20210120Comments.pdf

EDWARD JEWELL
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE,IDAHO 83120-W14
[phone]
IDAHO BAR NO. 10446
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Street Address for Express Mail:
II33I W. CHINDEN BLVD, BLDG 8 SUITE 2OI-A
BOISE, IDAHO 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S 2019 INTEGRATED RESOURCE
PLAN
CASE NO. IPC.E.19.19
COMMENTS OF THE
COMMISSION STAFF
BACKGROUND
On June 28,2Ol9,Idaho Power Company ("Idaho Power" or "Company") filed its 2019
Integrated Resource Plan ("Original2019IRP") with the Commission.
On July 19,2019, the Company filed a letter with the Commission "providing notice that
the Company had identified the need to perform supplemental analysis to confirm the accuracy
of its 2019 IRP's conclusions and findings." Subsequently, the Commission issued Order No.
34410 suspending review of the filing pending filing of the Company's supplemental analysis.
On October 8,2019, the Company filed a letter stating that it would need until November
8,2019, before it could provide a new estimated filing date.
On November 8,2019, the Company filed a letter stating that it would file its
supplemental IRP analysis no later than January 31,2020.
On January 31,2020, the Company filed an Amendedz}lg IRP ("First Amended 2019
RP"). The Company identified eight changes to its modeling inputs. These changes were
primarily related to inclusion of Jackpot solar as a resource, the costs of natural gas supply
expansion, a return to the previous after-tax discount rate for net present value calculations, and
STAFF COMMENTS 1 JANUARY 20,2O2I
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inclusion of third-party transmission revenues associated with the Boardman to Hemingway
transmission line.
On March 4,2020, the Commission issued Order No. 34572, Notice of Amended
Integrated Resource Plan and Notice of Intervention deadline.
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 I,2020, the Company submitted replacement pages to its IRP updating costs
associated with the Jim Bridger power plant.
On July 1,2020, the Company filed "Idaho Power Company's Motion to Suspend
Procedural Schedule and Update Regarding Boardman to Hemingway Transmission Line
Project." In its motion, the Company stated that the Company "...has experienced complications
in its efforts to implement a new modeling approach in this proceeding."
On July 16,2020, the Commission issued Order No. 34723, Notice of Vacated Comment
Deadlines.
On October 2,2020, the Company filed its Second Amended 2019 IRP with the
Commission. In its amended Application, the Company stated that its Second Amended 2019
IRP results in only one change to the Company's near-term action plan: The exit year for the
Valmy Unit2 coal-fired power plant. According to the Company, analysis conducted as part of
the Second Amended 2019 IRP found the potential for additional savings from an exit as early as
year-end 2022.
Along with the Second Amended 2019 IRP, the Company also filed a report titled, 2019
IRP Review Report: Process and Findings ("Review Report"), which outlines the Company's
findings and corrective actions regarding problems identified in its Original}Olg IRP Report and
First Amen ded 2Ol9 IRP Report.
On November 16, 2020, the Commission issued Order No. 34834, Notice of Revised
Comment Deadlines, establishing a comment deadline of January 20,2021, and a reply comment
deadline of February 10,2021.
The IRP is the Company's status report explaining how the Company plans to adequately
and reliably serve customers over the next 20 years. The Commission requires the Company to
file an IRP every two years, and to allow the public to participate and comment as the IRP is
2STAITF COMMENTS JANUARY 20,2O2I
being developed. Order No.22299. With this filing, the Company asks the Commission to
acknowledge that the Company has filed its Second Amended 2019IRP.
STAFF ANALYSIS
Summary
Staff recommends that the Commission acknowledge the Company's Second Amended
IRP; however, Staff cautions that the Commission should not rely on the Company's preferred
portfolio bbcause it may not be the optimal portfolio for the Company's ratepayers. The most
the Company can claim is that the preferred portfolio is least cost and least risk among a limited
set of competing portfolios. To summarize Staffs concerns, Staff is neither convinced that
AURORA's Long Term Capacity Expansion ("LTCE") tool was configured in a manner that
produces portfolios that provide the Company's ratepayers reliable power at low cost, nor is it
convinced that the LTCE is the appropriate tool for the Company's capacity expansion efforts.
Of particular concern to Staff is the Company's analysis of the proposed Boardman to
Hemingway transmission ("B2H") line. In addition to concerns about the way that B2H was
treated in the Company's LTCE selection process, Staff is concerned that the Company has not
demonstrated that there will be sufficient market capacity available through BZHto meet the
needs of Idaho Power customers.
The Company is contemplating the purchase of the Bonneville Power Authority's
("BPA") interest in the B2H transmission line. Staff believes the costs and tax implications
should be addressed in the Company's next IRP.
