent risk factor to all
BSAs and PPAs in the 2022 RFP. For the 2026 RFP, the Company will continue
to apply a 50 percent risk factor for PPAs. However, for BSAs the Company will
apply a 100 percent risk factor as the transaction will result in capital lease
accounting under generally accepted accounting principles. Under capital lease
accounting the entire amount of imputed debt will be accounted for on Idaho
Power's balance sheet as debt. It is the Company's understanding based on
conversations with the rating agencies that they do not make any additional
adjustments related to transactions accounted for as capital leases and see this
as debt impacting credit risk.
ii. Renewal assumptions for PPAs. Originally during the initial scoring process,
Idaho Power assumed a renewal period for new PPA projects that had a contract
term less than 35 years. After further review, Idaho Power removed this

UM 2255
Idaho Power Company's Response to NIPPC's
Information Request No. 1
methodology in the post-initial screen process. The Company does not plan to
add a renewal period to PPAs in the 2026 RFP.

REQUEST FOR PRODUCTION NO. 10: Please explain if the Company intends
to include the cost of imputed debt in its determination of the levelized costs for each bid.
If yes, please explain the Company's justification for doing this.
RESPONSE TO REQUEST FOR PRODUCTION NO. 10: Idaho Power intends to
include the cost of imputed debt to the levelized cost of third-party resources to reflect the
impact imputed debt can have on the Company's cost of capital. Idaho Power competes
with other companies in the capital markets to obtain debt and equity financing necessary
to operate its business and fund capital projects. In seeking to access capital, one of the
major factors banks and lenders consider is a company's overall financial profile,
including the strength of its balance sheet. The credit rating agencies Moody's and
Standard & Poor's ("S&F) assess the financial strength of companies like Idaho Power
and provide ratings to current and prospective lenders that measure balance sheet
strength.
While Moody's and S&P look at imputed debt differently, they both evaluate future
contractual obligations related to long-term power purchase agreements ("PPA") and
similar arrangements, like financing lease transactions (such as a battery storage tolling
agreement), as they consider future debt and debt-like obligations of issuers during their
ongoing monitoring of credit quality. The third-party is ultimately leveraging Idaho Power's
balance sheet to develop and operate its project, with the power purchase agreement or
tolling agreement and underlying payment stream as collateral. Because of this reliance,
it diminishes Idaho Power's credit profile and strength. Imputing debt is a credit rating
agency's way of transferring the project risk from the developer to the utility because the
contractual obligation of the utility is essentially providing cash flow and credit support to
IDAHO POWER COMPANY'S RESPONSE THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 14

the developer. It is analogous to a debt instrument that Idaho Power executes, in that
Idaho Power's ability to meet its long-term obligations on its indebtedness is supported
by its cash flows. Credit rating agencies account for this transferred risk as a fixed debt
obligation of the utility and impute this risk to the utility's balance sheet, which affects the
utility's financial and credit metrics, credit ratings, perceived financial strength, and
ultimately both the interest rates the utility pays on indebtedness and the utility's cost of
equity— both elements of financing costs. In that way, a PPA or similar arrangement can
become notably detrimental to a utility's balance sheet, particularly as the obligation
grows in magnitude.
Moody's and S&P have repeatedly noted the Company's significant level of
contractual obligations and highlighted the rising levels of these obligations in recent
years, as a risk area putting pressure on the Company's financial risk profile. In March
2026, one rating agency placed particular focus on the Company's third-party battery
tolling agreement, stating specifically that it would impute debt for the obligation
notwithstanding the existing mechanism for broad regulatory recovery. The risk analysis
associated with Idaho Power's large long-term contractual obligations has been a key
discussion point with Moody's and S&P, given the Company's significant long-term Public
Utilities Regulatory Policies Act ("PURPA") and non-PURPA power purchase obligations.
As of December 31, 2025, Idaho Power had contractual obligations related to
cogeneration and power production contracts of nearly $5.7 billion. This compares with
long-term debt obligations of approximately $3.3 billion on that same date.
The imputed debt relating to contractual obligations contributed to the financial risk
score of 'Significant' at Idaho Power in S&P's recent credit report and contributed to the
IDAHO POWER COMPANY'S RESPONSE THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY- 15

