20220331Amended Comments.pdf

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DAYN HARDIE
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 9917
Street Address for Express Mail:
1 I33I W CHINDEN BLVD, BLDG 8, SUITE 2OI-A
BOISE, TD 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION FOR
APPROVAL OF THE CAPACITY
DEFICIENCY TO BE UTILIZED FOR
AVOIDED COST CALCULATIONS
CASE NO. IPC.E.2I.Og
AMENDED COMMENTS OF
THE COMMISSION STAFF
STAFF OF the Idaho Public Utilities Commission, by and through its Attorney of
record, Dayn Hardie, Deputy Attomey General, submits the following comments.
BACKGROUND
On April 9,202l,Idaho Power Company ("Company") applied for Commission approval
of its capacity deficiency period determination for avoided cost calculations under the Public
Utility Regulatory Policies Act of 1978 ("PURPA") and Order Nos. 32697, 33084, 33159, and
34659. Based on its second amended 2019 Integrated Resource Plan ("IIU)'') the Company
asked for Commission approval of the capacity deficiency period with a first deficit occurring in
August 2028.
On February 4,2022, the Company filed a motion and amended application ("Amended
Application"), seeking to implement a first capacity deficit of July 2023 for both the Surrogate
Avoided Resource ("SAR") method and the IRP method. Idaho Power also requests that the
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ISTAFF COMMENTS MARCH 31,2022
Commission direct that future capacity deficiency filings for PURPA avoided cost rates be made
at the time the IRP is filed, rather than at the time the IRP is acknowledged.
Under PURPA, the Commission has established a surrogate avoided resource ("SAR")
method and an IRP method to calculate avoided cost rates for qualiffing facilities ("QFs").
Under both methods, a QF receives capacity payments only after the applicable capacity deficit
date is reached. Order Nos. 33377,33159, and 33898. The first deficit date under the IRP
method will float to reflect the changes in the QF queue, while the first deficit date under the
SAR method will not float to reflect the changes in the QF queue. Order No. 33933.
The capacity deficiency period is determined through the IRP planning process and is
submitted to the Commission in a proceeding separate from the IRP docket. The capacity deficit
date determined in the IRP process is presumed to be correct as a starting point but will be
subject to the outcome of the capacity deficiency case. Order No. 32697.
STAFF REVIEW
Staff reviewed the Load and Current Resource Balance ("L&R") contained in the
Company's Amended Application and recommends the following changes be made to the
proposed L&R:
o Use the most recent load forecast developed by the Company with Brisbie's load
removed and a l5.5oh planning reserve margin ("PRM") applied;
. Veriff the capacity amounts of Brownlee Hydro and Shoshone Falls Hydro facilities
and make sure the correct capacity amounts are used in the L&R;
. Add Energy Efficiency ("EE") Bundles to the L&R as an adjustment to load;
o Assume no renewals for PURPA wind projects unless the Company receives
information from the wind qualifuing facilities indicating they plan to renew their
contract;
o Reflect the expiration date of Path C transmission capacity, unless the Company has
renewal rights;
o Remove Boardman to Hemingway ("B2H") and B2H-related transmission capacity;
and
o Include the capacity of Western Systems Power Pool ("WSPP") market purchases in
the L&R, if not already included.
2STAFF COMMENTS MARCH 31,2022
Staff recommends that the Company file an updated L&R incorporating these changes
and update the first capacity deficiency date accordingly. The first capacity deficiency date
should be used in both the SAR method and the IRP method. Lastly, Staff recommends that if
the Commission decides to re-evaluate when the capacity deficiency date case should be filed, a
generic docket should be opened because the decision may need to consider factors affecting all
three Idaho electric utilities.
Load Forecast in the L&R
Staffcontinues to believe that the latest load forecast provides better accuracy for
determining the first capacity deficiency date because it is based on the most current information.
See Staff s comments filed on July 2l ,2021. If a more recent load forecast is available, Staff
recommends that the Company include it with Brisbie loads removed in an updated L&R with
the same 15.5% PRM applied.
The load forecast in the L&R includes Brisbie's forecasted load. See page 13 of Mr.