Staff believes that the improved peak load prediction method used to formulate the 2OI9
Load and Resource Balance will result in a more accurate forecast; however, Staff notes that the
Company did not actually include a fully developed Load and Resource Balance ("L&RB") in
this year's IRP. In future IRPs, Staff believes the Company should include its L&RB and more
detailed information about the assumptions and considerations used to formulate the L&RB such
as the Company's Public Utility Regulatory Policies Act of 1978 ("PURPA") renewal
assumptions, Open Access Transmission Tariff ("OATT") sales information, and market
availability and transmission capacity analysis.
In its comments, Staff will discuss the ramifications of not meeting the Company's
Regulating Reserve Requirements. In future IRPs, Staff believes the Company should explore
JSTAFF COMMENTS JANUARY 2O,2O2T
the impact of failing to meet optional regulation reserve requirements on cost and reliability and
explore the degree to which optional regulation reserve requirements might be relaxed.
Finally, Staff will discuss the Company's use of the after-tax marginal Weighted Average
Cost of Capital ("WACC") in its analysis, which is consistent with prior practice.
Portfolio selection process
Given its importance to the 2019IRP portfolio selection process, Staff is concerned by
the company's use of the LTCE. staff is particularly concerned that:
a. The Company has configured the LTCE to select portfolios based on
the benefits they provide to the Western Electricity Coordinating Council ("WECC"),
and not based on the benefits to Idaho power's ratepayers.
b. The Company's process for selecting, manually adjusting, and combining
portfolios is subjective, and not likely to produce the lowest cost portfolios for Idaho
Power's ratepayers.
c. The Company's process for selecting AURORA as its Capacity Expansion tool
was poorly defined. AURORA's Long Term Capacity Expansion software may not
be the appropriate tool for the Company's IRp planning process.
d. The Company's process for software validation is insufficient; however, Staff is
encouraged by improvements that the Company made to the process used to
verify inputs to the LTCE.
The Company's manually adjustedWECC optimized porfolios
In2019, the Company began using AURORA's LTCE software to generate and select the
portfolios that are the basis for its IRP planning process. Prior to z}Ig,portfolios were generated
manually, either by Company planners, or in conjunction with the Company's Integrated
Resource Plan Advisory Committee ("IRPAC"). The portfolios were then compared to each
other using the net present value of resource additions and retirements, and dispatch costs that
each portfolio would incur over the 2O-year IRP planning period. This process was manually
intensive, and because only a very small number of portfolios were considered, it did not
guarantee that any of the resulting portfolios provided Idaho Power's customers reliable power at
the lowest cost.
STAIIF COMMENTS JANUARY 2O,2O2I4
So long as it is configured correctly, the LTCE can generate and evaluate many more
portfolios than could be evaluated using the Company's previous manual process; however, Staff
is concerned that the Company has not configured the LTCE to select portfolios based on their
ability to provide the greatest value to the Company's ratepayers, and instead used objective
functions designed to maximize value for the entire WECC. Company Response to Staffs
Production Request No. 8. An objective function is a mathematical expression describing what
is being optimized, as well as any constraints placed on the model. For example, in Idaho
Power's older manual process, the objective function was to minimize the net present value of
costs to Idaho Power's ratepayers subject to the constraints that the system be reliable and
maintain required reserye margins. By contrast, the Company has configured the LTCE to use
an objective function that maximizes value for the entire WECC.
The needs of the WECC are not necessarily aligned with the needs of Idaho power, and
in its response to Staffs Production Request No. 89, the Company acknowledged that
".'.optimizing for the WECC does not necessarily result in least-cost portfolios for Idaho power's
customers." The Company also acknowledged that inconsistent and counterintuitive results
obtained using its WECC-optimized portfolios to analyzethe Jackpot Solar PPA resulted in the
Company's request to suspend processing of the Original 2019 IRP so that it could revise its
analysis. First Amended20lg IRP at 1, 2.
While the Company's willingness to withdraw and revisit its original analysis is laudable,
Staff believes that the analysis provided in the Company's First Amended2}lg IRp to have been
only a marginal improvement over its Original 2019 IRP. The Company's revised portfolio
selection process utilized manual adjustments to selected WECC-optimized portfolios generated
by the LTCE. These adjustments were relatively small and centered around timing of the
Company's exit from units at the Jim Bridger power plants. Company Response to Staffs
Production Request No. 11. Although somewhat more cost effective for Idaho power's
customers, the Company did not adequately explain the criteria for selecting these particular
portfolios for manual adjustment, why it focused on timing of the Company's exit from Bridger,
and why manually adjusting WECC-optimized portfolios might be expected to produce the best
results for Idaho Power's ratepayers. Company Responses to Staff Production Request Nos. 10,
II,12, and 13.