factors considered by Moody's during its most recent downgrade in 2022. Since the
downgrade, Moody's has put Idaho Power on a negative watch, which is a step toward
another downgrade. Further increases in its contractual obligations related to PPAs and
similar arrangements will put additional pressure on its credit metrics that could lead to
further negative watches and downgrades in its credit ratings. Both rating agencies are
now showing credit rating levels that are considered `Lower medium grade' by the
markets. Further material downgrades could drop the Company to `Non-investment grade
speculative' status, which would further increase the cost of borrowing for Idaho Power,
likely significantly, ultimately impacting customer rates.
In addition, deteriorating credit ratings not only impact long-term debt costs, but
also impact short-term credit markets, including existing and future credit facilities and the
ability of Idaho Power to access the commercial paper market. If Idaho Power's current
commercial paper rating of A-2/P-2 were to deteriorate, it would be more costly to the
Company and to customers to access short-term borrowings, as the markets for A-3/P-3
and below are more expensive and significantly less liquid, resulting in times when the
commercial paper market cannot be accessed reliably and must be replaced by more
costly short-term borrowings from credit facilities. Higher short-term debt costs could
negatively impact customers in the form of higher Allowance for Funds Used During
Construction rates.
The response to this Request is sponsored by John Wonderlich, Investor Relations
Manager, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF TO IDAHO POWER COMPANY - 16

Attachment 3 :
Expert Report on PPA Imputed Debt
of Michael P. Gorman,
OPUC Docket No.
UM 2255 (May 9, 2023)

BEFORE THE PUBLIC UTILITY COMMISSION
OFOREGON
In the Matter of UM 2255
IDAHO POWER COMPANY
Application for Approval of 2026
All-Source Request for Proposals to
Meet 2026 Capacity Resource Need.
Expert Report
on PPA Imputed Debt
of
Michael P. Gorman, CFA
May 9, 2023
BRUBAKER&ASSOCIATES.INC.
Project 11472

Michael P. Gorman
Page 1
1 My qualifications and experience to offer this expert report are summarized in the
2 attached BAI corporate qualifications profile. This report responds to Idaho Power Company's
3 ("the Company" or"Idaho Power") proposal to make an imputed debt adjustment to the cost of
4 purchased power agreements and battery storage agreements (collectively referred to as
5 PPAs) in the 2026 request for proposals ("RFP") bid evaluation process. This response was
6 prepared on behalf of the Northwest & Intermountain Power Producers Coalition ("NIPPC"),
7 and my conclusions support London Economics International's ("LEI") and the Oregon Public
8 Utility Commission Staff's recommendation to reject Idaho Power's proposal to include an
9 imputed debt adjustment to costs of non-utility resource bids (PPAs) for bid evaluation
10 purposes.
11 An imputed debt adjustment to the cost of a PPA(generally an imputed debt cost adder)
12 should be excluded from the RFP because such an imputed debt cost adder would create an
13 economic bias against selecting PPAs as the most economic resource option. As outlined
14 below, PPAs do have contractual financial obligations and do impose financial costs on utilities,
15 including Idaho Power, to balance the leverage risk of resource options including PPAs. But
16 importantly, non-PPA resources also cause financial costs related to the development,
17 operating uncertainty, and financial risk associated with utility-owned resource options. Idaho
18 Power has not proposed to reflect the added financial costs for the utility-owned resource
19 options in its resource economic evaluation. Idaho Power's proposal is inconsistent and
20 imbalanced. These added financial costs, if accurately measured for all resource options,
21 would largely be offsetting between PPAs and utility-owned resources. Therefore, it is fair and
22 accurate to simply not reflect these external, unknown financial costs in the comparison of
23 resource options.
BRUBAKER&ASSOCIATES,INC.

Michael P. Gorman
Page 2
1 Additionally, as further detailed in this report, Idaho Power has exaggerated the debt
2 equivalent and has overstated a debt imputation cost for PPAs, if one would be appropriate in
3 isolation of other types of resources, which it is not.
4 Idaho Power's evidence does not support its proposal to include an imputed debt adder
5 to the cost of a PPA in comparing the cost of various resource options in this RFP. However,
6 if the Commission is interested in further examining PPA debt equivalence and capital structure
7 management issues, Idaho Power could address the issue in Idaho Power's next rate case
8 along with other aspects of its cost of capital and/or cost of service.
9
10 UTILITY RESOURCES ADDED COSTS
11 Idaho Power's Position on Debt Imputation and PPAs
12 Idaho Power outlines how a credit rating agency would assess its leverage risk in a
13 utility credit rating assessment. It states that a PPA creates leverage which Idaho Power must
14 manage by changing its capital structure's mix of debt and equity in funding utility-owned
15 infrastructure investments in order to avoid a credit downgrade. Idaho Power suggests that it
16 may need to increase its use of equity capital on utility rate base investments (reduced
17 leverage risk) to balance the imputed debt equivalence of a PPA (increased leverage risk).
18 Idaho Power asserts that this possible change to the ratemaking capital structure's equity
19 component would increase Idaho Power's cost of service. Idaho Power maintains that the
20 PPA imputed debt cost adder reflects the added cost to the utility's cost of service caused by
21 the PPA. Further, Idaho Power contends that under new accounting standards, a PPA may,
22 under certain circumstances, be regarded as an operating lease which would need to be
23 recorded on its balance sheet as a regulatory liability.' Idaho Power claims that the increase
' Idaho Power's Reply Comments, p. 11 (March 24, 2023).
BRUBAKER&ASSOCIATES,INC.

