20210316Final_Order_No_34959.pdf

ORDER NO. 34959 1

Office of the Secretary
Service Date
March 16, 2021 BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF IDAHO POWER
COMPANY’S 2019 INTEGRATED
RESOURCE PLAN
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CASE NO. IPC-E-19-19

ORDER NO. 34959

On June 28, 2019, Idaho Power Company (“Idaho Power” or “Company”) filed its
2019 Integrated Resource Plan (“IRP”). The IRP outlines and analyzes Idaho Power’s strategy for
meeting its customers’ projected energy needs over the next 20 years. Idaho Power files an IRP
every two years and uses it to guide resource acquisitions. On July 19, 2019, Idaho Power filed a
letter stating that it would need to perform supplemental analysis to confirm the accuracy of the
IRP’s conclusions and findings. Idaho Power expected to file its additional analysis by October
31, 2019.
On August 13, 2019, the Commission issued a Notice of Application acknowledging
Idaho Power’s requested extension of time and stating the Commission would issue a Notice
establishing procedure and deadlines after Idaho Power submitted its updated 2019 IRP analysis.
Order No. 34410. On October 28, 2019, Idaho Power filed a letter stating it would need until
November 8, 2019, before it could provide a new estimated filing date. On November 8, 2019,
Idaho Power filed a letter stating it would file its supplemental IRP analysis no later than January
31, 2020. On January 31, 2020, Idaho Power filed its amended 2019 IRP.
On March 4, 2020, the Commission issued a Notice of Amended Integrated Resource
Plan and Notice of Intervention Deadline. Order No. 34572. On May 13, 2020, the Commission
issued a Notice of Modified Procedure establishing a July 22, 2020 comment deadline and an
August 26, 2020 reply comment deadline. Order No. 34665.
On June 1, 2020, Idaho Power submitted replacement pages to its IRP updating costs
associated with the Jim Bridger power plant. On July 1, 2020, Idaho Power filed “Idaho Power
Company’s Motion to Suspend Procedural Schedule and Update Regarding Boardman to
Hemingway Transmission Line Project.” On July 16, 2020, the Commission vacated the comment
deadlines until further notice. Order No. 34723.
On July 31, 2020, Idaho Power submitted an update stating it would file a “final update”
on October 2, 2020. On October 2, 2020, Idaho Power submitted an Amended Application and a
ORDER NO. 34959 2

Second Amended 2019 Integrated Resource Plan. On November 16, 2020, the Commission issued
a Notice of Amended Application and Notice of Revised Comment Deadlines. Order No. 34834.
Idaho Conservation League (“ICL”), Idaho Hydroelectric Power Producers Trust, d/b/a
IdaHydro, Industrial Customers of Idaho Power, STOP B2H COALITION (“STOP B2H”),
Micron Technology, Inc. (“Micron”), and Sierra Club intervened in this docket. The Commission
received extensive written comments from interested members of the public.
Having reviewed the record, we acknowledge Idaho Power’s 2019 Second Amended
IRP.
THE IRP PROCESS
An IRP is a status report on the utility’s ongoing, changing plans to adequately and
reliably serve its customers at the lowest system cost and least-risk over the next 20 years. The
report informs the Commission and the public about the utility’s plans, and is similar to an
accounting balance sheet, e.g., it is a “freeze frame” look at the utility’s fluid, resource planning
process. See Order No. 22299. The IRP is meant to demonstrate to the public that Idaho Power
has prepared for, and considered, many scenarios through a reasonable planning process. The
Commission thus expects a utility to have vigorously tested the IRP’s assumptions to ensure the
IRP accurately reflects changing markets and customer demand.
Idaho Power must update its IRP every two years and allow the public to participate in
its development. See id.; Order No. 25260. The final biennial IRP must include the subjects
required by the Commission’s prior orders, including Order Nos. 22299, 25260. In summary, the
IRP should explain Idaho Power’s present load/resource position, expected responses to possible
future events, and the role of conservation in those responses. It also should discuss:
any flexibilities and analyses considered during comprehensive
resource planning, such as: (1) examination of load forecast
uncertainties; (2) effects of known or potential changes to existing
resources; (3) consideration of demand- and supply-side resource
options; and (4) contingencies for upgrading, optioning and
acquiring resources at optimum times (considering cost, availability,
lead time, reliability, risk, etc.) as future events unfold.

Order No. 22299. The IRP should separately address Idaho Power’s:
• “Existing resource stack,” by identifying all existing power
supply resources;

• “Load forecast,” by discussing expected 20-year load growth
scenarios for retail markets and for the federal wholesale
ORDER NO. 34959 3

market including “requirements” customers, firm sales, and
economy (spot) sales. This section should be a synopsis of
the utility’s present load condition, expectations, and level
of confidence; and

• “Additional resource menu,” by describing the utility’s plan
for meeting all potential jurisdictional load over the 20-year
planning period, referring to expected costs, reliability, and
risks inherent in credible future scenarios.
Id.
If the Commission finds the IRP discusses these required subjects, then it will enter an
Order acknowledging that Idaho Power filed the IRP. By acknowledging the IRP, the Commission
is acknowledging Idaho Power’s ongoing planning process, not the conclusions or results reached
through that process.
The 2019 IRP is Idaho Power’s 14th resource plan prepared for state regulators. Second
Amended 2019 IRP at 8. The 2019 IRP evaluated the planning period from 2019 to 2038. Id.
Idaho Power described the four primary goals of the IRP as:
1. Identify sufficient resources to reliably serve the growing
demand for energy and flexible capacity within Idaho Power’s
service area throughout the 20-year planning period.

2. Ensure the selected resource portfolio balances cost, risk, and
environmental concerns.

3. Give equal and balanced treatment to supply-side resources,
demand-side measures, and transmission resources.

4. Involve the public in the planning process in a meaningful way.
Id.
THE 2019 IRP REVIEW AND AMENDMENT PROCESS
In its review of the 2019 IRP, Idaho Power created teams of subject matter experts to
examine the data used in the IRP model.1 Id. at 2. Idaho Power then ensured that the data was in
the correct format for the model. Id. at 3. Idaho Power then examined the model settings to ensure
the data was interacting with the model in a logical manner and consistent with Idaho Power’s
knowledge of its own system and resources. Id. Idaho Power then reviewed the model output for

1 For a comprehensive account of the Company’s efforts to review and revise its 2019 IRP, see the 2019 IRP Review
Report: Process and Findings, October 2020.
ORDER NO. 34959 4

consistency and accuracy. Id. Through this process, Idaho Power identified several adjustments
to its coal plant inputs and cost treatment, its natural gas plant inputs, demand response, financial
assumptions and future supply-side resources, transmission inputs, and reliability inputs. Id. at 3
– 6. Idaho Power stated this process resulted in only one change to its near-term Action Plan, the
accelerated exit from Valmy Unit 2. See Id. at 6.
To develop the 2019 IRP, the Company used for the first time the long-term capacity
expansion (“LTCE”) capability of AURORA to produce portfolios optimized to the Western
Energy Coordinating Council (“WECC”) territory.2 Id. at 102. AURORA LTCE develops
portfolios based on different planning assumptions about future natural gas and carbon costs. Id.
at 103. For example, a future scenario with a high natural gas price and/or a high cost of carbon
would be expected to have a lot of non-carbon emitting resources such as wind and solar because
such a portfolio would likely be economic under such a scenario. Id. at 10. Idaho Power explained,
Under the capacity expansion modeling approach used for the 2019
IRP, the AURORA model selects from the variety of supply- and
demand-side resource options to develop portfolios that are least-
cost for the given alternative future scenarios with the objective of
meeting a 15-percent planning margin and regulating reserve
requirements associated with balancing load, wind, and solar-plant
output. The model can also select to retire existing generation units,
as well as build resources based on economics absent a defined
capacity need.
Id. at 10 (emphasis in original).
A subset of the top performing WECC-optimized portfolios were then manually
adjusted by Idaho Power to reduce portfolio costs for the Idaho Power system. Id. at 102. Idaho
Power evaluated 48 total portfolios, 24 of which were developed by the LTCE model and 24 of
which were developed during the manual adjustment process. Id. at 104.
After the portfolios were developed using the LTCE function of AURORA then
grouped together and manually optimized, Idaho Power used AURORA’s portfolio cost analysis
function to determine the portfolios’ operating costs over the 20-year planning horizon. See id. at
111. Idaho Power explained,
The AURORA software applies economic principles and dispatch
simulations to model the relationships between generation,
transmission, and demand to forecast market prices. The operation

