20230511AVU to Staff 167-188.pdf

AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/08/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Clint Kalich REQUESTER: IPUC RESPONDER: Xin Shane, Carolyn Groome TYPE: Production Request DEPARTMENT: EIM Settlements
REQUEST NO.: Staff-167 TELEPHONE: [phone] REQUEST:
Please provide monthly costs and monthly revenues from the Energy Imbalance Market ("EIM") since Avista began participation in the EIM. RESPONSE:
Based on non-formal data responses with Staff, the Company is answering this data response in the
context of Staff’s understanding of the impact of EIM on overall power supply costs, the Settlement agreement regarding these costs, and how the costs flow through the PCA. The treatment of EIM is as follows: “Energy Imbalance Market (EIM). Currently Idaho’s share of
its incremental EIM O&M expenses are being deferred per Order No. 34606 in Case No.
AVU-E-20-01 until the expected “go live” date March 1, 2022. The Parties agree that effective
with the expected “go live” March 1, 2022 date, the Company will begin to reflect Idaho’s share of incremental EIM O&M expenses through the PCA up to Idaho’s share of EIM benefits that also will flow through the PCA. Any incremental EIM O&M expenses exceeding EIM benefits would
continue to be deferred for review and determination of recovery in a future
proceeding.”(emphasis added). Accordingly, Table No. 1 below lists the O & M expenses that are allowed to flow through the PCA per month as they do not exceed the benefits resulting from participation in the EIM market.
Table No. 2 contains a listing of the theoretical EIM Benefit results based on preliminary estimates. The Company has not finalized its benefit calculation and is currently evaluating the need to engage a consultant. The consultant would provide an independent evaluation of the Company’s proposed modifications from CAISO’s benefit calculation which more accurately represent Avista Utilities’ benefit of participation in the EIM. Note that in no instance has the
O&M expense exceeded the preliminary benefit estimate. In the 2021 PCA filing, the Company was required to file a Compliance filing no later than 30 days after approval, describing the most current benefit calculation. This was filed in Case Number AVU-E-22-11.
Table No. 3 provides the net settlement revenue (447.740) and net settlement expense (555.740)
resulting from participation in the EIM.
RECEIVED
2023 May 11, 5:57PM
IDAHO PUBLIC
UTILITIES COMMISSION

Table No. 1 O & M Expense

Year Month EIM Incremental O&M
Table No. 2 Preliminary Benefit Calculation

Year Month Preliminary Benefit Estimate
2022 March $ 1,804,150
2022 April $ 1,934,303
2022 May $ 1,421,074
2022 June $ 1,155,229
2022 July $ 745,971
2022 August $ 2,255,096
2022 September $ 3,799,470
2022 October $ 1,422,529
2022 November $ 2,228,826
2022 December $ 5,075,308
2023 January $ 2,396,977
2023 February $ 1,447,202
Table No. 3 Net Revenue and Sales