Tatum's Direct Testimony in Case No. IPC-E-21-42. Staff believes that Brisbie's load should be
removed from the load forecast because Brisbie's load and resource are contingent upon one
another. Until the Commission has approved the Brisbie contract, neither the load nor resource
should be included in the L&R.
The proposed load forecast includes a 15.5oh PRM based on a one day in twenty years
(1-in-20) or 0.05 days per year Loss of Load Expectation ("LOLE") reliability target. The
Company changed its target from a one-day in ten years (1-in-l0) LOLE target to the more
stringent target toward the end of the 2021 IRP cycle. According to the Company, this reliability
target was changed to account for the extreme weather events that are becoming more frequent
and increased uncertainty in year-to-year water availability impacting hydro generation. The
Company also stated that Northwest Power and Conservation Council used the same target in its
Seventh Power Planl and its Resource Adequacy site.z See Response to Staff s Production
Request No. l5 in Case No. IPC-E-21-43.
A 1-in-10 LOLE target is the industry standard for resource planning. See Response to
Staff s Production Request No. 14 in Case No. IPC-E-21-43 and the North American Electric
I https://www.nwcounci l.orgreportsiseventh-power-plan
2 https ://www. nwcou nci l.orVenergy/eners-v-top ics/resource-adequac),
aJSTAFF COMMENTS MARCH 31,2022
Reliability Corporation ('NERC")'s2021Long-Term Reliability Assessment.3 Staff does not
agree with the Company's justification used to change the LOLE target in the Company's IRP.
The reliability target threshold should be determined independent of the Company's loads and
resources and should be a policy decision based on the tolerance of customers and the public to
costs, risks, and other impacts related to electricity outages.
Instead of using a more stringent target, Staff believes it is more appropriate to
incorporate year-to-year variability in both the Company's load forecast and availability of hydro
generation rather than assuming average weather conditions in the IRP. The Company illustrated
how weather variability over just a four-year historic period can have a dramatic effect on the
resources needed to ensure reliability. By comparing each year's weather effect on2023
resource requirements to resource requirements based on average weather over those same years,
the Company demonstrated shortages could occur in two out of the four years. See Response to
Production Request No. 20 in Case No. IPC-E-21-32. This indicates that the load forecast may
be underestimated, or hydro resource capacity contribution overestimated (or a combination of
both) during some years over the IRP time horizon by not accounting for year-to-year variability
in weather. Given the resulting 15.5% PRM is close to the l5oh PRM used in previous IRPs,
Staff believes that using average weather and hydro conditions, but compensating by using a
more stringent l-in-20 LOLE target achieves approximately the same effect.
Resources in the L&R
Staff s evaluation of resources in the L&R is based on the principle of whether a resource
is "available" and/or "existing", unless exceptions are justified. Staff s review is focused on (l)
Jackpot Solar, (2) the Brownlee Hydro and Shoshone Falls Hydro facilities, (3) EE Bundles, (4)
PURPA Wind Renewals, (5) Thermal Plants, (6) Early Coal Plant Retirements, (7) Market
Purchases with Secured Third-Party Transmission, and (8) New Contract Changes.
Jackpot Solar
Staff believes that no changes should be made to the proposed L&R due to the delay of
Jackpot Solar. The developers of Jackpot Solar informed the Company that global supply chain
disruptions have raised concerns regarding Jackpot Solar's ability to achieve commercial
3 https://www.nerc.com/palRAPA/ralReliability%20Assessnrents%20DLNERC_LTRA-202l.pdf
4STAFF COMMENTS MARCH 31,2022
operation by the dates identified in the approved agreement. See page 170 of Idaho Power's
2021 IRP. The latest information from the developers indicates that Jackpot currently anticipates
a 40-day delay in project completion from the Scheduled Commercial Operation Date of
December 1,2022. See Response to Staff s Production Request No. 8 in Case No. IPC-E-21-43.
All the solar resources on the Company's system do not contribute capacity during winter
months of December, January, and Februarya inthe L&R. A 40-day delay should not affect the
project's capacity contribution to the system or the deficit date, especially since the deficit date
for the Company's system does not occur until the summer months.