STAFF COMMENTS JANUARY 2O,2O2I5
Shortly after filing its First Amended 2019 IRP, the Company filed another request with
the Commission to suspend processing it. Staff again commends the Company for its
willingness to withdraw a flawed analysis, but once again does not believe that the analysis
presented in the Company's Second Amended 2019 IRP to be a substantive improvement over
either of its two previous attempts. As was the case in its Original}Ol9IRP and its First
Amended 2019 IRP, the starting points for the portfolio analysis in the Company's Second
Amended 2019 IRP were its WECC-optimized portfolios. As it had done in its First Amended
2019IRP, the Company manually adjusted selected WECC-optimized portfolios;this time, by
combining portfolios that the Company determined to be similar. The resulting preferred
portfolio, which the Company calls PGPC B2H (L), was obtained by combining WECC-
optimized portfolios 13 and 14. In its responses to Staffs Production Request Nos. 69, 90, and
94,the Company did not adequately explain the process for combining these two portfolios.
Importantly, the Company did not explain why we might expect any combination of WECC-
optimized portfolios to assure that Idaho Power's customers obtain reliable power at least cost.
To assure that portfolios are optimized for Idaho Power's ratepayers, Staff believes that
the Company should start with an objective function that optimizes portfolios for Idaho Power's
system. Staff reminds the Company that to be deemed prudent, the Company must be able to
demonstrate that proposed investments are in the best interests of Idaho Power's ratepayers, and
not the WECC.
Software selection and model verification and validation
Given the importance of computer modeling to the Company's 2019 IRP, Staff believes
the Company should have done a more thorough job selecting its capacity expansion software,
validating the software and resulting model's ability to provide reliable results, and verifying that
the inputs to the software accurately reflect the Company's assumptions and operations.
For example, given the purpose of the IRP, it would seem obvious that any capacity
expansion software used in the IRP process should be able to generate portfolios that are
optimized for Idaho Power's system, yet the Company chose to use AURORA's LTCE, which is
incapable of doing so. In its 2019 IRP Review Report, the Company stated:
STAFF COMMENTS JANUARY 20,2O2L6
Subsequent to the initialfiling, Idaho Power discovered that the LTCE model optimized
portfolios for the entire Western Electricity Coordinating Council (WECC) ,rgion, but not
necessarilyfor Idaho Power's system in particular. For this reason, on July 19,2019, the
company notdied the Commissions of the need to perform supplemental analysis to ensure
that the IRP yielded a least-cost, least-risk solution specific to IPC's service area, and asked
that the Commissions refrainfrom adopting a procedural schedule until an amended IRp
could be filed. 2019 IRP Review Report, Process and Findings at l.
Staff appreciates that the Company recognized and acknowledged problems with its
LTCE software. However, Staff does not believe that optimizingfor the WECC and then
manually adjusting the resulting portfolios to be either a robust or transparent solution to
capacity expansion modeling issues, as witnessed in its three iterations of the 2019 IRp. Staff is
concerned that lack of well-defined business and modeling requirements for capacity expansion
tools will result in subsequent IRPs having problems like those encountered in the 2019IRp.
Staff believes the Company would benefit from using a disciplined, industry standard approach
in defining what is required of a capacity expansion modering tool.
In its response to Staffs Production Request No. 89, the Company stated that it was
evaluating the capabilities of the newest AURORA release, which would be capable of
simultaneously modeling the WECC and Idaho Power, with the concurrent goal of meeting the
planning margin for all entities within the WECC. In its response to Staffs Production Request
No. 100, the Company stated that this release would not guarantee that the portfolios obtained
from it would be the same as those obtained by optimizing for Idaho Power alone. Staff is
concerned that the newest AURORA release may not produce portfolios that are in the best
interests of Idaho Power's ratepayers.
Staff also believes the Company's process for validating capacity expansion software is
inadequate. Software validation is the formal process of assuring that software is capable of
meeting the requirements identified during the model selection process. Software validation
should be completed prior to purchasing a new software package and accepting it for operational
use. Instead, the validation process described by the Company in its Review Report focused on
evaluating the internal consistency and output of the Company's WECC-optimized models after
they had already been generated. Review Report at49.
Staff does not intend to disparage the Company's validation efforts, and notes that its
post-hoc validation process caught a number of important modeling discrepancies, including
AURORA's incorrect truncation of fixed costs associated with the Bridger shutdown. Second
STAFF COMMENTS JANUARY 20,2O2I7
Amended 2019 IRP at 3 and 4. Nevertheless, the Company's post-hoc validation process is quite
different from a formal software validation process that characterizes software reliability and
determines the range of circumstances over which results are reliable and can be trusted. A
formal validation process most likely would have revealed that the LTCE was only capable of
WECC optimization, and incapable of optimizing for Idaho Power's service territory. Amended
IRP at 1, 2.