2 AUORA is an energy system modeling software developed by the company Energy Exemplar.
ORDER NO. 34959 5

of existing and future resources is based on forecasts of key
fundamental elements, such as demand, fuel prices, hydroelectric
conditions, and operating characteristics of new resources. Various
mathematical algorithms are used in unit dispatch, unit commitment,
and regional pool-pricing logic. The algorithms simulate the
regional electrical system to determine how utility generation and
transmission resources operate to serve load.
Id. at 111.
Idaho Power’s 2019 preferred portfolio is based on planning gas and planning carbon
conditions and selects B2H. Id. at 6. Idaho Power stated its Second Amended 2019 IRP “continues
to demonstrate a clear cost-effective and reliable trajectory toward Idaho Power’s clean energy
future.” Idaho Power’s Reply Comments at 1. Idaho Power’s near-term Action Plan, from 2020
to 2026, contains the following elements:
(1) adding 120 [MW] of new solar generation by 2022; (2) exiting
from four coal-fired units by year-end 2022, and from five of [Idaho
Power’s] seven coal-fired units by year-end 2026; and (3)
completing the [B2H] transmission line by 2026. The development
of B2H, in particular, provides a crucial carbon-free and cost-
effective, supply-side resource that supports renewables and enables
[Idaho Power’s] transition away from coal.
Id.
THE COMMENTS AND REPLY COMMENTS
Two major issues emerged in Idaho Power’s 2019 IRP process: (1) Idaho Power’s use
of the AURORA LTCE to develop portfolio scenarios, and (2) Idaho Power’s analysis of the
proposed B2H transmission line, specifically (a) partner commitments, and (b) market availability
at the Mid-Columbia Interconnect (“Mid-C”). The parties’ comments on these issues are presented
together, along with Idaho Power’s reply. The parties’ other comments follow.
a. The AURORA LTCE.
Staff advised the Commission not to rely on Idaho Power’s Second Amended IRP when
making prudency determinations because the LTCE was optimized to the WECC, not Idaho
Power’s balancing authority. Staff Comments at 3. Staff expressed concern that the AURORA
LTCE software may not be the tool for Idaho Power’s IRP planning process. Id. Staff’s concerns
are rooted in its belief that optimizing portfolios to the WECC in the LTCE and then manually
adjusting a subset of top performing portfolios may not result in a least-cost least-risk portfolio for
ORDER NO. 34959 6

Idaho ratepayers. Id. at 4. Staff stated that the needs of the WECC are not necessarily the same
as the needs of Idaho Power. Id. at 5. As an example, Staff pointed to the inconsistent and
counterintuitive results Idaho Power obtained when modeling the Jackpot Solar PPA in the
WECC-optimized LTCE, which led to Idaho Power’s first request to suspend the 2019 IRP. Id. at
5. Staff described its concerns with Idaho Power’s manually adjusted portfolios as:
Although somewhat more cost effective for Idaho Power’s
customers, [Idaho Power] did not adequately explain the criteria for
selecting these particular portfolios for manual adjustment, why it
focused on timing of [Idaho Power’s] exit from Bridger, and why
manually adjusting WECC-optimized portfolios might be expected
to produce the best results for Idaho Power’s ratepayers.
Id.
Staff commended Idaho Power for withdrawing and revising its 2019 IRP and First
Amended IRP upon learning that the analyses were flawed but doesn’t believe Idaho Power
addressed the underlying issue—the LTCE optimized the portfolios to the WECC instead of Idaho
Power’s service territory—in its Second Amended IRP. Id. at 6. Staff stated that Idaho Power
should choose an objective function that optimizes portfolios to Idaho Power’s system and iterated
“that to be deemed prudent, [Idaho Power] must be able to demonstrate that proposed investments
are in the best interests of Idaho Power’s ratepayers, and not the WECC.” Id.
Staff expressed concern that Idaho Power chose a tool—AURORA’s LTCE—that is
incapable of optimizing to Idaho Power’s system and stated that Idaho Power should better define
its goals when selecting a capacity expansion tool. Id. at 6-7. Staff also expressed concerns about
Idaho Power’s validation of the capacity expansion software. Id. at 7. Staff explained, “Software
validation is the formal process of assuring that software is capable of meeting the requirements
identified during the model selection process.” Id. Staff stated that Idaho Power should have
validated the model before buying the modeling software and accepting it for use. But instead,
issues Idaho Power should have identified during software validation were not discovered until
after the 2019 IRP was submitted. Id. at 7-8. Although Staff was concerned with Idaho Power’s
software validation, Staff was encouraged that Idaho Power verified that the LTCE model’s results
were consistent with Idaho Power’s operations when developing the Second Amended 2019 IRP.
Id. at 8.
ICL stated it has long recommended Idaho Power use capacity expansion software to
model portfolios, and it believes Idaho Power considered a range of alternatives despite having to
revise the IRP. ICL Comments at 2. ICL stated each revision showed the most economic choice
ORDER NO. 34959 7

for Idaho Power’s customers is for Idaho Power to exit coal plants, especially when Idaho Power
focused the analysis on the value to Idaho Power customers, rather than the WECC. Id.
Sierra Club supported Idaho Power’s use of a capacity expansion model and stated that
the model may have led to outcomes that otherwise would not have been immediately apparent to
planners. Sierra Club Comments at 1-2. Sierra Club described the 2019 IRP modeling process as
a “dramatic improvement” over the 2017 IRP. Id. at 2. Sierra Club stated that as Idaho Power
refined its analyses in the 2019 IRP, accelerating the closure of the Jim Bridger coal plant emerged
as the best option for Idaho Power’s customers. Id. Sierra Club noted that Idaho Power owns 1/3
of Jim Bridger and PacifiCorp owns the rest. Id. Sierra Club stated the two utilities have expressed
different timelines for exit/retirement, “Specifically, whereas Idaho Power is seeking exit from one
Bridger unit as early as 2022 and a second Bridger [unit] in 2026, PacifiCorp announced they
intend to only exit Jim Bridger 1 ‘by the end of December 2023,’ and Bridger 2 by 2028, delays
of a year and two years, respectively.” Id. Sierra Club asked the Commission to not let PacifiCorp
“hold Idaho Power hostage” to the “political machinations” in Wyoming, a state “openly hostile
to the closure of non-economic coal plants.” Id.
Sierra Club made three recommendations for modeling in the 2021 IRP process: 1)
improve how AURORA values storage; 2) review projected net market purchases for
reasonableness; and 3) make a more realistic estimate of future summer peak load growth. Sierra
Club stated that the 2019 portfolios generated by AURORA “failed to include appropriate levels
of storage, undermining the ability of [Idaho Power] to introduce more Idaho sited renewable
energy cost effectively.” Id. at 3. Sierra Club stated that it is unrealistic to assume that no new
storage will come online in Washington, Oregon, and California in future years, and therefore the
model likely assumes that large amounts of variable generation will be exported, which would
suppress market prices in the model creating a bias toward west coast wholesale markets. Id. at 3-
4.
STOP B2H alleged Idaho Power “manipulated the [AURORA] model base case data
inputs . . . to stage the model for the next IRP. Perhaps the clearest example of this manipulation
of the [AURORA] model is Idaho Power’s unexplained sensitivity analysis around peaker O&M
costs.” STOPB2H Comments at 28. STOP B2H stated, “In this Second Revised 2019 IRP
modeling, Idaho Power has fundamentally changed the dispatch logic for Idaho Power peakers by
moving variable O&M costs (which accrue as the unit is operated) to a single startup cost which
is incurred only when the unit is started.” Id. STOP B2H stated that in the Second Amended 2019
ORDER NO. 34959 8