Period Account Account Description PTD $Period Account Account Description PTD $
Mar-22 447740 SALE FOR RESALE - EIM (1,676,296.68) Mar-22 555740 PURCHASED POWER - EIM -
Apr-22 447740 SALE FOR RESALE - EIM (1,519,257.32) Apr-22 555740 PURCHASED POWER - EIM 480.93
May-22 447740 SALE FOR RESALE - EIM (906,081.02) May-22 555740 PURCHASED POWER - EIM 567,778.92
Jun-22 447740 SALE FOR RESALE - EIM (1,454,401.53) Jun-22 555740 PURCHASED POWER - EIM 265,320.38
Jul-22 447740 SALE FOR RESALE - EIM (1,115,537.12) Jul-22 555740 PURCHASED POWER - EIM 97,410.60
Aug-22 447740 SALE FOR RESALE - EIM (84,192.21) Aug-22 555740 PURCHASED POWER - EIM 2,851,037.55
Sep-22 447740 SALE FOR RESALE - EIM (1,583,408.51) Sep-22 555740 PURCHASED POWER - EIM 1,450,585.55
Oct-22 447740 SALE FOR RESALE - EIM (667,012.43) Oct-22 555740 PURCHASED POWER - EIM 1,065,753.07
Nov-22 447740 SALE FOR RESALE - EIM (1,487,144.87) Nov-22 555740 PURCHASED POWER - EIM 61,284.32
Dec-22 447740 SALE FOR RESALE - EIM (1,302,373.00) Dec-22 555740 PURCHASED POWER - EIM 2,396,554.59
Jan-23 447740 SALE FOR RESALE - EIM (1,449,797.52) Jan-23 555740 PURCHASED POWER - EIM 6,988,711.99
Feb-23 447740 SALE FOR RESALE - EIM (1,525,009.83) Feb-23 555740 PURCHASED POWER - EIM (113,855.44)
Mar-23 447740 SALE FOR RESALE - EIM (1,531,088.04) Mar-23 555740 PURCHASED POWER - EIM 1,463,725.99
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/08/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Clint Kalich REQUESTER: IPUC RESPONDER: Lori Hermanson TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-168 TELEPHONE: [phone] REQUEST:
Page 11 of Mr. Kalich's Testimony stated "CCA [(' Climate Commitment Act' )] carbon allowance compliance is therefore modeled in Aurora such that each thermal plant must
overcome in its dispatch the Idaho share of the assumed carbon allowance price, or about $23.87 per metric ton." However, in discussions with Mr. Kalich , the only plant that included an allowance price in the Aurora dispatch was Boulder Park. Please reconcile these two statements and confirm that only Idaho's share of the allowance cost was included in the Aurora dispatch.
RESPONSE:
This statement was in error. Power cost modeling included CCA costs for all thermal plants; however, only Boulder Park was included explicitly in Aurora. The CCA became effective January 1, 2023, with little notice and not much clarity regarding the rules. Utilities have been reactive, attempting to obtain clarity from Ecology and proposing possible solutions that would be more beneficial for non-Washington customers. In preparation for this rate filing, Avista modeled
several different scenarios relative to CCA as more information became available. Ultimately, what was modeled was the CCA price on Boulder, the only Washington thermal plant that generates in this case that exceeded the 25,000 metric ton threshold. The CCA costs included in this case were calculated outside of Aurora using the emissions output from the rate case dispatch
and was included in the exhibit in sheet ‘Confidential Idaho CCA Costs’.
Boulder was unique in modeling because all generation is located inside Washington State and subject to CCA regulation no matter its ultimate use for serving load or sale to the market. Remaining regulated plants are all located outside of Washington State and incur CCA costs only
when power is sold at the Mid-Columbia marketplace. Because the Aurora model structure didn’t
allow tracking of outside-Washington plant allowance costs only on surplus sales from those plants, calculating the costs after the fact and outside Aurora was necessary. To account for non-Boulder costs, market sales in each hour were attributed an allowance cost using the rule-mandated Ecology “non-specified” allowance rate of 0.437 tonnes per MWh and the
referenced $23.87 price was used in the proforma.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/11/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Scott Kinney REQUESTER: IPUC RESPONDER: Ian McLelland TYPE: Production Request DEPARTMENT: Accounting
REQUEST NO.: Staff-169 TELEPHONE: [phone] REQUEST:
How does the Company plan to track the actual expenses of CCA allowances for Idaho in the
Power Cost Adjustment ("PCA"). Please address each of the following considerations in your explanation:
a. The CCA allowances can be obtained from different sources with different prices, such as auctions, bilateral, electronic exchange trading, and reserve accounts;
b. The CCA only requires a minimum of 30% of allowances to be retired in the year that
emissions occur with any balance due at the end of 2023-2026 Compliance Period;
c. According to Revised Code of Washington ("RCW") 70A.65.120(3), "During the first compliance period, allowances allocated at no cost to consumer-owned and investor-owned electric utilities may be consigned to auction for the benefit of ratepayers,
deposited for compliance, or a combination of both"; and
d. Avista can bank allowances for future uses.
RESPONSE:
a. For all off-system surplus electric sales that occur at the Mid-Columbia (Mid-C) trading hub, these sales are allocated between Washington and Idaho electric operations based on the approved production/transmission ratio (P/T Ratio). The current ratio in authorized power supply costs that is used to split the surplus sales and related system costs is approximately 65% Washington and
35% Idaho. For each sale that occurs at the Mid-C and is served by an emitting resource, Avista
incurs a carbon emission obligation, of which approximately 35% is allocated to Idaho along with the revenue from the sale. In addition to the carbon obligation for off-system surplus sales, Avista also incurs a carbon emission obligation for Washington-sited generation that is used to serve retail load (Boulder Park). The carbon emission obligation for Boulder Park is allocated between
Washington and Idaho using the P/T Ratio. At the time an off-system sale occurs at the Mid-C or Avista generates from Boulder Park to serve retail load, a carbon emission obligation has been incurred and expense must be recognized, regardless if Avista has purchased a carbon allowance at that time or not. At the time of the
off-system sale or generation, Avista will recognize carbon emission expense based on the number of emission allowances it must purchase to satisfy 100% of its Idaho emission obligation (see below for discussion around price changes and no cost allowances). If Avista has already purchased sufficient emission allowances, the weighted average price of allowances purchased will be the unit price used to calculate emission expense. If Avista does not have sufficient
allowances, any additional allowances that must be purchased above what it currently holds will be priced at the then current market price of emission allowances at the end of the month as the unit
price. Avista is proposing to include the monthly emission expense that is calculated using the above formulas in its monthly PCA calculation.