On the other hand, Staff is encouraged by the processes used by the Company to verify
that the values used in the LTCE are consistent with the IRP's assumptions and the Company's
operations. These processes are described by the Company in its Review Report and were used
in conjunction with the development of its Second Amended 2019IRp. Verification was
conducted by teams of subject matter experts from across the Company. As a result, the
Company found numerous effors in the values used to create the Company's Original and First
Amended 2019 IRPs. Second Amended 2019IRP at2-6. Staff lauds this approach to model
verification and encourages the Company to continue it in future IRp cycles.
Boardman to Hemingway
Staff is concerned with the assumptions made by the Company in its analysis of B2H.
Specifically, Staff is concerned that:
a. The analysis was conducted using WECC-optimizedportfolios, and B2H
was evaluated based on its value to WECC, rather than its value to Idaho
Power's ratepayers.
b. The analysis makes overly optimistic assumptions about the availability of
power in the Pacific Northwest for import into Idaho Power's system.
c. The analysis was conducted without regard to an increased share of
ownership in B2H currently being contemplated by the company.
The LTCE is incapable of considering transmission resources such as B2H for inclusion
in the portfolios it generates. Instead, the Company conducts two different groups of LTCE
model runs: One group is modeled assuming that B2H does not exist, and the other group is
modeled by including a hypothetical B2H into the transmission system assumed by the model.
Second Amended 2019 IRP at IO7. The net present values generated using the resulting WECC-
STAFF COMMENTS JANUARY 2O,2O2I8
optimized models can then be compared directly or, as the Company did in its Second Amended
2019 IRP, combined to create its preferred portfolio. Response to Staffs Production Request
No.66.
The fundamental problem with this approach is that because these are all WECC-
optimized portfolios, they represent the costs incurred by Idaho Power ratepayers to provide
benefits to the WECC, and not necessarily to Idaho Power ratepayers.
Staff is also concerned that the Company's assumptions about power availability in the
Pacific Northwest may be unrealistic and assume that much more dispatchable power will be
available for import into Idaho Power's system than seems likely under the current regulatory
climate. Significantly, the effects of Washington's Clean Energy Transformation Act ("CETA")
was not included in the Company's assumptions about the amount of power that would be
available for export from Boardman to the Idaho Power system. Response to Staffs Production
Request No. 66. Additionally, neither the Pacific Northwest Power Supply Adequacy
Assessment nor the 2018 BPA Pacific Northwest Loads and Resources Study that the Company
relied upon for its resource adequacy assessment took CETA into account. Second Amended
2019IRP, Appendix D, pages 55 and 56.
B2H Risks
Staff identified three areas of risk associated with the inadequateB2H investment
evaluation in the 2019 IRP: (1) forecasting future market prices for capacity, (2) regional
resource adequacy, and (3) shifting regional policies around renewable, coal, and thermal energy
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. If a capacity
resource does become available, many utilities in the Pacific Northwest region will be competing
for it, which could drive prices significantly above high market forecasts and potentially
eliminate the ability to acquire it. Further, when the Company first planned for B2H in 2006, it
was conceivable that capacity resources would be built in the region that could supply the B2H
transmission line. Since then, customer interest in clean energy solutions has increased and
utilities across the region have adopted clean energy goals and policy. Technology and
innovation have dramatically changed the energy sector to reduce costs for renewable energy
development, and regional policies penalize coal and thermal resources making them potentially
9STAFF COMMENTS JANUARY 2O,2O2I
risky and uneconomical investments. These factors have utilities transitioning away from coal
plants and they discourage the development of gas plants that could supply the B2H transmission
line. Staff recommends that in the next IRP, the Company provide detailed analysis and
explanation for how the forecasted capacity, if any, will be available for B2H to import and
provide more specifics about where it will come from.
B2H Partners
Currently Idaho Power has Project Joint Permit Funding Agreements with Rocky
Mountain Power ("RMP"), which is listed as a 55Vo partner, and BPA, which is listed as a24Vo
partner. IRP Appendix D at28. The202O BPA Transmission Plan, published December 22,
2020, describes BPA's ten-year system expansion and reinforcement plans for their transmission
system, but it did not include the B2H transmission line project and BPA has not yet made a
decision about joint ownership.l B2H is also not included in the RMp 2019 IRp preferred
portfolio or the planned transmission projects included in the 2019 IRP, and has very little
presence or analysis in IRP materials that would reveal the status of long-term commitment to
the near-term construction of B2H. RMP refers to B2H as a resource that in2ol2,"was pursued
as an alternative to PacifiCorp's originally proposed transmission segment from Eastern Idaho
into Southem Oregon." PacifiCorp 2019IRP at 83. Staff is concerned that the funding
partnership, beyond permitting, for B2H has not been solidified at this late stage in the planning
process.