IRP, “Idaho Power eliminated the roughly $3 MWh variable O&M adder in AURORA and
replaced it with an hourly adder of over $100 per MWh for the first hour of operation.” Id. at 29.
STOP B2H said there were significant modifications to the amended IRP and that Idaho Power’s
responses to questions about its modeling were concerning. Id. STOP B2H alleged that Idaho
Power included over 1,800 MW of “phantom coal generation” selling into the Mid-C market in
AURORA. Id. at 35. STOP B2H also alleged Idaho Power did not include Bonneville Power
Administration (“BPA”) wheeling charges assessed to Idaho imports from the Pacific Northwest.
Id. at 35.
Idaho Power Reply: In response to Staff concerns about model selection and
validation, Idaho Power acknowledged a learning curve in the 2019 IRP process that it stated will
be leveraged in the 2021 IRP process. Idaho Power Reply Comments at 26. Idaho Power stated
the most current version of AURORA can optimize concurrently to the WECC and Idaho Power’s
system, a function the prior version did not have. Id. at 29. Idaho Power also noted “the
importance of the model’s ability to concurrently optimize resources for both Idaho Power’s
system and the broader WECC to produce market prices and operating conditions that are
representative of specific modeled scenarios.” Id. at 26-27. Idaho Power noted that the market
for LTCE software is limited and stated that it reviewed software options using pre-defined criteria
before it selected AURORA as the best option for Idaho Power’s needs. Id. at 27-29.
Idaho Power responded to STOP B2H criticisms about Idaho Power’s inclusion of
startup costs for natural gas peaker plants in its Second Amended 2019 IRP. Id. at 46-47. Idaho
Power stated it made the adjustment after it realized its natural gas peakers were dispatched more
frequently in the model than in reality. Id. at 47. Idaho Power stated it carefully examined the
costs associated with natural gas peakers O&M and startup costs and updated the model to more
accurately reflect the actual costs incurred when dispatching a peaker plant. Id. at 47.
Idaho Power described its process of developing WECC-optimized portfolios through
the AURORA LTCE model and manually adjusting them to identify portfolios based on Idaho
Power’s system needs. Id. at 24 – 40. Idaho Power acknowledged that its demand is approximately
2 percent of WECC overall average demand. Id. at 32. Idaho Power explained that it is important
for AURORA to account for all WECC resources because the cost to serve Idaho Power’s system
depends on the resources selected for the WECC, because these resources affect market prices in
the model. Id. at 31-32. Idaho Power stated, “While the objective function for the initial LTCE
portfolios was to optimize for the WECC (of which Idaho Power’s system is part), the series of
ORDER NO. 34959 9

manual adjustments changed that objective function to identify the least-cost, least-risk portfolio
specifically for Idaho Power’s system.” Id. at 32. Idaho Power stated that the manual optimization
process began with Idaho Power grouping WECC-optimized portfolios that had similar resource
buildouts and timing. Id. at 33. Idaho Power stated that grouping WECC-optimized portfolios
allowed Idaho Power to evaluate a variety of portfolios for manual optimization, responding to a
prior critique that Idaho Power had evaluated a narrower selection of portfolios, allowed Idaho
Power to determine if further cost reductions were possible for Idaho Power’s specific system
needs, and provided a reasonable level of assurance that the least-cost, least-risk resource
portfolios were analyzed. Id. at 34. Idaho Power stated its manual adjustment process focused on
identifying the optimal exit scenarios for Idaho Power’s Jim Bridger coal units. Id. Idaho Power
evaluated B2H and non-B2H portfolios for: Planning Gas-Planning Carbon, Planning Gas-High
Carbon, and High Gas-High Carbon. Id. Idaho Power described the guiding principles for
adjusting these portfolios. Id. at 35. These manual adjustments resulted in 18 new portfolios. Id.
at 36.
Idaho Power then applied a fourth manual adjustment, which it applied to each
carbon/gas planning future with and without B2H, which resulted in eight additional manually
adjusted portfolios. Id. Idaho Power described the parameters for this adjustment, which aimed
to test the cost-effective adoption of flexible resources at different sizes while accelerating solar
and battery resources and reducing reliance on thermal resources. Id. at 36-37. Idaho Power
determined manual adjustments under this fourth scenario exercise did not produce a lower-cost
portfolio compared to the prior three manually adjusted scenarios. Id. at 37. In sum, Idaho Power’s
manual adjustment process resulted in it using AURORA to evaluate 24 more portfolios to
determine their net present value. Id. at 37-38.
b. Boardman to Hemingway.
Staff expressed several concerns with Idaho Power’s B2H analysis. Staff Comments
at 8 – 11. First, Staff noted the analysis was conducted using WECC-optimized portfolios. Id. at
8. Second, Staff stated the analysis made “overly optimistic assumptions about the availability of
power in the Pacific Northwest for import into Idaho Power’s system.” Id. Staff noted that Idaho
Power did not evaluate the potential impacts of Washington’s Clean Energy Transformation Act
(“CETA”) on the energy available for export from Boardman to Idaho Power’s system. Id. at 9.
Third, Staff stated Idaho Power did not analyze the substantially increased ownership share in B2H
that Idaho Power is contemplating as its potential partners in the transmission line, PacifiCorp and
ORDER NO. 34959 10

BPA, explore alternatives. Id. at 8. Staff stated that BPA excluded B2H from the 2020 BPA
Transmission Plan, which describes BPA’s ten-year system expansion and reinforcement plans.
Further, PacifiCorp’s 2019 IRP described B2H as “an alternative to PacifiCorp’s originally
proposed transmission segment from Eastern Idaho into Southern Oregon.” Id. at 10 citing
PacifiCorp 2019 IRP at 83.
Staff also stated Idaho Power’s inadequate B2H investment evaluation left three areas
of risk. First, Staff stated, “Forecasting future market prices for a capacity resource that has not
been identified, and may not exist, is not a reliable method for evaluating costs associated with the
B2H line.” Id. at 9. Second, competition from other regional utilities looking for capacity
resources will affect regional resource adequacy. Id. Third, neighboring states’ clean energy
policies will constrain capacity resource options. Id. at 9 – 10. Staff also stated that Idaho Power’s
2019 IRP did not analyze a potential additional 24 percent ownership share (that coincides with
BPA’s ownership share) even though Idaho Power disclosed to the Securities and Exchange
Commission that it was investigating a “hypothetical 45% ownership.” Id. at 10 citing SEC Form
8-K. Staff stated that BPA has advanced policies that “build at the smallest scale possible to meet
customer needs.” Id. at 11 citing Department of Energy, BPA Executive letter from Elliot Mainzer
to parties interested in the I-5 Corridor Reinforcement Project. Staff recommended Idaho Power
provide a detailed analysis of 45 percent and 100 percent ownership shares of B2H during the next
IRP cycle. Id. at 11. Staff asserted there would be potential tax implications if Idaho Power took
on additional B2H ownership. Id. Staff also noted that Idaho Power proposes using B2H, a project
estimated to cost $1 billion to $1.2 billion, with a 21 percent ownership share at $292 million, to
fill a 5 MW capacity deficiency in August 2029. Id.
STOP B2H expressed concerns about B2H project costs and partner commitments.
STOP B2H Comments at 7-12. STOP B2H stated that financial risk disclosures portrayed a
different B2H risk scenario than presented in Idaho Power’s IRP. Id. at 4, 12-16. STOP B2H
disagreed with Idaho Power’s assessment that Mid-C is a flexible, liquid, and reliable market. Id.
at 5. STOP B2H stated that the Northwest Power and Conservation Council (“NWPCC”) projects
upcoming resource inadequacy at Mid-C, which STOP B2H stated will drive prices up at Mid-C.
Id. STOP B2H noted that in IPC-E-19-14, Commission Staff determined the Jackpot PPA would
cost Idaho Power less than Mid-C purchases over 20 years. Id. STOP B2H stated Idaho Power
hasn’t effectively evaluated market purchases from other major market hubs. Id.
ORDER NO. 34959 11