To satisfy the emission obligation that is incurred and calculated on a monthly basis, Avista must acquire carbon emission allowances, generally from the quarterly Washington State Department of Ecology (Ecology) auctions, but they may also be acquired bilaterally from third parties or through electronic exchange trading. Avista will strive to acquire the allowances at the best
possible price from these sources and all allowances acquired will be held in an inventory account at their weighted average cost. At the end of each month, the life-to-date emission expense and emission obligation will be a combination of actual carbon allowances purchased and an accrual for the carbon allowances that must be purchased in the future to satisfy the remainder of the obligation.
Avista is also pursuing additional methods to reduce costs for Idaho customers. Avista and other regional market participants are actively engaged in conversations with Ecology to obtain clarification on two key approaches potentially providing a pathway to significantly reduce CCA
compliance costs for surplus sales. These methods center around: (1) wheel through transactions
that don’t result in energy delivery in the State of Washington, and (2) a resource netting calculation based on a common practice to offset purchases and sales made at the Mid-C. The results of these efforts, if successful, may substantially reduce the carbon obligation allocated to Idaho customers.

b. Avista will not relieve the emission obligation until it has retired the carbon allowances in the Washington Compliance Instrument Tracking System Services registry, even if it has already purchased the necessary carbon allowances. Compliance periods are 4-year periods and each November 1st companies must retire at least 30% of their prior year emission requirements and at
the end of the 4-year compliance period, the remaining emission allowances must be retired. For example, in the first compliance period (2023-2026) the compliance schedule looks like this: Nov. 1, 2024: 30% of 2023 emissions
Nov. 1, 2025: 30% of 2024 emissions
Nov. 1, 2026: 30% of 2025 emissions Nov. 1, 2027: 30% of 2026 emissions, plus the remaining 70% of all 2023-2026 emissions Companies can choose to retire more than 30% of their obligation each year; however, 30% is the
minimum. Even though all the allowances may not be retired in a given year, 100% of the anticipated expense will be recognized annually such that revenues and costs are recognized in the same period. In the event the actual cost of carbon allowances differs from the amount of emission expense recognized to-date, a true-up will be recorded in the period the actual amount is known. This true-up could be an increase or decrease to emission expense depending on the cost of carbon
allowances and the amount originally estimated. Any true-up to expense will be included in the PCA. c. Avista does not receive any no cost allowances related to its Idaho electric operations. The only allowances that Avista receives at no cost for electric operations are related to its Washington
operations and that is because Washington electric emissions are governed by the Clean Energy Transformation Act rather than the CCA. The no cost allowances that are provided for Washington electric operations are only meant to satisfy the Washington portion of the emission obligation and Avista does not expect to receive no cost allowances above its Washington emission obligation. As
such, it does not expect to sell the no cost allowances in Ecology auctions, and it will not have any no cost allowances that may be sold for the benefit of Idaho customers.