On November 5,20l9,Idaho Power filed Form 8-K with the Security and Exchange
Commission with a "hypothetical45Vo ownership" disclosure.2 During the 2Ol9IRp, the
Company omitted discussion of the need for an addition al24vo ownership of B2H and did not
provide any analysis for this hypothetical scenario. It does coincide with BPA's share of B2H.
After a permitting and planning process that lasted nine years, BPA cancelled its own plans to
invest in the Oregon/Washington I-5 Corridor transmission line in2017 and shifted from a policy
of relying on new transmission construction to meet changing transmission needs to embrace a
| 2O2O Bonneville Power Administration Transmission plan at:Microsoli Word - 2020 BPA TransmissionPlan FINAL and
2 IDACORP INC Form 8-K, United States Securiries and Exchange Commission, November S, 2019. potential
Long-Term Rate Base Growth at 11. Boardman to Hemingway 500kV Transmission Line project at Appendix A-lg
STAFF COMMENTS l0 JANUARY 20,2O2I
more flexible, scalable, and economically and operationally efficient approach to managing their
transmission system. BPA is moving forward with policy that seeks to improve efficiencies with
the partners and infrastructure it has in place in order to "build at the smallest scale possible to
meet customer needs.3 As a significant amount of time has passed since B2H partners
committed to Joint Permit Funding, and where at least one partner has made significant policy
changes regarding transmission investment, Staff recommends that the Company provide a
detailed analysis for a hypothetical 45Vo and. l00%o ownership share of the B2H transmission line
to present during the next IRP, should ownership status remain unresolved.
In March of 2020, the Company informed Staff that they continue to have discussions
with BPA over possible ownership changes, that these discussions have not matured, but could
present a change in overall ownership. Idaho Power Response to Staff's Production Request No.
18. The Company anticipates that significant ownership change may occur and they are already
performing hypothetical ownership change analysis. Staff recommends the Company keep the
Commission informed of any change between B2H transmission line partners, and allow ample
opportunity to evaluate potential B2H ownership changes during the next IRp.
In the event that the Company assumes BPA's ownership share of B2H, there could be
important tax implications. Under the current arrangement, the Company will assume a2l7o
interest in B2H. The Company is considering a 45Vo ownership share and the tax and cost
implications to ratepayers have not been vetted. Taxes on the Company's assumed share of BpA
assets could increase cost to rate payers. The Company should address this in their next IRp.
The Company also believes B2H is still a viable investment even if they absorb BpA's
24Vo shate of ownership. Idaho Power Response to Staff s Production Request No. 35.
Estimated costs for the B2H project were calculated in 201g to be $l to 1.2 billion dollars, with
the Company's investment share being $292 million. Amende d2OIg IRp Appendix D at 40.
The Company predicts an August2O2g capacity deficiency of 5 MW. Idaho power Response to
Staff s Production Request No. 92. Staff looks forward to seeing updated estimates, further
analysis, and more complete evidence that the B2H transmission line is the least cost future
resource benefitting Idaho customers.
3 Department of Energy, BPA Executive letter from Elliot Mainzer to parties interested in the I-5 CorridorReinforcement Project dated May 17, 2OI7 avnilable ar https://www.boa.gov/projects/proiects/I-</n,-,.,af+or T ( .l^^i ct \/ic;fa; I^-"-*.,
STAFF COMMENTS
final .,,-1. -.tF
11
t?202 t\
JANUARY 2O,2O2L
Load and Resource Balance
Staff believes that the assumptions used by the Company to formulate its L&RB are
mostly reasonable. In particular, Staff appreciates the improvements made to the Company's
peak load forecast in response to Staffs 2017 IRP comments. However, based on its analysis of
the peak load L&RB, Staff proposes several modifications to the resources included for purposes
of determining the first capacity deficiency date in PURPA contracts, including changes in
existing resources for contract renewals, market purchases, non-owned reserves, and energy
efficiency.
In addition, the Company included tables summarizing its L&RB in the body of the IRP
in past IRPs but did not include them in the Second Amended 2019 IRP. Staff relies on this
information to perform its analysis, which required Staff to request the information through Staff
Production Request No. 92. Staff recommends that the Company include the L&RB table in
future IRPs so that Staff and other stakeholders can readily access the information.
