20221212PAC to Staff 25-32.pdf

Y ROCKY MOUNTAIN
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1407 W Noilh Temple, Suite 330
Salt Lake City, Utah 84116
December 12,2022
Jan Noriyuki
Idaho Public Utilities Commission
472W. Washington
Boise, ID 83702-5918
[e-mail]. eov (C)
RE ID PAC.E.22-14
IPUC Set 2 (25-34)
Please find enclosed Rocky Mountain Power's Responses to IPUC 2d Set Data Requests2s-32.
The responses to IPUC 33-34 will be provided separately.
If you have any questions, please feel free to call me at [phone]
Sincerely,
-Jsl-J. Ted Weston
Manager, Regulation
Enclosures
PAC-E-22-14 / Rocky Mountain Power
December 12,2022
IPUC Data Request 25
IPUC Data Request 25
The Company's response to Production Request Nos. l, I 0, and 24 discussed the 3o/o
being applied to Front OfIice Transactions (FOTs). Please respond to the following:
(a) Please confirm that this 3% is required by NERC.
(b) Please confirm that the 3Yo contained in the Planning Reserve Margin is
intended to cover the Company's generator outage, while the 3% applied to
FOTs is intended to cover third party's generator outage.
(c) Please explain in detail why it is reasonable to apply the 3%o to FOTs for the
purpose of Load and Resource Balance (L&R).
Response to IPUC Data Request 25
(a) The 3 percent requirement is based on North American Electic Reliability
Corporation (NERC) standard BAL-002-WECC-2, as discussed in Appendix F
of PacifiCotp's2021Integrated Resource Plan (IRP). To comply with this
standard, utilities hold operating reserves equal 3 percent of their load plus 3
percent of their generation. Those reserves need to be able to be deployed within
10 minutes and at least half of those operating reserves need to be "spinning",
i.e. immediately responsive to changes in system frequency. Market purchases
do not impact the reserves associated with a utility's load, but they do reduce the
need for generation in the utility's balancing authority area (BAA), which also
avoids the 3 percent operating reserve obligation associated with that generation.
(b) Operating reserves held in accordance with NERC standard BAL-002-WECC-2
are deployed in the first hour after a transmission or generation outage. With
respect to deployment of those reserves, there is no distinction between the
requirement associated with load and the requirement associated with
generation, and all reseryes may be deployed in response to any type of outage
condition. As a result, a utility would need to have an additional 3 percent
operating reserves to be able to deploy a generating resource. With a firm
market sale, the third party would hold the additional 3 percent operating
reseryes associated with the sales volume, and it would deploy those operating
reserves to maintain the firm sale immediately after it experienced a forced
outage.
(c) Please refer to the Company's responses to subparts (a) and (b) above.
Recordholder:Dan MacNeil
Sponsor:Dan MacNeil
PAC-E-22-14 / Rocky Mountain Power
December 12,2022
IPUC Data Request 26
IPUC Data Request 26
Response to Production Request No. 3 discussed the load forecast. Please confirm
that the 2021lntegrated Resource Plan (RP) Update used the same methodology
to determine the load forecast as the 2021 IRP, which did not use the Bureau of
Reclamation Study. [f not, please explain what methodology was used to
determine the load forecast in the 2021 IRP Update.
Response to IPUC Data Request 26
The Company interprets the reference to "methodology" to mean normal weather
calculation methodology. Based on the foregoing interpretation, the Company
responds as follows:
Yes, the Company used the same nonnal weather calculation methodology in the
2021lntegrated Resource Plan QRP) and the 2021 IRP Update. The Bureau of
Reclamation's climate change projections were only used in the climate change
scenario in PacifiCorp's2021IRP and were not used in PacifiCorp's 2021 IRP
Update.
Recordholder: Lee Elder
Sponsor:Lee Elder
PAC-E-22-14 / Rocky Mountain Power
December 12,2022
IPUC Data Request 27
IPUC Data Request2T
The Company's response to Production RequestNo. 3 discussed the green
highlighted area within Confidential Auachment IPUC 1. Please respond to the
following:
(a) Please explain whether the conffacts in the green highlighted areas need to be
approved by their corresponding Commission(s).
(b) For those that need approval, have they been approved yet? Please explain.
(c) Generally, do PURPA projects in all territories of the Company need approval
from their corresponding Commissions? Please explain.
Response to IPUC Data Requqt?T
(a) None ofthe referenced contacts are contingent upon commission approval,
thus they are effective upon execution.
(b) Not applicable, please refer to the Company's response to subpart (a) above.
(c) Public Utility Regulatory Policies Act of 1978 (PURPA) powerpurchase
agreements (PPA) in Idaho and Utah are approved by their respective
commissions. PURPA PPAs in Wyoming are accepted for filing and are not
generally subject to additional process or approval. PURPA PPAs in the
Company's other jurisdictions are not subject to commission approval.
Recordholder: Dan MacNeil
Sponsor:Dan MacNeil
PAC-E-22-14 / Rocky Mountain Power
December 12,2022
IPUC Data Request 28
IPUC Data Request 28
Response to Production RquestNo. 4 discussed PURPA renewals. In the L&R,
does the Company assume PLJRPA project renewals in other states' jurisdictions?
Please explain.
Response to IPUC Data Request 28
PacifiCorp's2021 Integrated Resource Plan (RP) and202l IRP Update did not
assume Public Utility Regulatory Policies Act of 1978 (PURPA) project renewals
in any jurisdictions. Because ofthe immediate timing of the proposed deficiency
period, the load and resource balance in the Company's filing reflects the actual
status of current PLJRPA power purchase agreements (PPA), i.e. whether it is
currently effective lrl.2023, rather than a projection of renewals through a future
deficiency date.