Michael P. Gorman
Page 3
1 in this liability would also increase its leverage risk which would need to be considered in
2 managing a balanced ratemaking capital structure.
3 Ultimately, Idaho Power asserts that the PPA would increase Idaho Power's leverage
4 risk which would need to be balanced by increasing the percentage weight of common equity
5 capital in the utility's ratemaking capital structure (an offset to the PPA leverage) to maintain a
6 balanced amount of utility leverage which in turn will support its credit rating and access to
7 capital.
8 Idaho Power cites credit rating methodologies used by Standard & Poor's ("S&P") and
9 Moody's Investors Service ("Moody's") to support its claims.
10
11 Response
12 1 do not dispute that credit rating agencies will consider a contractual obligation of the
13 utility in an assessment of the overall leverage or financial risk of the utility and that may result
14 in added costs to a utility's cost of service for added leverage risk. However, these added
15 costs do not result only from PPAs but also result from added financial cost for utility-owned
16 and utility-developed generating resource options. Idaho Power has ignored or has
17 understated these financial costs for non-PPAs. A balanced review of these added leverage
18 risk adjustments shows that the added financial costs for a PPA are similar to the added
19 financial costs for utility-owned facilities. Hence, it is not fair, balanced, or accurate to consider
20 only an imputed debt adjustment cost for a PPA resource option without any consideration of
21 the added financial costs for a utility-owned resource option. Idaho Power's comparison
22 creates a clear bias against the cost of PPA resource options and favoritism for utility-owned
23 resources. It is more conservative and more accurate to set the added financial cost issue
24 aside in a resource cost comparison such as RFP scoring, with the understanding that the
25 utility will need to balance its financial obligations in order to maintain strong credit standing
BRUBAKER&ASSOCIATES,INC.

Michael P. Gorman
Page 4
1 while selecting resource options which reflect the best and most economic resource options
2 available to the utility.
3 Again, I agree with Idaho Power's findings that credit rating agencies consider leverage
4 risk for PPAs, but I do not agree with certain assertions Idaho Power makes concerning the
5 magnitude of those PPA leverage risks. Specifically, I believe Idaho Power exaggerates the
6 debt equivalents for a PPA in several aspects in its application for its approval of the 2026
7 RFP. In its reply comments, the Company states that Idaho Power currently has contractual
8 obligations for cogeneration and power production contracts of more than $4 billion.z At pages
9 12 and 13 of the reply comments, it states that, as the Company transforms from a resource
10 surplus position to a resource deficient position, the risk factor used by credit agencies in
11 determining the debt-like equivalent of its PPAs will likely increase from a 25% factor up to a
12 50% factor. It states this will happen simply by consequence of moving from being capacity
13 surplus to being capacity deficient. Further, at pages 11 and 13 of the reply comments, Idaho
14 Power asserts that under new accounting standards, Idaho Power may need to record any
15 PPA with dispatch rights as an operating lease and record the PPA on its balance sheet as a
16 regulatory liability. Under this accounting, Idaho Power reports that the PPA would be given
17 100% imputed debt treatment by the credit rating agency.
18 Neither of these assertions hold up in a review of Idaho Power's credit rating metrics
19 published by S&P. Specifically, Table 1 below contains S&P's published analysis of Idaho
20 Power's leverage metrics and risk assessment, including the "off-balance sheet" debt
21 equivalence S&P has attributed to Idaho Power's existing PPA obligations. As shown below
22 in Table 1, the$4 billion in cogeneration and power production contracts noted by Idaho Power
23 do not translate into a similar amount of off-balance sheet debt considered by S&P for Idaho
24 Power's leverage risk assessment. Instead, the $4 billion of cogeneration and power
2 Id., p. 7 (March 24, 2023).
BRUBAKER&ASSOCIATES,INC.