STOP B2H disputed Idaho Power’s statement that its ability to transact at Mid-C is
transmission constrained. Id. STOP B2H noted that Idaho Power routinely exceeds the
transmission line’s 1200 MW commercial rating and that STOP B2H could not identify a specific
date on which Idaho Power could not buy the power it wanted from Mid-C. Id. STOP B2H
claimed Idaho Power operates its transmission Path 14 (to Mid-C) differently from its other
transmission resources. STOP B2H noted that, in contrast to BPA and other utilities, Idaho Power
refused to accept conditional firm energy on Path 14. Id. STOP B2H stated Idaho Power is not
considering non-wire solutions, but other utilities are. Id. at 6.
STOP B2H doubted that Idaho Power’s strategy to buy from Mid-C reflects a
commitment to a clean energy future. Id. at 20. STOP B2H examined AURORA’s carbon
emissions forecast and highlighted that the preferred portfolio carbon forecast predicts greenhouse
gas emissions will be 3.5 percent higher in 2028 than in 2019. Id. at 21. STOP B2H stated, “This
persistent increase in Idaho Power’s CO2 emissions occurs despite the addition of the 120 MW
Jackpot Solar and the exit of one Bridger unit in 2022, the exit of a second Bridger unit in 2026
and the addition of B2H in 2026. In fact, in the three years after adding B2H (2026-2028), CO2
emissions on the Idaho Power system continue to increase.” Id. at 23. STOP B2H stated that B2H
is a clear path to a high-carbon future for Idaho Power. Id.
Idaho Power Reply: Idaho Power stated that it is negotiating with PacifiCorp and
BPA about potential ownership and cost responsibility agreements for B2H. Idaho Power Reply
Comments at 3. Idaho Power noted its July 1 and July 21, 2020 letters to the Commission advised
the Commission that Idaho Power is exploring the acquisition of BPA’s 24 percent ownership
share. Id. Idaho Power stated BPA or its customers would pay for their respective usage of B2H.
Id. Idaho Power emphasized that it is still negotiating with BPA and PacifiCorp, has no updates
to report, expects the ownership agreements will be finalized by the time Idaho Power files its
2021 IRP. Further, Idaho Power stated it believes the negotiations on the ownership arrangements
will not materially impact the 2019 preferred portfolio or the action items. Id. at 4. Idaho Power
stated it will not agree to ownership arrangements that shift cost risks to its customers without
corresponding increases in benefit. Id. at 5. Idaho Power stated it believes PacifiCorp remains
committed to Idaho Power’s longstanding plan to own 55 percent of B2H. Id. at 6. Idaho Power
agreed to consider Staff’s concerns, such as tax and cost implications of Idaho Power assuming a
greater ownership in B2H in its 2021 IRP. But Idaho Power claimed these concerns are immaterial
ORDER NO. 34959 12

for this IRP cycle because Idaho Power would not expose its customers to increased costs without
a commensurate increase in benefits due to partnership changes. Id. at 7, 9.
Idaho Power stated it evaluated B2H within AURORA based only on B2H’s benefits
to Idaho Power’s native load customers, not on B2H’s benefit to the WECC. Id. at 10. Idaho
Power stated that B2H is a lower capital cost resource than other options (e.g., $626 per kW-peak
for B2H compared to $1,294 per kW-peak for a combined-cycle combustion turbine) and would
increase market purchases between the Pacific Northwest and Idaho. Id. Idaho Power stated that
B2H’s benefits to other entities will be compensated and the revenue will flow back to Idaho
Power’s retail customers. But to ensure a conservative financial picture, Idaho Power’s 2019 IRP
did not consider these potential third-party revenues. Id. at 10-11. Idaho Power also noted the 20
percent cost contingency factored into the B2H costs are unique to B2H and not utilized for other
resources. Id. at 11. Idaho Power compared the top performing portfolios with and without B2H
to estimate that B2H could still be cost effective even if B2H costs 30-35 percent more than Idaho
Power’s current 20 percent contingency estimate. Id. at 12. Idaho Power stated it is consulting
with an engineering firm to revise its B2H cost estimate, intends to revise the 2021 IRP’s cost
estimate, and is evaluating whether to continue to include a contingency in its B2H cost estimates
when it does not do so for other resources. Idaho Power also stated the 2021 IRP would incorporate
a sensitivity analysis. Id.
Idaho Power reiterated that B2H is foundational to a clean energy future. Id. at 13.
Idaho Power responded to Staff’s concerns about market availability in the Northwest by stating
the Northwest has ample hydro capacity resources, which will pair well with renewable energy
resources. Id. at 14-15. Idaho Power disagreed with Staff’s assessment that CETA will negatively
affect Idaho Power’s ability to acquire power from wholesale markets because the referenced
studies include committed retirements without factoring in future resource plans or additions, and
are only two data points of many provided by Idaho Power in Appendix D. Id. at 15. Idaho Power
stated that CETA would lead the Northwest to build substantial renewables with corresponding
firm, potentially non-thermal, capacity. Id. at 15-16. Idaho Power emphasized that it and other
utilities will still have to meet reliability requirements even when transitioning away from thermal
generation, and that the region will build out resources to meet winter peak needs, which Idaho
Power stated are likely to grow with electrification, leaving excess resource availability in the
summer. Id. at 16.
ORDER NO. 34959 13

Idaho Power described Mid-C as a “deep market hub, with dozens of counterparties”
that is “very liquid” with daily average trading volume on a day ahead basis during heavy-load
hours in June and July from 10,000 MWh to 29,000 MWh. Id. Idaho Power summarized the
NWPCC’s Pacific Northwest Power Supply Assessment for 2024 as continuing to show that the
Northwest primarily faces issues during the winter, while Idaho Power’s peaks are in late June and
early July. Id. at 17. Idaho Power stated that it anticipates the Northwest’s new resources will be
largely solar-plus-storage, and wind-plus-storage, which are even more effective at addressing
summer peak than winter peak. Id. at 18. Additionally, B2H could be used to import remote
renewable resources to load centers when the Mid-C lacks adequate market capacity. Id. at 19.
Idaho Power stated B2H would provide a different value to its customers than would individual
projects like solar projects because B2H would be a firm, diverse resource that could provide
energy after the sun goes down. Id. Idaho Power expressed that STOP B2H incorrectly claimed
that Idaho Power improperly included “phantom coal generation” and excluded BPA wheeling
rates from B2H modeling. Idaho Power also provided the retirement dates for the coal resources
and asserted it modeled the BPA wheeling rates in the B2H segment. Id. at 19-20.
Idaho Power described the difference between a transmission line’s commercial
transmission capacity and its actual power flows. Id. at 20-21. Idaho Power explained that the
transmission path between the Northwest and Idaho (Path 14) has a commercial transmission
capacity of 1,200 MW, which means that the transmission provider cannot allocate more than
1,200 MW of firm transmission requests. Id. at 21. Idaho Power acknowledged that over the past
few years, Path 14 has had “adverse unscheduled flow” above the 1,200 MW rating, sometimes
by hundreds of MW, but this does not mean that capacity is unconstrained. Id. Idaho Power stated
that B2H provides an ancillary and unquantified benefit: B2H’s 1,050 MW of West-to-East
capability would offer operational flexibility and decrease adverse loop flow that could otherwise
result in a transmission line exceeding its rated capacity. Id. at 21-22. Idaho Power stated that the
grid faces significant stresses and is mostly constrained by transmission rather than generation. Id.
at 22. Idaho Power pointed to the summer 2020 rolling outages in California as a prime example
and noted that resources were available at Mid-C, but transmission availability limited the ability
to move resources to load. Id. Idaho Power also pointed to FERC- and NERC-approved rules
requiring margins in response to STOP B2H’s concerns that Idaho Power is improperly
representing transmission availability. Id. at 22-26.
c. Commission Staff Comments.
ORDER NO. 34959 14