Brownlee Dam and Shoshone Falls
Staff recommends that the Company veriff the capacity amounts of Brownlee and
Shoshone Falls hydro facilities and make sure the correct capacity amounts are included in the
L&R. Page 38 of the 2021 IRP states that the Company has 17 hydroelectric projects with a total
nameplate capacity of 1,773 megawatts ("MW"). The nameplate capacity for Brownlee
increased by 22.4 MW and the Shoshone Falls nameplate capacity increased by 3.2 MW
both due to plant upgrades. Together these changes increased hydro nameplate capacity from
1,773 MW to 1,798.8 MW. See Response to Staff s Production Request No. I in Case No.
IPC-E-2I-43.
EE Bundles
Staff recommends that EE Bundles be added to the L&R as an adjustment to the load
forecast, even though this would not affect the identification of the first capacity deficiency date.
In determining the deficit amount of each year over the planning horizon, the proposed L&R
uses the EE amounts determined in the EE Potential Study as an adjustment to load, which
includes both the existing and future EE programs deemed to be cost-effective from the Utility
Cost Test. See Response to Staff s Production Request No. 9 in Case No. IPC-E-2I-43. The EE
Bundles selected in the preferred portfolio are treated as new resources and are not used to adjust
the load forecast. As stated in Staff s first set of comments, all cost-effective EE should be
a Response to StafPs Production Request No. 6 in Case No. IPC-E-21-09 states that, for winter months, the system
peak hour occurs in the morning before sunrise. Therefore, PURPA solar capacity is zero in winter months of
December, January, and February. Staffbelieves this rationale also explains why Jackpot Solar has zero capacity in
the winter months.
5STAFF COMMENTS MARCH 31,2022
included, because utilities are expected to pursue all cost-effective EE pursuant to Order Nos.
32426 and33917. Therefore, Staff believes that all cost-effective EE, whether identified from
the EE Potential Study or from the modeling process, should be included in the L&R. However,
this will not affect the determination of the first capacity deficiency date because EE Bundles do
not provide capacity until 2039.
PURPA Wind Renewals
The Company's assumption that wind QFs will not renew their ESAs has been in place
for several IRP cycles. See Idaho Power's Reply Comments in Case No. IPC-E-I9-19. Staff
believes it is reasonable to assume no renewals for PURPA wind projects absent receipt of
information from the wind qualifring facilities indicating intent to renew. Therefore, Staff
recommends that the Company remove the 25o/o renewal rate in the proposed L&R and include
only the capacity for wind projects that have indicated intent to renew contracts upon expiration.
Staff has three reasons to support its recommendation. First, the obstacles to wind
renewals still exist, which include the high cost of repowering wind facilities, reductions and/or
elimination of tax credits, and integration costs for wind. Second, a wind project will either
renew in total or not renew its contract; it is unlikely that only 25o/o of a wind project will renew
after a contract expires. Finally, the Company's communication with wind project owners did
not provide a positive indication of their intent to renew. See Response to Staff s Production
Request No. 7 in Case No. IPC-E-21-43.
Because the Company has established communication with wind developers and because
of difficulties for renewals, Staff believes that the inclusion of renewal contracts should be based
on an indication that a project will renew its contract on a case-by-case basis.
Thermal Plants
Staff believes the capacity of thermal plants included in the L&R is reasonable.
Compared to the original L&R included within the Application on April 9, 2021, the updated
L&R in the Amended Application updated the capacity amounts of Bridger, Valmy, Bennet
Mountain, and Danskin plants due to methodology changes to determine capacity contribution in
the 2021 IRP. The method used in the updated L&R incorporates Effective Forced Outage Rates
("EFOR") and the refinement of Effective Load Carrying Capability ("ELCC"). There are also
6STAFF COMMENTS MARCH 31,2022
small refinements made to the peaking capabilities of coal and gas units. See Response to Staff s
Production Request No. 9 in Case No. IPC-E-21-43. After a detailed review of the Company's
methods for predicting capacity contribution of thermal resources, Staff believes that they are
accurate and reasonable.
Eorly Coal Plant Retirements
Other than a planned exit of Valmy Unit 2 atthe end of year 2025, there are no early
coal plant exits in the L&R. See Response to Staff s Production Request No. 33 in Case No.