Michael P. Gorman
Page 5
1 production facilities referenced by Idaho Power's reply comments has resulted in an imputed
2 debt equivalent from S&P of only $271 million in 2017-2019. For additional context, that
3 $271 million of debt equivalent related to existing PPAs is relatively minor in relationship to the
4 more than $2.0 billion of on-balance sheet debt. This shows that a PPA's debt equivalence is
5 manageable for Idaho Power.
TABLE 1
Idaho Power Company
S&P Credit Rating Leverage Metrics
(Millions)
Description 3 yr avq 2017 2018 2019 2020 2021 2022
Balance Sheet Debt $2,065 $1,746 $1,835 $1,837 $2,000 $2,001 $2,194
OLA Debt 0 35 0 0 0 0 0
Accessible cash and liquid investments (112) (45) (165) (99) (166) (60) (109)
Purchase Power Debt Equivalent 0 271 271 271 0 0 0
ARO Debt Adjustment 27 21 21 22 22 29 30
Pension&Other Debt/Deferred Comp. 372 351 345 415 506 417 193
Total OBS 287 632 471 609 362 386 114
Total Debt:Balance Sheet Plus OBS 2,352 2,378 2,306 2,446 2,362 2,386 2,308
Source:
S&P Credit Stats,Idaho Power Company
6
7 Also of significance in S&P's leverage risk assessment is the off-balance sheet debt
8 associated with asset retirement obligations ("ARO"), and the pension and other debt-deferred
9 compensation issues. AROs can include the cost of decommissioning utility-owned resources
10 and can include such items as coal ash pond remediation and other environmental cleanup
11 costs. Pension off-balance sheet obligations include the utility's obligation to fully fund its
12 pension trust fund to meet the retirement obligations of its employees. Credit rating agencies
13 track these obligations because the costs can be material and reflect liabilities to the utility,
14 much the same way PPAs can be contractual liabilities to the utility. As shown in Table 1
15 above, off-balance sheet debt obligations for AROs and pension obligations exceed the
16 off-balance sheet debt obligations of PPAs.
BRUBAKER&ASSOCIATES,INC.