Loadforecast
The Company's L&RB compares the capabilities of existing Company resources with
monthly forecast average load, system sales, and peak load over the 2}-year IRP planning
period. The Company's method for forecasting average load is substantially the same as that
presented in its 2017 IRP; however, the Company made modest improvements to its peak load
forecasting methodology. These improvements result in a more accurate forecast; however, Staff
believes that even more improvements can be made to the Company's peak forecasting
methodology.
In its 2017 IRP comments, Staff noted that decisions to build or buy generation and
transmission plant are primarily driven by the Company's peak load forecast, not its monthly
forecast average load. Despite the relative importance of the peak load forecast, the Company's
peak load forecasting methodology was still less sophisticated than its method for forecasting
average monthly load and system sales.
In this IRP cycle, the Company improved the way that it models the relationship between
peak load and consumption drivers such as temperature. In its 2017 IRP, the Company modeled
peak load using a simple linear relationship between consumption and temperature. In fact, the
STAFF COMMENTS 12 JANUARY 20,2O2L
relationship is not linear: As the weather becomes more extreme, and heating/air conditioning
devices are required to run near their maximum capability, the relationship between temperature
and consumption flattens out. Thus, the Company's previous model tended to overstate
consumption during extreme weather events. In the 2019 IRP, the Company still used a linear
relationship to model consumption, but applied the results obtained from this model to a simple
neural network that corrected the model for extreme weather events.
Rather than use a neural network to correct its linear model, Staff would have preferred
that the Company take a more direct approach and use either a non-linear model or generalizable
linear model that is more closely aligned to the underlying relationship between peak load and
consumption drivers. Such a model would have avoided the use of a neural network and not
need further correction. Notwithstanding Staffs preference for a different peak modeling
methodology, Staff believes the Company's peak modeling methodology is adequate for use in
this IRP and lauds the Company's willingness to improve its methodology. Staff notes that peak
modeling is inherently more difficult than modeling average load. Whereas the averaging
process tends to smooth and make the monthly average load reasonably predictable, peaks are by
their nature unpredictable extreme events. Furthermore, the choice of peak modeling
methodology is highly sensitive to assumptions about the underlying relationships driving
consumption and assumptions about the statistical distribution of peaking events.
The Company did not implement two of the modeling improvements suggested by Staff
in its 2017 IRP comments: Staff recommended that l) peak forecasts be obtained by aggregating
results from individual classes, and 2) the Company include a sensitivity analysis with its
forecast. Staff believes that these improvements would both improve the accuracy of the IRp
and they would inform the Commission about the risk of assuming any particular forecast
assumptions.
The Company develops its monthly average load forecast by adding together the
individual 70th percentile forecast monthly loads from each of its customer classes, and by doing
so, provides a forecast that is less sensitive to individual assumptions than a forecast based on a
single system-wide growth model. Given the peak load forecast's relative importance, Staff
believes that the Company should use a similar methodology, albeit with 90th or 95th percentile
forecast monthly peaks, to forecast peak load.
STAFF COMMENTS t3 JANUARY 2O,2O2I
Staff believes that the Company's peak forecast should include a sensitivity analysis. The
Company's peak forecast is very sensitive to modeling assumptions, and particularly to
assumptions about growth rate. For example, the Company's model assumes an average annual
effective growth rate of l.2Vo. Using this growth rate, the Company determined that it would
experience a capacity deficit in calendar year 2O29; however, by assuming a growth rate only
0.17o less than that assumed by the Company, Staff found that the estimated capacity deficit date
was delayed by more than a year. Given the capacity deficit date's importance in the
determination of avoided capacity values, Staff believes that it is important to understand the
reliance of this calculation on modeling assumptions, and that a sensitivity analysis should be
included in the Company's L&RB.
PURPA contract renewals
The Company assumes that all PURPA contracts are renewed except for wind. Company
Response to Staff s Production Request No. 85. However, for purposes of establishing the first
capacity deficiency date in PURPA contracts, Staff believes it is reasonable to assume that all
PURPA contracts, including wind, are renewed, unless the Company has been informed by a QF
that its contract will not be renewed.
1. utilities are mandated by PURPA to take energy produced by a eF. 1g c.F.R. $
292.303.
2. Since these QFs are already existing and currently in operation, the roadblocks to
establishing a renewal contract are minimal.
3. In Idaho, there were26 QF contracts in total that expired in2019 and2020. Only two
expired without establishing a renewal. Every QF continuing operation after its
contract expired established another contract with the same utility.
4. Staff believes wind QFs have potential to renew their contracts like other technology
types.
Therefore, the Company should assume that all expiring PURPA contracts will be renewed after
their current term is complete, unless the QF notifies the Company that its contract will not be
renewed.