IPC-E-21-09. Staff believes this treatment in the L&R is reasonable. As stated in Staff s
July 2l ,2021, comments, existing resources should reflect their authorized useful life unless
early retirements are authorized; until then, any resource decision not authorized by the
Commission is speculative.
In Avista's early exit of Colstrip Units 3 and 4, the Commission stated Avista's decision
to include the 2025 exit of Colstrip Units 3 and 4 is presumptuous and ignored that the
Commission had not addressed the economic retirement date for those units. Order No. 34981.
Further Order No. 34981 stated that until the Commission had an opportunity to evaluate and
determine a proper exit date, it was unreasonable to utilize Avista's updated first capacity
deficiency date.
Given these criteria, Staff believes that Valmy Unit 2 should be included until the end of
2025. Valmy started operation in 1985 with a 50-year useful life. However, in the Settlement
resulting in Case No. IPC-E-16-24, the parties agreed Idaho Power will negotiate with co-owner
NV Energy to accomplish a permanent end to coal-burning operations of Valmy Unit I by
December 31,2019, and of Valmy Unit 2 by December 31, 2025. Or, alternatively, the parties
agreed that Idaho Power will use prudent and commercially reasonable efforts to end its
participation in the operation of Valmy Unit I by December 31, 2019, and Valmy Unit 2 by
December 31,2025. The Settlement was approved in OrderNo. 33771. Therefore, Staff
believes it is reasonable to reflect retirement of Valmy Unit 2 in the L&R based on the approved
Settlement.
7STAFF COMMENTS MARCH 31,2022
Market Purchases with Secured Third-Party Transmission
In its review of Market Purchases with Secured Third-Party Transmission, Staff focused
on four components: (l) Capacity Benefit Margin ("CBM"), (2) Idaho-NV Energy Path, (3) Path
C, and (4)B2H assumptions.
1. CBM - Staff believes that the CBM contained in the L&R is reasonable. CBM is
transmission capacity the Company holds as being unavailable for firm use on its
transmission system for the purpose of accessing reserve energy to recover from
severe conditions such as unplanned generation outages or energy emergencies. It
allows the utility to reduce the amount of reserve generation capacity on its system by
providing transmission availability to another market. See Response to Staff s
Production Request No. 11 in Case No. IPC-E-21-43. If tdaho Power were to replace
the emergency reserve provided by CBM with another on-system resource, then the
Company would be in the same position for resource planning purposes. Reducing or
eliminating CBM moves the need for capacity from one bucket (serving load) to
another bucket (PRM), while having no impacts on the Company's overall system
capacity need. See Idaho Power's Reply Comments in Case No. IPC-E-19-19.
Because CBM is used to lower the Company's need for PRM to cover emergencies,
Staff believes it should be included in the L&R as the Company proposed.
The capacity amount of CBM in the proposed L&R is 330 MW for the entire
planning horizon, which is based on the Company's most severe single contingency:
the loss of two Bridger Units or the loss of the Langley Gulch Plant. See Response to
Staff s Production Request No. l1 in Case No. IPC-E-21-43. Staff believes that this
amount accurately reflects the magnitude of the greatest potential emergency on the
Company's system and that the amount of CBM capacity included in the proposed
L&R is reasonable.
2. Idaho-NV Energy Path - Staff believes capacity available through the Idaho-NV Energy
path is reasonable. The Company uses the Idaho-NV Energy path to import electricity
generated at Valmy. However, access to firm transmission south of Valmy currently
does not exist. The Company reflects transmission access to Valmy until the Valmy
8STAFF COMMENTS MARCH 31,2022
exit date in the L&R. Staff believes is reasonable and reflects the actual transmission
circumstances.
Path C - Staffrecommends the L&R reflect the expiration date of Path C transmission
capacity unless the Company has renewal rights. Despite the Idaho-NV Energy Path,
the Company has secured 50 MW of transmission capacity between June and October
to access Southwest markets through Path C, which is owned and operated by
PacifiCorp. See Page 13 of Appendix D of the 2021 IRP. However, this 50 MW is
included in the proposed L&R for the entire planning horizons without an expiration
date. Staff recommends that the L&R reflect its actual expiration date unless the
Company has renewal rights.