Michael P. Gorman
Page 6
1 Idaho Power Exaggerates PPA Debt Equivalency Impacts
2 Further, Idaho Power's argument that the risk factor for converting PPA capacity
3 payments to debt equivalents will increase materially as it transitions from being a capacity
4 surplus utility to a capacity deficient utility is also not consistent with S&P's reports regarding
5 its risk assessment method for calculating a PPA's debt equivalent.3 NIPPC asked Idaho
6 Power to provide copies of its communications with credit rating agencies to confirm its
7 representations of the PPA debt equivalence assertions. In response, Idaho Power stated that
8 its communications with credit agencies were oral, and it did not have written material from the
9 credit agencies.4
10 Idaho Power's characterization of the oral communications with credit agencies
11 concerning PPA debt equivalency risk factor adjustments do not align with S&P's published
12 reports that explain its PPA debt equivalence methodology used in the utility credit rating
13 process. Once again, S&P uses a risk factor in its debt imputation for PPAs by considering
14 the utility's expected capacity payments under the PPA, and converts that into a debt
15 equivalent using a risk factor. In S&P's published report that describes its debt imputation for
16 PPAs used in utility credit rating leverage assessments, S&P describes the risk factor
17 adjustment to PPA capacity payments as follows:
18 Risk Factors
19 The NPVs that Standard & Poor's calculates to adjust reported financial metrics
20 to capture PPA capacity payments are multiplied by risk factors. These risk
21 factors typically range between 0% to 50%, but can be as high as 100%. Risk
22 factors are inversely related to the strength and availability of regulatory or
23 legislative vehicles for the recovery of the capacity costs associated with power
24 supply arrangements. The strongest recovery mechanisms translate into the
25 smallest risk factors. A 100% risk factor would signify that all risk related to
26 contractual obligations rests on the company with no mitigating regulatory or
27 legislative support.5
3 Idaho Power's Reply Comments, pp. 12-13 (March 24, 2023).
4 Idaho Power's Response to NIPPC's Information Request No. 3.
5 Standard & Poor's Ratings: "Standard & Poor's Methodology For Imputing Debt For U.S. Utilities'
Power Purchase Agreements," at 2 (May 7, 2007) (emphasis added).
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Michael P. Gorman
Page 7
1 At page 5 of this same report, S&P describes its debt equivalency adjustment if a PPA
2 is treated as an operating lease. S&P will still apply the risk factor adjustment in determining
3 the PPA's debt equivalent. Idaho Power claims that if the PPA is recorded as a lease liability,
4 the PPA would be treated as the equivalent of long-term debt.6 However, that assertion is not
5 consistent with S&P's published methodology, which states S&P would still use its risk factor
6 adjustment for a PPA recorded as a lease liability to gauge its debt equivalence. S&P stated
7 as follows:
8 Several utilities have reported that their accountants dictate that certain PPAs
9 need to be treated as leases for accounting purposes due to the tenor of the
10 PPA or the residual value of the asset upon the PPA's expiration. We have
11 consistently taken the position that companies should identify those capacity
12 charges that are subject to operating lease treatment in the financial statements
13 so that we can accord PPA treatment to those obligations, in lieu of lease
14 treatment. That is, PPAs that receive operating lease treatment for accounting
15 purposes won't be subject to a 100% risk factor for analytical purposes as
16 though they were leases. Rather, the NPV of the stream of capacity payments
17 associated with these PPAs will be reduced by the risk factor that is applied to
18 the utility's other PPA commitments. PPAs that are treated as capital leases
19 for accounting purposes will not receive PPA treatment because capital lease
20 treatment indicates that the plant under contract economically "belongs" to the
21 utility.'
22 While debt equivalence of a PPA in an assessment of a utility's credit risk is not in
23 dispute, Idaho Power's claimed magnitude of the debt equivalence is exaggerated.
24 Specifically, Idaho Power has claimed that its risk factor would increase from 25% to 50% due
25 to change of its resource position from surplus to deficient. This assumption is not supported
26 by S&P's methodology for assigning a risk factor for purposes of an imputed debt calculation.
27 By making this assumption, Idaho Power has increased by double the amount of debt
28 equivalency of expected PPAs. This overstates the cost of a PPA debt equivalency adjustment
29 and is not consistent with a reasonable estimate of the financial leverage impact on Idaho
30 Power's cost of service.
6 Idaho Power's Reply Comments, p. 11 (March 24, 2023).
Id. at 5 (emphasis added).
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Michael P. Gorman
Page 8
1 Idaho Power's Debt Equivalence Risk Factor Adjustments for PPAs is Flawed
2 In its debt equivalency methodology, Idaho Power states that it is assigning a risk factor
3 of 50%, an increase from the current PPA risk factor of 25%, to judge the debt equivalence of
4 a PPA cost and to adjust PPA costs in its resource cost comparison.$ Idaho Power maintains
5 that the risk factor used by credit rating agencies to determine the PPA debt equivalence, at
6 least with respect to its Public Utility Regulatory Policies Act of 1978 ("PURPA") contracts, was
7 a 25% risk factor but the Company expects that to increase to 50% because the Company is
8 moving from a capacity surplus position, to a capacity deficient position.9 The Company has
9 used a 50% risk factor in its quantification of a PPA embedded debt estimate in its last RFP,
10 and plans to do so again in this RFP.10 Idaho Power states that in its last RFP this methodology
11 resulted in a bid adder with a median magnitude of 18% for the imputed debt for the PPA bids,
12 when measured as a percentage of overall levelized revenue requirement for the bid.11 Again,
13 Idaho Power's debt equivalency is exaggerated and imbalanced.
14 There are several flaws in Idaho Power's adjustments. First, Idaho Power states the
15 risk factor adjustment should be increased because it is moving from a capacity surplus to a
16 capacity deficient position, and this increased need for capacity will increase the PPA risk
17 factor in calculating its debt equivalent. However, S&P's published methodologies do not
18 support this assumption. Rather, as quoted above, S&P's debt equivalency risk factor is more
19 impacted by the cost recovery mechanisms in place for the utility's recovery of the costs it must
20 pay to the seller under the PPA, and not Idaho Power's capacity surplus or deficiency position.
21 Second, Idaho Power's assumption that new accounting standards may result in a PPA
22 being regarded as an operating lease and recorded as a regulatory liability on its balance
23 sheet, which would be treated by credit rating agencies as long-term debt, is also not
8 Idaho Power's Reply Comments, pp. 12-13 (March 24, 2023).
9 Id.
10 Id.; Idaho Power's Response to NIPPC's Information Request No. 1(c).
11 Idaho Power's Response to NIPPC's Information Request No. 1(a).
BRUBAKER&ASSOCIATES,INC.