STAFF COMMENTS t4 JANUARY 2O,2O2I
Market purchases
Market purchases in the peak load L&RB only reflect total transmission capacity, without
considering market availability.a In PAC-E-15-12, the Commission stated that a utility's import
capability - its ability to make short term purchases using its transmission capacity - should
be included in the LR&B. Order No. 33425. Staff believes import capability is determined by
both transmission capacity and market availability and is constrained by the lower of the two
values. Therefore, Staff recommends that the Company consider not only transmission capacity,
but also market availability in determining market purchases for purposes of establishing the first
capacity deficiency date in PURPA contracts.
Non-owned Reserves
Non-owned reserves represent capacity sales through the OATT to wholesale customers
in a utility's balancing authority area (such as municipal and cooperative providers of electricity)
for which a utility is obligated to provide reserves. Currently, non-owned reserves are not
included in the L&RB for purposes of establishing the first capacity deficiency date in PURPA
contracts.5 Staff recommends that the Company include non-owned reserves in the peak load
L&RB as a decrease in existing resources, because the Company uses its own resources to
provide non-owned reserves.
Energy Efficiency
Existing energy efficiency is included in the peak load L&RB. However, the values for
existing energy efficiency include both existing energy efficiency and expanded energy
efficiency.6 Because utilities are expected to pursue all cost-effective energy efficiency
measures and the amount does not depend on the need for capacity, Staff believes that all cost-
effective energy efficiency measures should be included. Order Nos. 32426 and33917. In
addition, to make sure the resource category is better defined, Staff recommends changing the
label from "Existing EE" to "Energy Efficiency."
a This understanding was confirmed by Idaho Power on December 23,2020 through email.
s This understanding was confirmed by Idaho Power on December 18,2020 through email.
6 This understanding was confrmed by Idaho Power on December 18,2O2O through email.
STAFF COMMENTS 15 JANUARY 2O,2O2I
Regulation Reserves
The First and Second Amended 2019 IRPs incorporated regulation reserye requirement
rules identified in the 2018 Variable Energy Resource Integration Analysis ("2018 VER Study")
to estimate the amount of regulation reseryes necessary to balance the system net of load, wind
production, and solar production, without compromising system reliability while still allowing
construction of low-cost portfolios that meet the regulation reserve requirements.
Although this effort is a significant improvement compared to prior IRPs, Staff believes
additional improvements are needed to implement the regulation reserve requirements in the IRP
modeling process. Staff also believes that the Company should explore the impacts of reserve
shortfalls from a reliability perspective and a cost perspective.
The AURORA model used in the IRP has an hourly demand requirement, and optional
constraints including regulation reserve requirements. "The model's primary objective is to meet
the hourly demand. If a secondary constraint cannot be met, the model will relax an optional
constraint in order to meet its primary obligation (to meet the hourly demand)." Company
Response to Staff s Production Request No. 88(a). Staff believes it is critical to explore the
degree to which the optional regulation reserve requirements should be relaxed so that two
competing goals can be balanced: 1) The regulation reserve requirements should not be so
relaxed that the model produces unreliable portfolios, and2) The regulation reserve requirements
should not be so stringent that the model produces unreasonably expensive portfolios.
Besides this issue in upstream model assumptions, Staff also believes it is critical to
evaluate the regulation shortfalls in the downstream model results from a reliability perspective
and a cost perspective. The Company is able to quantify regulation shortfalls in Megawatt hours
for each portfolio; however, the impacts of these shortfalls have not been identified. For
example, it is not known if shortfalls result in unacceptable loss of load;7 how much it costs for
? In Response to Staff's Production Request No. 103 the Company states that a regulation reserve shortfall cannot
cause a loss of load event and that a loss of load event occurs when demand exceeds supply. Staff does not agree.
Staff believes a regulation reserve shortfall can cause demand to exceed supply, resulting in a loss of load event. In
fact, other utilities consider loss of load caused by regulation reserve shortfalls. For example, RMP assumes 0.5 loss
of load hours per year due to regulation reserve shortages in their 2019 Flexible Reserve Study, which is in addition
to any loss ofload resulting from transmission or distribution outages, resource adequacy, or other causes. See
RMP's 2019IRP, Appendix F p. 90, Case No. PAC-E-l9-16.
STAITF COMMENTS t6 JANUARY 2O,2O2I
the Company to fulfill any shortfalls; and whether the costs are added into the costs of
portfolios.8
Idaho Power is currently conducting a new Variable Energy Resource Integration
Analysis using a new methodology, but Staff believes that these questions still need to be
answered when new regulation reserve requirements are implemented in the IRP process. Staff
recofilmends that the Company further examine how to appropriately implement the regulation
reserve requirements in the IRP modeling process and explore any cost and reliability impacts
from any reserve shortfalls.