As it relates to Idaho electric operations, since Avista must purchase allowances to meet its entire Idaho emission obligation, if Avista determines that it has excess carbon allowances that are not necessary for CCA compliance, it can sell these allowances via the Ecology auctions, bilaterally or through an exchange. In the event Avista does sell excess allowances that it has previously
purchased, the net difference between the original cost and sales price from these sales will be included in the PCA. d. Banking allowances will only occur between the period the allowances are acquired and the period they are retired for compliance. They will be held in inventory during this period and be
used to calculate the weighted average cost of allowances which is the basis for the unit price of the monthly emission expense.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/08/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Clint Kalich REQUESTER: IPUC RESPONDER: Lori Hermanson TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-170 TELEPHONE: [phone] REQUEST:
According to RCW 70A.65.120(3), "During the first compliance period, allowances allocated at no cost to consumer-owned and investor-owned electric utilities may be consigned to auction for the benefit of ratepayers, deposited for compliance, or a combination of both." Please explain the following.
a. Do "ratepayers" include all Avista ratepayers (Idaho and Washington) or
only Washington ratepayers?
b. Please define the "first compliance period".
c. Will free allowances occur in subsequent compliance periods?
RESPONSE: a) Only Washington ratepayers benefit from the no-cost allowances. b) The first compliance period is 2023-2026. c) Yes.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/08/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Clint Kalich REQUESTER: IPUC RESPONDER: Lori Hermanson TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-171 TELEPHONE: [phone] REQUEST:
Please explain the role of e-tags in tracking actual expenses for CCA allowances. RESPONSE:
CCA allowances are required for electricity imported into Washington State. E-tags are relied
upon to define the source and ownership path of the imported power, defining for each transaction whether an allowance is required. The “first jurisdictional deliverer,” the entity on the e-tag bringing the power into Washington State is responsible for any emissions associated with that import. They also define where a transaction is specified (i.e. from a clean renewable source) or
unspecified in that the source is unknown.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/08/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Clint Kalich REQUESTER: IPUC RESPONDER: Lori Hermanson TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-172 TELEPHONE: [phone] REQUEST:
The first quarterly auction was held on February 28, 2023. What was the clearing price in the auction? RESPONSE: The auction cleared at $48.50 per allowance of one ton of carbon dioxide equivalent.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/08/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Clint Kalich REQUESTER: IPUC RESPONDER: Lori Hermanson TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-173 TELEPHONE: [phone] REQUEST:
Please provide the emission factor adopted by the Washington Department of Ecology. Please explain how it is calculated and why the emission factor is appropriate for the unspecified energy under the Washington CCA. RESPONSE: The emission factor for unspecified imports Ecology is 0.437 tonnes per MWh. The factor is stated in Ecology’s rule. Ecology, to our understanding, has not documented where this value comes
from. In our own research we believe we have confirmed the source of the factor based on California code, as found in the following footnote in a California DWR document: 5 California Code of Regulations, title 17 division 3, chapter 1, subchapter 10, section 95111 identifies 0.428 mtCO 2e/MWh of electricity as the appropriate default emissions factor for
accounting for power for which the source is unspecified or unknown. DWR has added a 2% transmission loss factor to arrive at a total default emissions factor for unspecified power of
0.437 mtCO2e/MWh. The methodology for calculating this number has also been used by
CARB to calculate this value for all years 1990-2009. In estimates of historical emissions for years 1990-2009, DWR has used the specific emissions rate for that year in its calculations.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/08/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Clint Kalich REQUESTER: IPUC RESPONDER: Lori Hermanson TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-174 TELEPHONE: [phone] REQUEST: Please update Table No. 2 - Monthly Forward Prices at Key Trading Hubs contained in Mr.
Kalich's Direct Testimony based on the latest one-month average of Intercontinental Exchange ("ICE") prices. RESPONSE:

The following prices are updated, reflecting the period March 22, 2023 – April 20, 2023.
Period AECO Malin Mid-C LLH Mid-C HLH AECO Malin Mid-C LLH Mid-C HLH
1.624 3.216 85.78 179.48 2.335 3.567 74.30 155.49
1.821 3.284 70.21 79.31 2.504 3.453 55.00 74.12
2.337 4.823 78.55 90.72 3.059 5.598 70.61 90.50
2.661 7.296 99.53 128.82 3.344 6.850 104.18 128.81
2.741 7.400 102.36 125.39 3.445 7.022 95.52 112.91
2.724 7.002 88.60 104.17 3.430 6.806 83.30 96.97
2.486 4.904 52.98 63.02 3.164 5.381 69.21 79.94
2.278 3.033 53.37 58.90 2.888 3.569 49.59 55.76
2.142 2.930 41.13 51.48 2.812 3.487 43.73 53.18
2.182 3.115 41.40 55.01 2.877 3.696 43.25 54.80
2.255 3.592 73.72 164.40 2.958 4.038 85.00 164.95
2.272 3.638 105.97 208.75 2.982 4.078 97.89 188.53

AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/11/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Clint Kalich REQUESTER: IPUC RESPONDER: Lori Hermanson TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-175 TELEPHONE: [phone] REQUEST: Please re-run the Aurora model using (1) the latest one-month natural gas forwards prices and
electric forwards prices provided in the previous request, and (2) by including Rattlesnake Flat and Palouse Wind in the Aurora model for dispatch. Please update Confidential Exhibit No. 7 (based on the re-run) in electronic format with all formula enabled, with the following additional information:
a. A breakdown of Columbia Basin Hydro ("CBH") costs by project;
b. A breakdown of CBH transmission costs by project; and c. A breakdown of Chelan PUD costs between the existing contract and the newly signed contract.
RESPONSE:
Please see Avista's response 175C, which contain TRADE SECRET, PROPRIETARY or CONFIDENTIAL information and are separately filed under IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code.
Please see Staff_PR_175C Confidential Attachment A which includes the exhibit as filed adjusted
for updated latest one-month forwards through 4/20/2023 and the addition of Rattlesnake Flat and Palouse wind projects. a) Please see Staff_PR_175C Confidential Attachment A line items 7-10 in sheets ‘Schedule 2 RY1’ and ‘Schedule 2 RY2’ for the breakdown of CBH costs by projects. This had no
effect in RY1 and a small effect (due to slightly different dispatch due in June due to updated forwards as requested above) in RY2 to power supply costs as it was just further break out of the Columbia Basin Hydro line item. b) Please see ‘Columbia Basin Hydro Transmission’ sheet of the ‘565 Transmission Expense’ workpaper for the CBH transmission by project. This had no net effect to power supply
costs in the exhibit as these costs were already included. c) Please see Staff_PR_175C Confidential Attachment A line items 3-4 in sheets ‘Schedule 2 RY1’ and ‘Schedule 2 RY2’ for the breakdown of the existing Chelan slice and the 2024-2033 Chelan slice. This had no net effect to power supply costs as it was just further
break out of the Chelan PUD line item.
The impact of updated forwards results in $60.008 million less net power supply costs. The impact of adding in Palouse and Rattlesnake is $11.865 million. The total impact of both changes is a reduction of $71.873 million.

See Staff_PR_175 Attachment B for a reconciliation of the impact to Rate Year 1 (effective 09.01.2023) and Rate Year 2 (effective 09.01.2024) over the Two-Year Rate Plan of the requested updated information including 1) updating forward prices alone, versus 2) updating forward prices
and wind projects (Rattlesnake Flats/Palouse), versus that as-filed per the Company’s direct filed
case.
Note that the impact to the Company’s case of updating forward prices (excluding wind) would reduce the Company’s net power supply expense by $20.7 million (Idaho Share) in Rate Year 1
below as-filed levels. Whereas, net power supply expense would increase $9.8 million (Idaho
Share) in Rate Year 2, above updated Rate Year 1 levels, or $5.2 million above as-filed Rate Year 2 levels of $4.6 million. The impact to the Company’s case of updating forward prices, plus including wind, would reduce
the Company’s net power supply expense by $24.8 million (Idaho Share) in Rate Year 1 below as-filed levels. Whereas, net power supply expense would increase $10.4 million (Idaho Share) in Rate Year 2, above updated Rate Year 1 levels, or $5.8 million above as-filed Rate Year 2 levels of $4.6 million. (The net difference of including wind results in an overall decrease in net power supply expense of $11.9 million in Rate Year 1, or $4.1 million Idaho share.)