Michael P. Gorman
Page 9
1 supported. S&P states that it will continue to make a risk factor adjustment to a lease obligation
2 in assessing the PPA's off-balance debt equivalence. Rate recovery mechanisms make a
3 significant impact on Idaho Power's credit risk attributable to a PPA.
4 The debt risk of a utility-owned facility is considerably greater than that of a PPA
5 because under a PPA a third-party supplier, in whole or at least in great part, assumes the
6 operating risk of the resource used to provide capacity and energy to Idaho Power. Comparing
7 a PPA to a utility-owned facility, if the resource fails to operate as expected, under a PPA,
8 Idaho Power can terminate capacity and energy payments to the third-party supplier if they fail
9 to deliver capacity and energy to Idaho Power.12 This ability to terminate fixed capacity
10 payments to a PPA reduces its debt equivalence attributed by the credit rating agency. In
11 contrast, with a utility-owned facility, the credit rating agency will consider the risk that a utility
12 will develop a facility which fails to operate, in which case the utility will continue to be obligated
13 to make debt service payments for debt it took to finance this facility, or other infrastructure
14 investments, irrespective of whether or not the utility-owned facility actually operates as
15 planned. In this instance, the utility would both be obligated to make debt service payments
16 on the generation resource option it developed and owns, plus it would be obligated to go to
17 the market to buy replacement power costs.
18 Further, Idaho Power acknowledges its cost recovery mechanisms for a PPA may be
19 different than those for a utility-owned facility. Idaho Power states that a utility-owned facility
20 typically would be recovered in the utility's rate case, and recovered through traditional tariff
21 rates. However, a PPA may be subject to the Company's Power Cost Adjustment Mechanism
22 ("PCAM"). The Company states in a discovery response, that its PCAM reflects an actual cost
23 reconciliation relative to the forecast costs, and variances outside of a symmetrical bandwidth
24 are subject to recovery or refund to customers.13 This reconciliation factor within the PCAM
12 Idaho Power's Response to NIPPC's Information Request No. 10.
13 Id.
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Michael P. Gorman
Page 10
1 transfers most of the cost recovery risk of a PPA to customers, and thus reduces the debt-like
2 nature of the PPA in the credit rating process. Hence, credit rating agencies recognize if a
3 utility has less cost recovery risk under a PPA due to the regulatory mechanisms which provide
4 the utility greater assurance of full cost recovery, those cost recovery assurances mitigate the
5 debt-like nature of a PPA compared to utility-owned resources, and would reduce Idaho
6 Power's leverage risk for a PPA relative to a utility-owned resource.
7 Because Idaho Power's recovery mechanisms for PPA costs are not changing, there
8 is no legitimate reason to assume that the PPA debt equivalent will increase by adjusting the
9 risk factor from 25% as it currently exists up to 50%, as Idaho Power proposes. Hence, Idaho
10 Power's debt equivalency adder for a PPA is not only imbalanced and unfair, but it is also
11 intentionally exaggerated in amount.
12
13 Utility-Owned Financial Leverage Cost Adjustments
14 Idaho Power's proposal to include a PPA leverage cost adjustment to fully account for
15 the cost of PPAs is not balanced by making similar financial leverage cost adjustments to
16 reflect additional leverage costs associated with utility-owned resources.
17 Utility-owned resources have investment and operating risks that are greater than
18 those inherent in a PPA, in which case the third party assumes the investment and operating
19 risks. For example, a PPA has far less financial risk to the utility compared to utility-owned
20 facilities for the following reasons:
21 1. A PPA poses little or no cash flow constraints on the utility while the resource is
22 initially being developed. Indeed, Idaho Power acknowledges that under a PPA, it
23 typically would not pay for the capacity and energy from the unit until the unit is
24 actually able to provide capacity and energy to Idaho Power.
25 2. For a utility self-build project, the utility can go through a period of cash deficiency
26 in the resource development stage if, prior to the unit being placed in service and
27 providing service to customers, the resource cost is not included in tariff rates. This
28 cash stress period during development can also impact the utility's financial
29 leverage and generally could result in the utility increasing the equity ratio of its
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Michael P. Gorman
Page 11
1 ratemaking capital structure to accommodate the weak cash flow experienced
2 during the development of a utility-owned resource. The utility cash flow would not
3 be stressed during the development of a PPA resource.
4 3. The PPA exposes the utility to less asset risk than a utility-owned facility.
5 Specifically, if a PPA failed to operate sufficiently and did not provide capacity and
6 energy, then the utility may not be obligated to pay capacity and energy payments
7 to a third-party supplier under the PPA. In some instances, Idaho Power
8 acknowledges that the third-party supplier may be liable to Idaho Power for
9 replacement capacity and energy costs if it failed to perform under the PPA.14 Also,
10 to the extent there is significant prolonged damage to the resources underlying a
11 PPA, Idaho Power may be able to declare the third-party supplier to be in default
12 and can cancel its financial obligations under a PPA.15 The utility may be largely
13 protected from resource failure under a PPA but not under utility ownership.
14 4. Under a utility-ownership scenario, the utility has full asset risk for the generating
15 resource, and will still be obligated to make debt service payments for the funding
16 used to develop or acquire the utility-owned resource even if it has a catastrophic
17 event which removes the resource from public service and precludes full recovery
18 of the utility's costs and outstanding debt from ratepayers.
19 These resource asset development and operating risks would be considered by credit
20 rating agencies in developing the overall leverage risk and financial risk of Idaho Power in a
21 credit rating review. These risks are unique to utility-owned resources, which Idaho Power
22 would need to manage in balancing a capital structure to maintain its financial integrity and
23 investment grade credit standing. These are all financial costs associated with utility-owned
24 resources which would not be risks or costs incurred under a PPA. Ignoring these utility-owned
25 financial costs to manage development and operating risks as an offset to the PPA debt
26 equivalent renders Idaho Power's proposed cost comparison of the various resources inexact,
27 imbalanced, and biased against PPA bids in the RFP.
28 Idaho Power's proposal to include a PPA debt equivalence adder as part of a PPA's
29 cost in an economic comparison of various resource options should be denied.
14 Idaho Power's Response to NIPPC's Information Request No. 9.
15 Id.
BRUBAKER&ASSOCIATES,INC.