Staff stated Idaho Power improved its peak load forecast in its load and resource
balance (“L&RB”) compared to the 2017 IRP by, for example, improving the way it models the
relationship between peak load and consumption drivers such as temperature. Staff Comments at
12. Staff also recommended Idaho Power include its L&RB in future IRPs, as Idaho Power has
done in the past, so that stakeholders can readily access the information rather than have to request
it through Production Requests. Id. Staff also reiterated its two recommendations from the 2017
IRP case that were not incorporated in the 2019 IRP. Specifically, Idaho Power should 1) obtain
peak forecasts by aggregating results from individual classes, and 2) provide a sensitivity analysis
with its forecast. Id. at 13.
Staff proposed Idaho Power modify how it determines first capacity deficit dates for
PURPA contracts. Id. at 12. Staff stated that Idaho Power should assume all PURPA contracts,
including wind, will be renewed when they expire. Id. at 14. Staff also stated there should be a
market availability component to determining transmission capacity and that the lower of the two
values should be used. Id. at 15. Staff also recommended that non-owned reserves (such as
municipal and cooperative electric companies) be included as a decrease in existing resources
because Idaho Power uses its own resources to provide non-owned reserves. Id. Staff also stated
Idaho Power should change how it portrays its energy efficiency in the peak L&RB by clarifying
that it includes existing and “expanded” or cost-effective energy efficiency. Id.
Staff recommended Idaho Power improve how Idaho Power implements regulation
reserve requirements in the IRP modeling process. Id. at 16. Staff stated Idaho Power should also
explore the impacts of reserve shortfalls from reliability and cost perspectives. Id. Staff stated,
“it is not known if shortfalls result in unacceptable loss of load; how much it costs for [Idaho
Power] to fulfill any shortfalls; and whether the costs are added into the costs of portfolios.” Id.
at 16-17.
Staff noted that the Original 2019 IRP used a 9.59 percent discount rate, which included
Idaho Power’s WACC plus a tax gross-up for the equity-financed portion of the overall costs. Id.
at 17. In the 2019 IRP’s subsequent iterations, Idaho Power reverted to using a 7.12 percent
discount rate that reflects the after-tax WACC. Id. Staff stated that it agreed with the reversion to
the after-tax WACC discount rate but looks forward to Idaho Power’s additional analysis and
justification for a post-tax WACC discount rate. Id.
Idaho Power Reply: Idaho Power responded to critiques by Commission Staff, Sierra
Club, and STOP B2H about its peak forecasting. Idaho Power Reply Comments at 54-62. Idaho
ORDER NO. 34959 15

Power stated that “it is important to first consider the performance of the current model when
evaluating whether the proposed changes will result in a more robust model with improved
accuracy.” Id. at 55. Idaho Power expressed concern that Staff’s bottom-up approach (aggregating
individual customer classes) would not improve accuracy over the current systemwide approach
because the systemwide approach “leverages the rich system-level historical data, which allows
the models to capture the nuances of peak behavior.” Id. at 56. Idaho Power stated its present
approach considers several variables that consumption modeling does not, such as “average daily
peak temperature, average daily peak temperature trend, average system MW, and multiple
indicator variables (e.g., adjustments for impacts related to the 2001 energy crisis).” Id. Idaho
Power stated that a bottom-up approach would rely on a regression analysis using advanced
metering infrastructure (“AMI”) data. Id. Idaho Power stated its reliable bulk AMI data only goes
back to 2014. Id. Additionally, the system peak data includes peak losses, which are about 8 to
12 percent, and the bottom-up approach would introduce additional uncertainty for calculating
losses. Id. at 56-57. Idaho Power agreed that class peak dynamics are important to know and
therefore, in response to Staff’s recommendation, proposed that class-level AMI data be used to
inform assignments of class contribution to system peak. Id. at 57. Idaho Power also agreed its
future IRPs would analyze class-level peak contribution and include sensitivity or probability
bands of its system peak forecast. Id.
Idaho Power stated that it retained Energy and Environmental Economics, Inc., to
conduct a variable energy resource integration study, which included examining new regulation
reserve requirements for the 2021 IRP. Id. at 39. Idaho Power agreed to explore the cost and
reliability impacts from reserve shortfalls during the 2021 IRP process. Id.
Idaho Power responded to Staff critiques about the L&RB. Id. at 68-72. Idaho Power
disagreed with Staff’s recommendation to assume all QFs, including wind QFs, would renew their
ESAs upon expiration. Id. at 68-69. Idaho Power listed factors it considered when deciding to
assume that wind QFs would not renew their ESAs, including “the high cost of repowering wind
facilities, reductions and/or elimination of tax credits applicable to wind projects, current
integration costs for wind, and the notable fact that none of Idaho Power’s wind QFs have
requested or entered into replacement ESAs.” Id. at 69. Idaho Power noted that of its 32 wind QF
ESAs, the first is set to expire in 2025. Id. Idaho Power noted that four hydro QFs, two biomass
QFs, and two cogeneration QFs did not renew contracts; thus, assuming renewal for any resource
type adds risk to planning. Id. Idaho Power recognized that wind repowering does occur but Idaho
ORDER NO. 34959 16

Power has no evidence to support intent or interest in repowering wind QFs. Id. at 70. Idaho
Power stated it is open to revising its assumption as more QF wind replacement information
becomes available, and its next IRP will include a sensitivity analysis about wind replacement
assumptions and their impacts on resource planning. Id. Idaho Power agreed with Staff’s
recommendation that market availability should be evaluated alongside transmission capacity. Id.
Idaho Power also agreed that the L&RB evaluation should include the contingency reserve
requirements to serve transmission customers. Id. at 71. Idaho Power stated its L&RB already
includes all cost-effective energy efficiency (“EE”) measures, not just existing EE. Id. at 72.
d. ICL Comments.
ICL stated, “Overall, the 2019 IRP evidences a substantial improvement in Idaho
Power’s portfolio development and assessment process.” ICL Comments at 1. ICL recommended
the Commission acknowledge the IRP. Id. ICL also recommended the Commission direct Idaho
Power to: 1) use publicly available forecasts for the natural gas price forecast and other critical
inputs, or require Idaho Power to disclose all data, methods, and assumptions used for any
proprietary forecast; 2) continue to improve its assessment of climate impacts on load and
generation; 3) include distribution level planning in future IRPs to reflect the growth of DERs; and
4) issue a Request for Proposals to collect current and location-specific information on potential
generation resources. Id. at 1-2.
ICL acknowledged that Platt’s, the third-party vendor that created Idaho Power’s
natural gas forecast, presented its overall method and results to the IRPAC. But ICL claimed the
IRPAC could not fully review the underlying basis for the price forecast. Id. ICL stated that Idaho
Power merely listed other utilities that use proprietary forecasts and recommended Idaho Power
analyze which gas price source has accurately predicted future prices. Id.
ICL stated that Idaho Power slightly improved the climate change assessment but Idaho
Power reviewed only two studies, made general observations about the timing and volume of snow
runoff and did not quantify the impacts in the load forecast or incorporate climate-related
generation variability into the modeling process. Id. at 3. ICL requested the Commission direct
Idaho Power to work with the scientific community and IRPAC on methods that account for
climate-related changes to customer demand patterns and generation profiles. Id.
ICL expressed concern that Idaho Power determined resource costs based on stale data
from the National Renewable Energy Laboratory’s 2018 Annual Technology Baseline report. Id.
at 4. ICL stated that other utilities in the region have gathered specific information from developers
ORDER NO. 34959 17