Changes to the Discount Rate
The Company developed the portfolios used in the Original 2019 IRP using a discount
rate of 9.59Vo, which included the Company's WACC plus a tax gross-up for the equity-financed
portion of the overall costs. This represented a change from prior IRPs, in which the after-tax
WACC was used for all discounting calculations. In subsequent filings, the Company used a
discount rate of 7 .l2vo to formulate its portfolios. The 7.l2%o discount rate reflects the after-tax
WACC. The Company states that both methods (pre-tax and after-tax) are analytically sound
and should be reasonably considered. In addition, the Company stated that the higher discount
rate may better align with the customer cost perspective, as it reflects the total financing costs
customers will pay through rates. The Company filed a Second Amended 2019IRP in October
2020 and returned to the prior practice of applying its internal after-tax WACC as the discount
rate. The Company will continue the practice until they can evaluate and vet the alternative
methodologies using a pre-tax WACC. The current approach of using the after-tax WACC
discount rate remains consistent with prior years. Staff agrees with the adjustment back to the
after-tax WACC discount rate and looks forward to the Company providing the additional
analysis and justification for using a post-tax WACC discount rate.
8 The Company stated "the costs were not quantified and therefore not included in any of the portfolio costs."
Company Response to Staff's Production Request No. 54.
STAFF COMMENTS 11 JANUARY 2O,2O2I
RECOMMENDATIONS
Staff recommends that the Commission acknowledge the Company's Second Amended
2019 IRP; however, Staff also cautions that the portfolios and other results obtained from the
Company's LTCE modeling may be unreliable. Staff also recommends the following:
l. Order the Company to model B2H as a resource based on its economic value.
2. Order the Company to provide detailed analysis and explanation of how the capacity
it forecasts will be available for B2H import and provide more specifics about where
the capacity will come from.
3. Order the Company to provide a detailed analysis for a hypothetical 45Vo and lOl%o
ownership share of the B2H transmission line if ownership is still unresolved during
the next IRP.
4. Order the Company to notify Staff of any change between B2H transmission line
partners within 7 business days of the occuffence.
Respectfully submitted this 20rH day of January 2021
r(
Edward
Deputy Attorney General
Technical Staff: Michael Morrison
Travis Culbertson
Rachelle Farnsworth
Kevin Keyt
Yao Yin
Umisc/CommentVipcel 9. l9ejmmksktncyyrf corunents
STAFF COMMENTS 18 JANUARY 20,2O2I
w
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 2OTH DAY OF JANUARY 2021,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. IPC-E-19.19, BY E-MAILING A COPY THEREOF, TO THE
FOLLOWING:
LISA D NORDSTROM
REGULATORY DOCKETS
IDAHO POWER COMPANY
PO BOX 70
BOISE rD 83707-0070
E-mail : lnordstrom@idahopower. com
dockets @,idahopower. com
BENJAMIN J OTTO
ID CONSERVATION LEAGUE
710 N 6TH ST
BOISE ID 83702
E-mail: [e-mail]
PETER J zuCHARDSON
RICHARDSON ADAMS PLLC
515 N 27TH STREET
PO BOX 7218
BOISE ID 83702
E-mail: [e-mail]
JACK VAN VALKENBURGH
VAN VALKENBURGH LAW PLLC
PO BOX 531
BOISE ID 8370I
E-mail: [e-mail]
AUSTIN RUESCHHOFF
THORVALD A NELSON
HOLLAND & HART LLP
555 ITTH ST STE 32OO
DENVER CO 80202
E-mail : darueschhoff@hollandhart. com
tnelson@hollandhart. com
aclee@hollandhart. com
gl garanomari @hollandhart. com
TIM TATUM
MATT LARKIN
IDAHO POWER COMPANY
PO BOX 70
BOrSE rD 83707-0070
E-mail : ttatum@idahopower. com
mlarkin@.idahopower. com
C TOM ARKOOSH
ARKOOSH LAW OFFICES
PO BOX 2900
BOISE ID 83701
E-mail: [e-mail]
eri n. ce ci I @,arkoo sh. com
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-mail: [e-mail]
JIM KREIDER
STOP B2H COALITION
60366 MARVIN RD
LA GRANDE OR 97850
E-mail: [e-mail]
JIM SWIER
MICRON TECHNOLOGY INC
8OO SOUTH FEDERAL WAY
BOISE ID 83707
E-mail: [e-mail]
CERTIFICATE OF SERVICE
JULIAN ARIS
SIERRA CLUB
2101 WEBSTER ST STE 13OO
OAKLAND CA94612
E-mail: [e-mail]
GLORIA D SMITH
SIERRA CLUB
2101 WEBSTER ST STE 13OO
OAKLAND CA946I2
E-mail: [e-mail]
SECRE
CERTIFICATE OF SERVICE