Change from Filed Case:
RY1 RY2 RY1 RY2
As-Filed 179,030$ 119,023 179,030$ 107,158
Updated 119,023$ 147,321 107,158$ 137,289
(60,008)$ 28,298$ (71,873)$ 30,132$
ID Share (Reduction RY1)(20,685)$ 9,754$ (24,775)$ 10,386$
As-Filed 4,553$ As-Filed 4,553$
ID Share (increase RY2)5,202$ (increase RY2)5,834$
*PT ratio 34.47%System Idaho Share
**Difference in Rate Year 1 with wind (11,865)$ (4,090)$
Updated Fwds Updated Fwds+wind

AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/05/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Clint Kalich REQUESTER: IPUC RESPONDER: Lori Hermanson TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-176 TELEPHONE: [phone] REQUEST: Please re-run the Aurora model using (1) the latest one-month natural gas forwards prices and
electric forwards prices provided in the previous request, and (2) by including Rattlesnake Flat and Palouse Wind in the Aurora model for dispatch. Please update Confidential Exhibit No. 7 (based on the re-run) in electronic format with all formula enabled, with the following additional information:
a. A breakdown of Columbia Basin Hydro ("CBH") costs by project;
b. A breakdown of CBH transmission costs by project; and c. A breakdown of Chelan PUD costs between the existing contract and the newly signed contract.
RESPONSE:
Please see the Company’s response to Staff_PR_175.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/11/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Scott Kinney REQUESTER: IPUC RESPONDER: Ryan Finesilver TYPE: Production Request DEPARTMENT: Energy Supply
REQUEST NO.: Staff-177 TELEPHONE: [phone] REQUEST:
Please respond to the following regarding the CBH projects, which consists of seven projects: Russell D. Smith, E.B.C. 4.6, Summer Falls Development, P.E.C. 66.0 Development, Quincy Chute Development, Main Canal Development, and P.E.C. Headworks Development.
a. Please provide a copy of each contract for the seven projects; and
b. Please provide the contract price of each project with a reference to the page number in the contract where it is listed.