through Requests for Proposals in their IRP processes, which provides utility- and project-specific
information and is the best way to determine accurate pricing and performance characteristics. Id.
ICL stated that Idaho Power did not evaluate the impact of DERs on the load forecast or include
that impact in the generation resource options the AURORA LTCE could select. Id. ICL stated
Idaho Power took a “cursory look” at how DERs might defer some distribution level needs and
made “crude assumptions” by using average values rather than location-specific values. Id. ICL
recommended the Commission direct Idaho Power to incorporate DER concerns in the IRP process
and do a “distribution level analysis of needs, constraints, hosting capacity, and options.” Id.
ICL stated that Idaho Power analyzed energy storage technologies without considering
ancillary services and by merely looking at energy and capacity that storage technologies can
provide. Id. at 4-5. ICL recommended the Commission direct Idaho Power to work with the
IRPAC to adopt methods to quantify the services storage can provide. Id. at 5.
Idaho Power Reply: In response to ICL’s recommendation that Idaho Power issue a
request for information (“RFI”) about projects specific to Idaho and Idaho Power’s needs to
determine accurate pricing and performance characteristics to use as inputs in future IRPs, Idaho
Power stated that it uses pricing information from several well-established and publicly available
sources and adjusts the data to obtain location-specific data. Id. at 41. Idaho Power also stated
that RFIs typically are not used for long-term resource planning, require substantial time and effort
from bidding parties, and solicit near-term and time-limited information. Id. at 41-42.
Idaho Power responded to ICL’s comments that its natural gas forecasts should be
publicly available like the U.S. Energy Information Administration (“EIA”) forecast. Id. at 62-65.
Idaho Power stated it used the publicly available EIA High Oil and Gas Resource and Technology
forecast in its 2017 IRP, which was highly criticized. Id. at 63. Idaho Power stated it chose a
third-party forecaster, S&P Global Platts North American Natural Gas Analytics (“Platts”), based
on IRPAC feedback and looking at peer utilities. Id. Idaho Power reiterated that a Platts
representative presented Platts’ forecast and assumptions in a 2019 IRPAC meeting. Further, the
Platts forecast is more transparent than the EIA forecast because only the EIA forecast’s output,
and not the EIA forecast’s input or assumptions, is publicly available. Id. Idaho Power stated that
it verified the reasonableness of the Platt’s forecast by comparing it to EIA forecasts, Moody’s
Analytics and the NYMEX natural gas futures settlements. Id. at 64. Overall, Idaho Power stated
the Platts natural gas forecast is reasonable and should remain the source for future IRPs. Id. at
64-65.
ORDER NO. 34959 18

Idaho Power responded to critiques from ICL, Micron, and Sierra Club about the role
of DERs in the IRP process. Id. at 42-44. Idaho Power stated it adjusted its long-term sales
forecast downward to reflect the impact of estimated customer adoption of DERs. Id. at 43. Idaho
Power calculated customer billing histories for Schedules 6, 8, and 84 and multiplied them by the
estimated use-per-customer sales impact, which Idaho Power stated was derived from “historical
trends and policy considerations.” Id. At the end of the 20-year forecast, the annual residential
sales forecast was reduced by about 38 aMW, and the commercial reduction was less than 4 aMW.
Id. Idaho Power acknowledged that customer-generators accounted for one-half of one percent of
retail customers when the 2019 IRP was developed but that recent adoption of solar is “relatively
strong” in Idaho Power’s service territory, and the higher values will be reflected in the 2021 load
forecast. Id. Idaho Power agreed to include additional DER opportunities in the 2021 IRP and
present those ideas in the 2021 IRPAC meetings. Id.
Idaho Power responded to Sierra Club and ICL’s critiques about the assessment of
battery storage technology in the 2019 IRP and stated that it “views storage solutions as an
important part of Idaho Power’s future, both to integrate new and existing resources and to provide
ancillary services.” Id. at 45. Idaho Power noted that its preferred portfolio includes 80 MW of
battery storage, as selected economically by the AURORA LTCE, and that it included numerous
storage technologies and sizes as available for selection in the model. Id.
Idaho Power responded to ICL’s critique about assessing the impacts of climate change
on energy demands and generation sources. Id. at 65-68. Idaho Power stated that it “tracks the
latest climate projections, as well as studies that are being conducted to reflect relevant
temperature, precipitation, and streamflow changes in the Snake River Basin.” Id. at 65. Idaho
Power noted that its hydropower system is downstream from federally managed irrigation and
hydropower projects and changes to federal hydro operations will impact Idaho Power’s
hydropower system. Thus, Idaho Power relies on the River Management and Joint Operating
Committee, Second Edition, part 1 report (“RMJOC-II Part 1 Report”). Id. Idaho Power stated
the RMJOC-II Part 1 Report focuses on “potential changes to temperature, precipitation,
snowpack, and natural streamflow in the Columbia and Willamette River Basins under a variety
of future climate scenarios and with multiple methods for responding to hydrological changes.”
Id. at 65-66. Idaho Power stated it intends to continue using the RMJOC-II studies and findings
as they become available. By doing so, the Company “maintains a consistent framework for
understanding the risks and uncertainties associated with climate change impacts to hydropower
ORDER NO. 34959 19

throughout the Snake River Basin and allows Idaho Power’s projections to be informed by findings
for the upstream and downstream federal system.” Id. at 66. Idaho Power stated that it conducted
its own internal climate risk analysis for the 2019 IRP because upstream reservoir regulation was
not yet available. Id. Both its internal analysis and the RMJOC-II Part 1 Report “found that inflow
to Brownlee Reservoir is expected to increase in the winter to spring period and little-to-no change
is expected to occur in the summer to fall, through the 20-year IRP planning period.” Id.
e. Sierra Club Comments.
Sierra Club stated that the 2019 IRP “represents significant steps forward, both within
the [IRPAC] process and in the use of a substantially more capable analytical framework compared
to that used in the 2017 IRP.” Sierra Club Comments at 1. Sierra Club stated there was an increase
in transparency and stakeholder engagement in the 2019 IRP process. Id. Sierra Club noted that
the 2019 IRP predicts dramatic increases in Idaho Power market purchases, forecasting that Idaho
Power will acquire almost one-fourth of its total customer sales from other western entities by
2038. Id. at 5. Sierra Club stated the shift to net energy purchases largely coincides with the
planned retirement of Idaho Power’s coal and PURPA wind contracts (which Idaho Power assumes
will not renew). Id. Rather than adding generation in Idaho, the 2019 IRP backfills with market
purchases. Id. Sierra Club stated, “An expectation that [Idaho Power] will be able to rely on others
for such a high portion of the energy required for its customer load seems highly unrealistic and
should be carefully examined when reviewing portfolio alternatives in the 2021 IRP iteration.” Id.
at 6. Sierra Club stated, “[DERs] sited in Idaho could mitigate the risk of over-reliance on out-of-
state resources.” Id. at 7.
Sierra Club stated the 2019 IRP overestimates future peak load growth to the
disadvantage of Idaho-based resources. Id. at 6. Sierra Club noted that the 2019 IRP projects peak
loads to grow by 50 MW per year, while the average energy requirement is predicted to grow by
20 MW per year. Id. Sierra Club stated, “Idaho Power’s assumption of aggressive peak load
growth reduces the perceived value of low-cost energy sources such as Idaho solar and implies
unrealistic barriers to economically beneficial earlier retirement of coal units.” Id. at 6-7.
Idaho Power Reply: In response to Sierra Club’s statements about Idaho Power’s
ownership interest in the Jim Bridger coal units, Idaho Power clarified that it has no contractual
mechanism with PacifiCorp to pursue early exit and is working with PacifiCorp to determine the
costs and details of exiting Jim Bridger. Idaho Power Reply Comments at 40.
ORDER NO. 34959 20