Recordholder: Dan MacNeil
Sponsor:Dan MacNeil
PAC-E-22-14 / Rocky Mountain Power
December 12,2022
IPUC Data Request 29
IPUC Data Requst29
Response to Production Request No. 4 stated that non-firm contacts do not
commit to providing capacity. Please respond to the following:
(a) Please define "non-firm" contracts and provide examples.
(b) Please explain why non-firm contracts do not provide any capacity on the
resource side of the L&R. Specifically, from a statistical perspective, do non-
firm contracts provide capaclty less than firm confiacts but gteater than zero?
Please explain.
Response to IPUC Data Request 29
(a) The referenced non-firm (NF) contracts are generally cogeneration facilities
who produce steam as part of their production processes. The generation from
that steam prior to its use for other purposes is somewhat incidental and
usually is used to serve their own onsite load fnst, with only the excess
delivered to the grid. These conftacts do not have performance requirements
or minimum delivery guarantees, and some such contracts have zero
deliveries in an entire year. The contact is nonetheless necessary for
PacifiCorp to be ready accept such deliveries should they occur. Because it is
not a firm commitment, the contract terms do not typically have a long-term
fxed price, but instead use either a market index or market pricing which is
updated annually. Examples ofNF contracts are the Utah qualifying facility
(QF) contracts with Kennecott and Tesoro that have had annual NF contracts
for many years.
(b) Because NF contracts do not include commifinents to deliver generation,
PacifiCorp does not generally attribute capacity to them on the resource side
of the load and resource balance. Where the incremental output is occasional,
it is likely to coincide with reduced onsite customer load, which is unlikely to
coincide with the peak conditions that drive capacity needs. Where a customer
routinely generates power in excess of its needs, it may coincide with peak
conditions and enhance reliability slightly. In Pacifi Corp' s 2021 Integrated
Resource Plan (IRP) Update, minor amounts of such NF generation may be
reported in the "Contracts" line item.
Recordholder: Dan MacNeil
Sponsor:Dan MacNeil
PAC-E-22-14 / Rocky Mountain Power
December 12,2022
IPUC Data Request 30
IPUC Data Request 30
Page 15 of the 2021 tRP stated Dave Johnston Units 14 will be retired at the end
of 2027. Please respond to the following:
(a) [s2027 an early retirement year for Dave Johnston?
(b) If so, what is each unit's end-of-life schedule?
(c) It2027 is an early retirement year, please explain why Dave Johnston does
not show on Tab "Adjustments" of the Excel File of 'Attach IPUC I CONF".
Response to IPUC Data Request 30
(a) This was not considered an early retirement in PacifiCorp's2021Integrated
Resource Plan (IRP) or the 2021 IRP Update. 2027 was the last year in which
the four Dave Johnston units were assumed to be available to operate in the
2021 IRP. However, the202l tRP did contemplate possible installation of
carbon, capture, utilization and storage (CCUS) equipment at Dave Johnston
Unit 4 which, along with other ongoing maintenance, would have extended
the life of the plant. [n light of that possibility and reconsideration of these end
of life dates generally, the Company's 2023 IRP has assumed that the Dave
Johnston units could retire early or could continue to operate as follows:
Dave Johnston Unit I and Dave Johnston Unit2l. as late as December 31,2028.
Dave Johnston Unit 3: as late as December 31,2027.
Dave Johnston Unit 4: as late as December 31,2039.
Please refer to slide 25 from the presentation materials from PacifiCorp's
2023IRP public input meeting held on September 1,2022 / September 2,
2022.The presentation materials are publicly available and can be accessed by
utilizing the following website link:
https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/ener
gy/integrated-resource-plan/2023- irp/l RP_PI M_Sept%20 I -2_2022. pdf
(b) Not applicable
(c) Not applicable.
Recordholder:Dan MacNeil
Sponsor:Dan MacNeil
PAC-E-22-14 /Rocky Mountain Power
December 12,2W2
IPUC DataRequest 3l
IPUC Data @ucst 31
Which coal plants are assumd to last indefinitely in the L&R besides Craig and
Hayden?
Responee to IPUC Data @uest 31
The rezults presentod in Table No. 2 of the Company's Application assume all of
the coal plants wift retirement daGs could be e:rtended through the end ofresrtts,
which was 2031. In addition to Craig, Hayden, Naughton Unit 1, Nurghton Unit
2, Colstrip Unit 3, and Colsuip Unit 4 were also extended.
Recordholder: Dan MacNeil
Sponson Dan Maclleil
PAC-E-22-14 / Rocky Mountain Power
December 12,2022
IPUC Data Request 32
IPUC Data Request 32
The Company's response to Production RequestNo. 8 states ttrat the L&R
includes demand response programs selected as part of the 2021 Request for
Proposals. Please respond to the following:
(a) Which selected programs are going to be implemented by the third parties?
Are these programs signed with the Company yet? Do they need Commission
approval in their states?
(b) Which selected programs are going to be implemented by the Company? Do
they need Commission approval in their states?
Response to IPUC Data Request 32
(a) The selected programs to be implemented by a third party include:
l. Commercial and industial curtailment, (all states).
2. Irrigation load control, (Oregon, Washington and Califomia).
3. Residential smart thermostats load contol, (Oregon, Washington, and
California).
4. Residential water heater direct load contol (Oregon, Washington, and
Califomia).
The commercial and industrial curtailment and irrigation load contol program
implementers have signed contracts with the Company. The residential
program implementer is expected to sign a contract with the Company before
the end of 2022. The Company intends to seek commission approval before a
program is implemented in its respective state.
(b) The WattSmart battery program was selected for all states and is currently
implemented by the Company in Utah and ldaho and is expected to be
implemented by the Company in its other states.
Recordholder:Peter Schaffer
Sponsor:Alex Osteen