Summary of Professional Qualifications and Experience
Michael A Gorman
Mr. Gorman is a Managing Principal at BAI. He received Degrees of
Bachelor of Science in Electrical Engineering from Southern Illinois
University at Carbondale and Master of Business Administration from
WIE -Cft the University of Illinois at Springfield. Mr. Gorman has also done
extensive graduate studies in Financial Economics. He earned the
designation Chartered Financial Analyst(CFA)from the CFA Institute.
Mr. Gorman has been in the consulting practice since 1990, and in the
energy business since 1983. Mr. Gorman was employed by the Illinois
Commerce Commission and held positions including Director of the
Financial Analysis Department, Senior Analyst, Planning Analyst and
Utility Engineer. Mr. Gorman was also employed by Merrill Lynch as a
I Financial Consultant.In this position,he consulted on cash management
and investment strategies.
Areas of Expertise His responsibilities at BAI include project management, cost of capital
Competitive Procurement studies, depreciation studies, financial integrity studies, system resource
Competitive Energy Procurement planning studies, alternative regulation plan/mechanisms, cost of
Price Forecasts service, rate design, production cost evaluations, commodity risk
Risk Management management, commodity procurement management, competitive
Supplier Management supplier management and counterparty credit risk.
Cost of Service/Rate Design
Altemative/Incentive Regulatory
Plans/Mechanisms Proiect Work
Cost of Service
Electric Fuel and Gas Cost
Reviews and Rates
Marginal Cost Analysis
Nuclear Decommissioning Costs
Performance Based Rates
Prudence and Used/Useful
Evaluation
Rate Design and Tariff Analysis
Storage Cost/Necessity
Financial
Asset/Enterprise Valuation
Cost of Capital
Depreciation Studies
Financial Integrity o av
Merger Evaluations fl
(Benefit/Costs)
d
Revenue Requirement Issues
Special Projects
Site Selection and Evaluation
Training Seminars Project Work in Western States
•Oregon,Washington,California,Montana,Wyoming,
Colorado,New Mexico,Idaho,Utah,Arizona,and Nevada
CORPORATE PROFILE —� —
BRUBAKER&ASSOCIATES.IN(..

Attachment 4 :
Idaho Power's Independent Evaluator
Discovery Responses
* Idaho Power's Responses to NIPPC's Interrogatory Nos. 12 & 13

INTERROGATORY NO. 12: Please confirm that under Idaho Power's proposal
for the 2032 RFP, no independent party would score any of the bids, whereas in Idaho
Power's 2026 RFP and 2028 RFP an independent evaluator independently scored bids
consistent with the requirements of the Oregon Public Utility Commission rules. If
confirmed, please explain how this is consistent with the process found reasonable by the
Commission in the 2026 and 2028 RFPs.
ANSWER TO INTERROGATORY NO. 12: While the Company is not proposing
the use of an independent evaluator for this solicitation, Idaho Power is not necessarily
opposed to independent evaluator participation in the RFP selection process so long as
the Company can maintain the proposed timeline to ensure bidders are able to meet in-
service timelines. The Company believes the selection will be conducted through a fair,
transparent, and confidential evaluation process in accordance with the solicitation
procedures. Given the 2032 RFP will be conducted in a substantively similar manner with
past RFPs, which the Commission has found to be fair and reasonable, the Company
believes that additional administrative oversight could introduce unnecessary cost and
schedule risk without providing commensurate benefits. As explained in Idaho Power's
Response to Staff's Request for Production No. 12, the Company will also be coordinating
and sharing information with Commission Staff throughout the process, functioning in an
audit capacity similar to an independent evaluator.
The response to this Request is sponsored by Eric Hackett, Projects and Resource
Development Director, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO NORTHWEST & INTERMOUNTAIN POWER
PRODUCERS COALITION'S FIRST SET OF PRODUCTION REQUESTS AND FIRST SET OF
INTERROGATORIES -22