Idaho Power responded to Sierra Club criticisms about its reliance on market purchases.
Id. at 47-48. Idaho Power stated that it modeled transmission constraints in the 2019 IRP and that
it is engaged with Northwest utilities to create the framework for a regional resource adequacy
program to provide coordinated planning on a regional basis. Id.
Idaho Power responded to Sierra Club claims that Idaho Power’s peak load forecast is
dramatically higher than historic records might indicate. Id. at 57-58. Idaho Power stated that,
when making a historic comparison to peak, it is important to adjust for demand response (“DR”)
and any major changes in customer base (e.g., exclusion of Astaris), and to recognize that not
every annual peak-hour event was driven by the same or similar weather conditions. Id. at 58. In
response to Sierra Club’s graph, Idaho Power stated, “adding a trendline through actual peaks—
where each historical year’s peak has its own probability of occurrence—has little meaning and
can lead to confusing results and misinterpretation.” Id. at 58. Idaho Power stated that for IRP
planning purposes, it uses 50th percentile conditions plus a 15 percent planning margin. Id.
“Comparing the trend of average peak load growth unadjusted for historical weather or
precipitation to a forecast reflecting 50th percentile conditions plus 15 percent would always
demonstrate that the trendline is less than forecasted peak.” Id. Idaho Power stated Sierra Club’s
historic figures only go back to 2000, and that its method is more accurate than Sierra Club’s. Id.
at 59. Idaho Power also states that its system has become “peakier” with peak growth outpacing
average energy consumption, particularly in summer months. Id.
Idaho Power stated it uses 12 regression equations, each for one month of the year,
generally estimated over 25 years of historical data. Id. at 67. “The peak-hour forecasting
regressions express system peak-hour demand as a function of monthly sales (stated in average
MW) and average peak-day temperatures, as well as real electricity prices and precipitation when
statistically significant.” Id. Idaho Power’s three special contract customers’ contribution to
system peak is separately determined and added to the overall system peak demand. Id. Idaho
Power stated that the forecast of average peak-day temperatures, which are calculated over the
most recent 30-year period, is a key driver of the monthly system peak models. Id. Idaho Power
models peak scenarios based on 50th, 90th, and 95th percentiles for each month of the year, with
June, July, and August re-specified to reflect an increasing temperature trend during those months.
Id. Idaho Power stated it will continue to work toward better reflecting climate change in its load
and generation forecasts. Id. at 67-68.
f. STOP B2H Comments.
ORDER NO. 34959 21

STOP B2H stated it is “extremely concerned with the accuracy and validity of the data
in Case No. IPC-E-19-19.” STOP B2H Comments at 4. STOP B2H disputed Idaho Power’s
assessment that its preferred portfolio enables a clean energy future. STOP B2H stated that 2005
is not a representative year to use as a baseline for carbon emissions because 2005 was an
extremely poor year for Idaho Power’s hydroelectric resources. Id. at 23-24. STOP B2H stated
that it “has examined the carbon intensity of Idaho Power’s individual resources and has concluded
that Idaho Power has quietly embarked on a high-carbon operating strategy for its gas-fired
resources and unfettered trading in the EIM appears to be the motive.” Id. at 24. STOP B2H
examined the carbon intensity of the Langley Gulch combined-cycle combustion turbine from
2013 to 2019 and concluded that Idaho Power operated Langley Gulch efficiently for the first five
years and averaged 820 lbs of CO2 per MWh from 2013 to 2017. Id. at 25. STOP B2H stated
that after Idaho Power joined the EIM in 2018, “Idaho Power profoundly changed the operating
regime of Langley Gulch resulting in gross inefficiencies in operation.” Id. STOP B2H stated that
the carbon intensity of Langley Gulch jumped by almost 20 percent to 969 lbs. of CO2 per MWh.
Id. STOP B2H stated,
This curious operation of Langley Gulch by Idaho Power in 2018-
2019 resulted in almost 200,000 tons of unnecessary CO2 emissions
and over $10 million of unnecessary fuel costs, at actual 2018-2019
gas prices, to the detriment of ratepayers . . . . Under the EIM, the
‘benefits’ of the EIM accrue to stockholders while this $10 million
of excess fuel costs is paid by ratepayers.
Id. STOP B2H stated it “does not know the drivers behind this wasteful and expensive operation
of Langley Gulch but maintaining the plant in wasteful hot standby to bid into the EIM, frequent
operation at partial load, and operating power augmentation (duct firing) to achieve quick and dirty
ramping capacity for EIM participation are likely contributors.” Id., FN 43.
STOP B2H stated that Idaho Power’s stochastic analysis in the Second Amended 2019
IRP was improperly structured to bias the analysis against portfolios optimized under a high-
carbon cost future. Id. at 27. STOP B2H alleged Idaho Power did this “by hard-wiring different
carbon price inputs into AURORA depending on which Portfolio was being studied.” Id. STOP
B2H stated, “This hidden bias against every Portfolio optimized for a high carbon cost future in
the stochastic analysis ensures that Idaho Power will always prefer a Portfolio with little or no
renewables.” Id.
ORDER NO. 34959 22

STOP B2H urged Idaho Power to evaluate whether adding new resources within Idaho
Power’s service territory would enable Idaho Power to reduce or eliminate the 330 MW Capacity
Benefit Margin on Path 14, which it stated would open 330 MW of new long-term firm capacity
on Path 14. Id. at 36. STOP B2H relied on Staff’s analysis in IPC-E-19-14, which demonstrated
that the Jackpot Solar PPA would be more cost effective than buying from Mid-C. Id. at 32-34.
STOP B2H disputed Idaho Power’s load and sales forecast. Id. at 37-45. STOP B2H
stated, “The increase in Idaho’s residential population has been perfectly matched by a decrease
in average residential use.” Id. at 37. STOP B2H claimed that Idaho Power consistently
overestimates its load forecasts in its IRPs. Id. at 38-39. STOP B2H asked if Kalman filtering,
spectral decomposition, or time-series analysis had been applied to Idaho Power’s long-term
projections, and if not, why not. Id. at 39. STOP B2H stated that the “hyper-complex mixed
regression analyses employed for the utility’s simulations of sales and load forecasts, dependent
as they are on an impossibly large collection of open-ended parameters, is at the root of the
problem[.]” Id. at 40.
STOP B2H stated that Idaho Power’s DR savings have declined since 2010-2012 and
remained relatively static since 2015, and are expected to achieve the same savings in 2036 as
were achieved in 2012. Id. at 47. STOP B2H stated that Idaho Power chronically underestimates
its EE targets, which makes the resource stack forecast untrustworthy. Id. at 48. STOP B2H
stated, “The Commission should not acknowledge the Second Amended 2019 IRP as it stands and,
at a minimum, should pause continued permitting and construction of the B2H until partners are
signed and a solid budget developed.” Id. at 52.
Idaho Power Reply: Idaho Power responded to STOP B2H’s argument that B2H
would increase Idaho Power’s near-term carbon emissions by focusing on B2H as a long-term
resource that will allow Idaho Power to integrate more renewables across widespread geographic
areas. Id. at 13-14. Idaho Power stated that stochastic risk analysis is unnecessary for carbon price
futures, contrary to what STOP B2H argued, because the range of carbon prices are neither
unpredictable nor uncertain. Id. at 38. Idaho Power stated that two of the three portfolio groupings
selected for manual optimization were developed under a high-carbon price scenario to ensure a
range of possible policy futures. Id. at 39.
Idaho Power responded to STOP B2H critiques about demand-side resources and stated
that it has a mature EE and DR portfolio and has steadily increased its DSM offerings. Id. at 48.
Idaho Power stated that in 2019, it achieved its highest EE savings since the Idaho Energy
ORDER NO. 34959 23

Efficiency Rider was established in 2002, and that it has achieved a 25 percent increase in energy
savings since 2015. Id. at 48-49. Idaho Power contrasted its EE growth to regional EE savings,
which it stated have plateaued or declined since 2010. Id. at 49-50. Idaho Power stated that the
AURORA LTCE model could select additional EE bundles above the amounts identified as
economic and achievable in the third-party Potential Study conducted by Applied Energy Group
for Idaho Power, but the model selected none of the higher-cost EE bundles. Id. at 50-51.
Idaho Power responded to STOP B2H comments about Idaho Power’s DR efforts. Id.
at 52-54. Idaho Power acknowledged that its DR capacity has decreased since 2012 but stated that
its DR programs were designed “specifically to avoid or delay the need to build new supply-side
peaking resources within very limited peak hours and days.” Id. at 52. Since 2012, Idaho Power
stated that its analyses have forecasted no capacity deficit in peak hours, and therefore Idaho Power
petitioned and the Commission approved temporary suspension of two out of three DR programs
to avoid spending money on an unneeded resource. Id. at 52-53. Idaho Power stated that despite
the decrease in DR, its 2019 DR capacity as a percent of system peak is significantly higher than
most utilities. Id. at 53-54. Idaho Power stated that its IRP analysis showed that additional DR
capacity will not be the lowest-cost resource until 2030. Id. at 54.
Idaho Power separately responded to STOP B2H claims about its modeling. Id. at 60-
62. Idaho Power stated it has incorporated considerations and feedback into its modeling processes
and its “present forecast methodology provides a long-term planning framework that aligns
retrospective comparisons to weather-adjusted growth, while accounting for the specific factors
that impact Idaho Power’s future load.” Id. at 61. Idaho Power stated that it continues to believe
that its inferred econometric models are “the best available means for long-term load growth
forecasting, with their ability to factor in both a rich history of data and to account for a range of
factors impacting load growth. These models are the industry standard for long-term load
forecasting in the IRP context.” Id. Idaho Power stated that clear data refutes STOP B2H’s claim
that decreased average residential use has counteracted an increase in residential population and
noted that its weather-adjusted residential sales recently have grown about 1 to 2 percent per year,
and its agricultural base continues to grow. Id. at 61-62.
Idaho Power responded to STOP B2H claims about its carbon emissions. Id. at 72-79.
Idaho Power stated that the choice of 2005 as a baseline year is consistent with multiple greenhouse
gas (“GHG”) reduction frameworks and legislation including the proposed Waxman-Markey Bill.
Id. at 72. Idaho Power stated that 2005 was selected as a baseline year “because that year was a
ORDER NO. 34959 24