4. B2H Assumptions - Staffrecommends B2H-related transmission capacity should be
removed from the proposed L&R. B2H has not been authorized by the Commission
and should not be included in the L&R until there is some regulatory certainty that it
will become a resource. Because the B2H project has not been approved by the
Commission and the term sheet between the funding parties6 is non-binding, Staff
recommends B2H and B2H-related transmission capacity (i.e. 500-MW BPA
transmission service and 200-MW acquisition from PacifiCorp) should be removed
from the proposed L&R.
New Contract Changes
Since the development of the proposed L&R, the Company has witnessed three contract
changes: (1) a Power Purchase Agreement ("PPA") with Black Mesa Energy, LLC, for a 40-MW
solar project, (2) a PPA with Verde Light Community Solar, LLC, for a 2.95-MW solar project
under the Oregon Community Solar Program, and (3) a WSPP Schedule C agreementfor 76-
5 The proposed L&R uses transmission capacity forecasts contained in Tab "ATC Backgnd" in the Attachment
contained in Response to Staffs Production Request No. 29 in this case. These forecasts cover202l through 203 l,
while the L&R covers 2021 through 2040. After 203l,the transmission forecasts used in the proposed L&R repeat
the 2031 forecasts.
6 On January 18,2022, the three B2H permit funding parties (ldaho Power, PacifiCorp, and Bonneville Power
Administration ("BPA")) executed a non-binding term sheet that addresses B2H ownership, transmission service
considerations, and asset exchanges. Seepage I ofAppendix D ofthe 2021 IRP.
.,
9STAFF COMMENTS MARCH 31,2022
MW market purchases to be delivered to the Company's border June through September in2022
through 2024, for hours ending 0700-2200 Pacific Prevailing Time. Staff recommends different
treatments to these contracts.
As stated earlier, future resources and their corresponding useful lives should be included
when authorized, because any resource decision not authorizedby the Commission is
speculative. The Black Mesa 40-MW solar PPA has not been authorized by the Commission and
should be removed from the L&R.
Verde Light's 2.95-MW solar project should not be included in the L&R because the
project has not been certified. Although this project has been pre-certified, the project needs to
be 50 percent subscribed to receive final certification. See page 4l of Oregon Community Solar
Program's Program Implementation Manual (Version 2022011l).7 According to the program
design, any generation from a pre-certified project that is not sold or finally subscribed will sell
to utilities through a2}-year PPA on an "as-available" basis subject to the requirements of
PURPA and ORS $ 758.505 upon request. "As-available" is considered non-firm and should not
be included in the L&R. Therefore, Staff recommends inclusion of Verde Light's subscribed
capacity in the L&R once the project is certified.
The Company has established a WSPP market purchase, which typically does not require
Commission approval. However, these purchases may not have any impacts on the proposed
L&R because the capacity associated with purchases may be covered by Market Purchases with
Secured Third-Party Transmissior. Staff recommends that any impacts of the WSPP market
purchases should be reflected in the L&R, if not already included.
Filine Schedule
The Company requests that the Commission direct that future first capacity deficiency
date filings for PURPA avoided cost rates be made at the time the IRP is filed. Staff
recommends if the Commission decides to re-evaluate its direction for capacity deficiency date
case filings, a generic docket should be opened. Staff believes the decision should be made
considering relevant factors impacting all three Idaho electric utilities.
7 https://www.oregoncsp.orglpim/
STAFF COMMENTS l0 MARCH 31,2022
Currently the Commission requires each Idaho electric utility to submit its capacity
deficiency date filing after acknowledgement of its IRP, rather than upon its IRP filing. Order
No. 33917. In addition, Order No. 34649 states:
[T]he Commission determines that it is prudent for the Company to file its first
capacity deficit date cases upon IRP acknowledgment. The narrower capacity
deficiency review should follow the more in-depth IRP review, thereby providing
assurances that the Company is using data and forecasts that have undergone
rigorous review before establishing its first capacity deficit date. This is not done
for the mere convenience of Commission Staff, as the Company suggests, but to
ensure that a review of the Company's data has indeed occurred before using the
data to establish QFs rates. The Company's claim that delaying the processing of
its first capacity deficit date cases will be to the direct detriment of ratepayers is
unpersuasive. This is an anticipated, biennial update that will provide an
opportunity for a QF to establish a legally enforceable obligation before the
update occurs, regardless of whether the update occurs after the IRP is filed or
after the IRP is acknowledged.