INTERROGATORY NO. 13: Please confirm that under Idaho Power's proposal
for the 2032 RFP, no independent party would monitor final negotiations of contracts
between Idaho Power and third-party bidders, whereas in Idaho Power's 2026 RFP and
2028 RFP an independent evaluator independently monitored contract negotiations
consistent with the requirements of the Oregon Public Utility Commission rules. If
confirmed, please explain how this is consistent with the process found reasonable by the
Commission in the 2026 and 2028 RFPs.
ANSWER TO INTERROGATORY NO. 13: Please see the Company's Response
to Interrogatory No. 12.
The response to this Request is sponsored by Eric Hackett, Projects and Resource
Development Director, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO NORTHWEST & INTERMOUNTAIN POWER
PRODUCERS COALITION'S FIRST SET OF PRODUCTION REQUESTS AND FIRST SET OF
INTERROGATORIES -23

Attachment 5 :
Idaho Power's Benchmark Bid
Discovery Response
* OPUC Docket No. UM 2255 Idaho Power's Response to Staff Data Request No. 3

UM 2255
Idaho Power Company's Response to Staff's
Data Request Nos. 01-05
TOPIC OR KEYWORD: Scoring & Modeling Methodology and Draft RFP
STAFF'S DATA REQUEST NO. 3: Please provide a detailed narrative of the evaluation process
for benchmark bids under the draft RFP. Please provide all workbooks related to the evaluation
of benchmark bids.
IDAHO POWER COMPANY'S RESPONSE TO STAFF'S DATA REQUEST NO. 3:
As described in section 2.4—IPC SELF-BUILD RESOURCES AND BENCHMARK RESOURCES
of the RFP, Idaho Power has established a Separation of Function standard that bifurcates the
Idaho Power Evaluation Team from the Idaho Power Internal Bid Team. The Internal Bid Team
is allowed to submit a bid (or bids) in response to the RFP in the same manner, with the same
expectations and criteria as any third-party market bidder. As such, the Evaluation Team will
evaluate, score, and model any Internal Bid Team bids in the same manner that would be applied
to a third-party bid.
To ensure unbiased evaluation, the Internal Bid Team bids will be due ahead of market bids. The
Internal Bid Team bids will be scored by the Evaluation Team and scoring submitted to the
Independent Evaluator (IE) within five days of receipt. The IE will validate the Evaluation Team's
scoring and provide their own review and scoring and submit a report to Staff ahead of the
Evaluation Team receiving or opening third-party market bids.
Internal Bid Team bids must meet the same minimum qualifications and provide self-scoring of
the non-price components--the same as a third-party market bid--as well as provide complete
pricing information to be used in the comprehensive price scoring and eventual AURORA
modeling.
A comparative example scoring matrix of an Internal Bid Team bid and two third-party market bids
is included in the attached Excel files. The example shows that the non-price scoring, assuming
all answers to the questions are equivalent, results in the same non-price score. The table below
shows the resulting pricing results of the three example benchmark bids.
Proposal Number 1100201000 1100201100 1100201200
Project Number 1A.Storage 2.1.Storage 2.2.13ESS
Product Type BESS BESS BESS
M W 100.00 100.00 100.00
Levelized ($/mwh) NA NA NA
LCOC - ($/kW/Month) $13.77 $13.77 $13.96
Total Capital Cost (Ex. AFUDC) $150,000,000 $150,000,000
Total Capital Cost (Inc. AFUDC) $155,750,401 $155,750,401
ITC 30% 30%
PTC No No

Attachment 6:
Idaho Power's Price/Non-Price
Allocation Discovery Response
* Idaho Power's Response to NIPPC's Interrogatory No. 15

INTERROGATORY NO. 15: Please explain the points allocation between the
price score and non-price score in the 2032 RFP (e.g., 90%/10%, etc.).
ANSWER TO INTERROGATORY NO. 15: As described in Section 7.2 of the 2032
RFP, the non-price score is worth a total value up to 100 points based on the weightings
of each evaluated factor outlined in Exhibit D — Non-Price Scoring Sheet. The price
evaluation does not include a numbered value for combination with the non-price scoring.
Rather, the price evaluation is based on the relative price ranking of resources within the
same technology. Through the quantitative price evaluation and the qualitative non-price
scoring, the comprehensive set of the highest ranking and relatively lowest cost proposals
become the initial shortlist.
The response to this Request is sponsored by Eric Hackett, Projects and Resource
Development Director, Idaho Power Company.
IDAHO POWER COMPANY'S RESPONSE TO NORTHWEST & INTERMOUNTAIN POWER
PRODUCERS COALITION'S FIRST SET OF PRODUCTION REQUESTS AND FIRST SET OF
INTERROGATORIES -25