generational peak for national GHG emissions.” Id. at 73. Idaho Power acknowledged that its
GHG profile consistently fluctuates based on stream flows and therefore it has consistently stated
that an average intensity over several years is an appropriate metric. Id. Idaho Power noted that
its voluntary GHG reduction goals have been extended and increased twice since 2009, including
its March 2019 public proclamation that it will provide customers with 100 percent clean energy
by 2045. Id.
Idaho Power responded to STOP B2H’s claim that it operates Langley Gulch to
maximize EIM participation to the benefit of shareholders and the detriment of ratepayers. Id. at
74-79. Idaho Power stated that it discovered discrepancies between FERC Form 1 data submitted
to FERC, and upon which STOP B2H based its analysis, and the actual data collected through
Idaho Power’s continuous emissions monitoring system and gas billing records. Id. at 74-75.
Idaho Power stated, “The values for Langley Gulch in 2018 and 2019 were inadvertently
overstated because of manual-entry error for the two months of August 2018 and July 2019 in the
FERC Form 1.” Id. at 75. Idaho Power filed corrected FERC Form 1 data in January 2021. Id. at
75. Despite the error, Idaho Power stated that neither data set supports STOP B2H’s claim that
Idaho Power has embarked on a “high-carbon operating strategy.” Id. Idaho Power stated that
Langley Gulch’s 2018 and 2019 emissions are “more, or less in line” with the 2013 to 2017 data
with variation driven by factors such as customer demand and weather. Id. Instead of focusing
solely on Langley Gulch, Idaho Power stated that from 2013 to 2018, “generation from thermal
resources has declined and total CO2 emissions from those resources decreased by almost 50
percent[.]” Id. at 76. Idaho Power stated that both the costs and benefits of EIM participation flow
back to customers and are realized as reduced net power supply expenses. Id. at 77. Idaho Power
described the EIM dispatch procedures. Id. at 78.
g. Micron Technology Comments.
Micron noted that it is Idaho Power’s largest customer and depends on Idaho Power’s
reliable service at reasonable rates to remain competitive in the global marketplace. Micron
Comments at 1. Micron stated that it supports Idaho Power’s transition to clean energy, which it
described as the hallmark of the 2019 IRP. Id. Micron stated that it has established sustainability
goals, “including aggressive efforts to reduce its emissions and power its operations with
renewable energy.” Id. at 2. Micron described these sustainability goals as “a 40 percent absolute
reduction in greenhouse gases from its 2018 levels and implementing 100 percent renewable
energy where available.” Id. Micron stated that it is “currently evaluating several renewable
ORDER NO. 34959 25

energy strategies to meet its internal goals and is interested in potential cost-competitive
partnerships that could be formed with [Idaho Power].” Id. Micron stated that Idaho Power’s
diligent efforts resulted in a preferred portfolio that “is marked by reasonable exits from coal-fired
generating facilities, the addition of renewable resources, and access to regional electricity markets
allowing for increased reliability and cost-effective electricity purchases.” Id. Micron stated that
it is specifically interested in Idaho Power’s plans to add significant solar and battery facilities. Id.
at 3. Micron stated it is evaluating possibilities including virtual power purchase agreements and
on-site renewable generation at its Boise campus, and it is interested in working with Idaho Power
and the Commission to develop cost-effective strategies to increase its use of renewable energy
and invest in local renewable energy projects. Id.
PUBLIC COMMENTS
The Commission received hundreds of written comments on Idaho Power’s 2019 IRP.
The public comments predominately expressed support for Idaho Power’s transition away from
coal-fired generation resources toward greater integration of renewable resources and encouraged
Idaho Power to pursue a more aggressive timeline for this transition.
DISCUSSION AND FINDINGS
Idaho Power is an electrical corporation and public utility as defined in Idaho Code §§
61-119 and -129, and the Commission has jurisdiction over it and the issues in this case under Title
61 of the Idaho Code, including Idaho Code § 61-501. Having reviewed the record, we find that
Idaho Power’s Second Amended 2019 Electric IRP satisfies the requirements in the Commission’s
prior orders. We thus acknowledge that Idaho Power has filed the Second Amended 2019 Electric
IRP. In doing so, we reiterate that an IRP is a working document that incorporates many
assumptions and projections at a specific point in time. It is a plan, not a blueprint, and by issuing
this Order we merely acknowledge Idaho Power’s ongoing planning process, not the conclusions
or results reached through that process. With this Order, the Commission does not approve the
IRP or any resource acquisitions referenced in it, endorse any particular element in it, opine on
Idaho Power’s prudence in selecting the IRP’s preferred resource portfolio, or allow or approve
any form of cost recovery. The appropriate place to determine the prudency of the IRP or Idaho
Power’s decision to follow or not follow it, and the validation of predicted performance under the
IRP, is a general rate case or other proceeding where the issue is noticed.
ORDER NO. 34959 26

As evidenced by the extensive procedural record, the 2019 IRP process entailed
significant learning about the intricacies of LTCE modeling. We appreciate Idaho Power’s
substantial efforts to ensure that the model reflects its understanding of its own system. We also
appreciate the continued engagement of parties and other members of IRPAC. We look forward
to seeing the co-optimized modeling in the 2021 IRP. Idaho Power responded to numerous party
comments by indicating it will continue to work with IRPAC to address the concerns raised by the
parties. We believe that approach is a good practice and that IRPAC is the proper forum to work
through the technical issues and disputes. Idaho Power’s presumption that PURPA contracts will
renew, and the associated impact on Idaho Power’s L&RB, should be examined in both Idaho
Power’s forthcoming capacity deficit filing and in IRPAC meetings. And B2H partnership status
and demonstrating market availability at Mid-C should continue to be areas of focus.
The IRP planning process attempts to ensure that Idaho Power is well-positioned to
meet the demands of a changing energy sector. While there are inherent limitations in trying to
predict a multitude of conditions over the next 20 years, the planning process is worthwhile when
Idaho Power strenuously evaluates model inputs, verifies the model logic, and collaborates with
engaged stakeholders. Doing so helps ensure that Idaho Power can continue to provide reliable
and economical service to its customers as the energy sector evolves.
In its reply comments, Idaho Power requested Commission authorization to delay filing
its 2021 IRP. We find that interested persons and parties should have the opportunity to comment
on the request and therefore direct Idaho Power to file a petition requesting an extension to its
2021 filing deadline.
O R D E R
IT IS HEREBY ORDERED that the filing of Idaho Power’s Second Amended 2019
IRP is acknowledged.
THIS IS A FINAL ORDER. Any person interested in this Order may petition for
reconsideration within twenty-one (21) days of the service date of this Order. Within seven (7)
days after any person has petitioned for reconsideration, any other person may cross-petition for
reconsideration. See Idaho Code § 61-626.

ORDER NO. 34959 27

DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 16th day
of March 2021.

PAUL KJELLANDER, PRESIDENT

KRISTINE RAPER, COMMISSIONER

ERIC ANDERSON, COMMISSIONER

ATTEST:

Jan Noriyuki,
Commission Secretary

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