Regardless of when the first capacity deficiency date case should be filed, the date should
be determined based the latest and most accurate information. The Commission has expressed
this expectation in prior orders:
1. "The capacity deficiency determined through the IRP planning process will be the
starting point, and will be presumed to be correct subject to the outcome of the
proceeding." Order No. 32697.
2. It is appropriate for a utility to use the most updated information available in
calculating its capacity deficit date. Order No. 33958.
3. PacifiCorp is required to use the most recent peak-load forecast when its next
capacity deficiency case is filed. OrderNo.34918.
Further, when complex new methods are introduced in an IRP that affect the first
capacity deficiency date, including the methods used to determine the capacity contribution of
resources and the determination of the PRM in the202l IRP, consideration for the time required
to perform the review should be given. As is currently required by Commission orders, this level
of review is performed after the review of the IRP, requiring a shorter review period during the
deficiency date case filed after IRP acknowledgment. Altematively, as proposed by the
Company, the capacity deficiency date case could be filed at the same time as the IRP so that
both cases are processed simultaneously but allow sufficient time during the deficiency date case
schedule to ensure any new methods and/or data can be fully vetted.
STAFF COMMENTS ll MARCH 3I,2022
If the Commission decides to re-evaluate the schedule, Staff recommends the
Commission open a generic docket to determine the deficiency date filing schedule in relation to
the schedule of the IRP to ensure all three utilities can provide input.
STAFF RECOMMENDATION
Staff recommends that the Company file an updated L&R and a new first capacity
deficiency date as a compliance filing that incorporates the following changes:
o Uses the most recent load forecast developed by the Company with Brisbie's load
removed and a l5.5Yoplanrring margin applied;
. Verifies the capacity amounts of Brownlee Plant and Shoshone Falls Plant and make
sure the correct capacity amounts are used in the L&R;
. Adds EE Bundles to the L&R as an adjustment to load;
o Assumes no renewals for PURPA wind projects, unless the Company receives
information from the wind qualifring facilities indicating they plan to renew their
contracts;
o Reflects the expiration date of Path C transmission capacity, unless the Company has
renewal rights;
o Removes B2H and B2H-related transmission capacity; and
. Includes the impacts of WSPP market purchases in the L&R, if there are any impacts
on the L&R.
Staff also recommends that, if the Commission decides to re-evaluate when the capacity
deficiency case should be filed, a generic docket should be opened to consider impacts to all
three Idaho electric utilities.
3t*Respectfully submitted this day of March2022.
Dayn
Technical Staff: Yao Yin
i:umisc/commentVipce2l.9dhyy amended comments
STAFF COMMENTS t2
Deputy Attorney General
MARCH 31,2022
CERTIFICATE OF SERYICE
I HEREBY CERTIFY THAT I HAVE THIS 3IST DAY OF MARCH 2022,
SERVED THE FOREGOING AMENDED COMMENTS OF'THE COMMISSION
STAFF, IN CASE NO. IPC-E-21-09, BY E-MAILING A COpy THEREOF, TO THE
FOLLOWING:
DONOVAN E WALKER
IDAHO POWER COMPAI.IY
PO BOX 70
BOISE rD 83707-0070
E-MAIL: [e-mail]
dockets@idahopower. com
PETER J RICHARDSON
RICHARDSON ADAMS PLLC
515 N 27TH ST
BOISE ID 83702
E-MAIL: [e-mail]
C TOM ARKOOSH
ARKOOSH LAW OFFICES
913 RIVER ST STE 450
BOISE ID 83702
E-MAIL: [e-mail]
erin. ceci I @arkoosh. com
CAMILLE CHRISTEN
ENERGY CONTRACTS
P.O. BOX 70
BOISE,ID 83707
E-MAIL: [e-mail]
enerq.vcontracts @ i dahopower. com
DR DON READINU
6070 HILL ROAD
BOISE ID 83703
E-MAIL: [e-mail]
SECRET
CERTIFICATE OF SERVICE