RESPONSE:
Please see Avista's response 177C, which contain TRADE SECRET, PROPRIETARY or CONFIDENTIAL information and are separately filed under IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code.
Please see Staff_PR_177 – Attachment A for a copy of the requested Contract. Please note the
Columbia Basin Hydro Project is one contract, comprised of multiple projects. The pricing of the contract is included as Exhibit B of this attachment.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/11/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Scott Kinney REQUESTER: IPUC RESPONDER: Ryan Finesilver TYPE: Production Request DEPARTMENT: Energy Supply
REQUEST NO.: Staff-178 TELEPHONE: [phone] REQUEST: Mr. Kalich's Direct Testimony states that the CBH was evaluated as part of Avista's 2022
Request for Proposals ("RFP") process. However, Avista's 2023 Draft Integrated Resource Plan ("IRP") states "[a]nnouncements adjacent to the 2022 All-Source RFP include the acquisition of power from Columbia Basin Hydro's irrigation hydro generation fleet. .." Please respond to the following . a. Please confirm that CBH was not a bid in the RFP but was evaluated in the
RFP with other bidding projects.
b. Mr. Kalich's Testimony states that "[a] full accounting and reporting for CBH will be sponsored in testimony in our next Idaho general rate case, once all resources procured as part of the RFP process are under contract". Is the
Company seeking a determination of prudence for any of the CBH projects in
this case? If so, please state which one(s).
c. If the Company is seeking a determination of prudence for any of the projects , please provide the Company's justification of need for each of these projects. Please provide evidence to support the justification.
d. Please provide a comparison of the contract price(s) of each CBH project
to the contract price of each selected project from the RFP on an equivalent basis.
e. Please provide the scoring matrix used to select the short list and final
selection of resources in the RFP.
RESPONSE: Please see Avista's response 178C, which contain TRADE SECRET, PROPRIETARY or CONFIDENTIAL information and are separately filed under IDAPA 31.01.01, Rule 067 and
233, and Section 9-340D, Idaho Code.
Please note that the CBH project is one purchase power agreement consisting of multiple projects. See Avista’s response to Staff_PR_177 for the contract.
a. Confirmed. CBH was not one of the proposals received as a result of the 2023 All Source
RFP. CBH had conducted their own solicitation that Avista had bid on, and so the discussions for those contracts had run separate from the All-Source RFP Process. However, the Company evaluated this project using the All-Source RFP process, to ensure it was competitive with pricing in line with all other market solicitations. When compared to all other responses to the
RFP, CBHP was within the top 3 proposals received. Had the contract been part of the RFP
process, this result would also have resulted in selection of this project. Had the project not been competitive with the other RFP projects, Avista would not have moved forward with the contract.
b. Yes, Avista is seeking a determination of prudence for this PPA. This would include the seven projects that are included in the CBH project. The final RFP Report has yet to be
completed with a concise analysis. However, given that the first pricing for the first three
projects – Russell D. Smith (6.1 MW effective 03.01.2023), EBC 4.6 (2.2 MW effective 05.01.2023) and Summer Falls (92 MW effective 01.01.2025) were included in the rate period in this case, the Company should have provided additional information in this case in order for prudence to be determined at minimum for these projects. The Company apologizes for this
oversight. Please see the response to part c for additional information. c. Avista’s 2021 Integrated Resource Plan (IRP) identified the need to procure resources to meet capacity requirements, energy needs, and renewable energy requirements. The Company provided updates to the Idaho Public Utilities Commission on several occasions to follow up
on the IRP identified needs, as well as updates throughout the process. A discussion of identified projects resulting from the IRP was virtually held with IPUC on July 11, 2022. On September 12, 2022 the Company provided an update on the RFP process to the IRP Technical Advisory Committee which Idaho PUC typically participates in. The need for resources was
discussed with Idaho Staff in a virtual meeting held on October 12, 2022. On December 12,
2022 an update was also provided on CBH including the amount of additional generation, etc. The Company’s IRP is filed on its website at myavista.com. Columbia Basin Hydro, as well as all other resources were selected according to the
Company’s need and scored according to the evaluation criteria. While the smaller projects
came online prior to the identified need, these were relatively small in nature 2.2 and 6.1, with the larger Summer Falls and Main Canal (as well as remaining others) coming on line within a reasonable timeframe of the 2026 identified needs. The RFP allowed for that type of early acquisition if it supported acquiring cost-effective resources for the 2026-2030 timeframe.
d. Columbia Basin Hydro is one contract, comprised of multiple projects. As such, there is only one price for the entire contract. In terms of financial analysis, the Company does not have a comparison of contract price for each project readily available as it is not used as a
sole factor in the financial analysis portion of the evaluation. The financial analysis is
based on the value of each project in relation to others in the bid. This value is then translated into a score which is the basis for the Customer Energy Impact component of the scoring impact. Staff_PR_178 Attachment B has this score, in comparison to all other bids in the total Evaluation Matrix. (This is titled NonRFP Proposal and is rated number 3
in this analysis.) The Company will supplement this production response with offer price
by May 16, 2023. Please also see the Company’s response to part (e) below. e. Please see Staff_PR_178C Confidential Attachment A for the evaluation methodology used in scoring each proposal. Staff_PR_178C Confidential Attachment B includes the scoring
matrix used to select resource within the 2022 All-Source RFP.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/11/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Clint Kalich REQUESTER: IPUC RESPONDER: Lori Hermanson TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-179 TELEPHONE: [phone] REQUEST: Please provide monthly flat Mid-C prices at the 10th percentile, 50th percentile, and 90th
percentile as determined in the 2021 IRP for the period from 2023 through 2045 and compare these to the contract prices for the following on an equivalent basis:
a. Each CBH project, and
b. The two newly signed Chelan contracts referenced in Mr. Kinney's Direct Testimony. RESPONSE:
Please see Avista's response 179C, which contain TRADE SECRET, PROPRIETARY or CONFIDENTIAL information and are separately filed under IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code. Please see Staff_PR_179C Confidential Attachment A - Flat Monthly Prices 2023-2045. Please
note that the 2026-2045 slice was evaluated in the same manner as the 5% fixed cost slice
described in Kinney’s testimony page 43. Regarding Columbia Basin Hydro, it assumes a 2% inflation after the initial period (please see Exhibit B of the contract for additional info). These three contracts are for energy, capacity and RECs. However, in the case of CBH the $/MWh
shown in the attachment represents only the energy portion. The two Chelan slice contracts both
state an annual amount as opposed to a $/MWh rate and capacity cost ($/kW-mo). So, for the purposes of this PR, the Company used the annual contract amount for each slice divided by Chelan’s average water estimated energy to infer a $/MWh price to compare with the 2021 Mid-C
prices.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/11/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Scott Kinney REQUESTER: IPUC RESPONDER: Ryan Finesilver TYPE: Production Request DEPARTMENT: Energy Supply
REQUEST NO.: Staff-180 TELEPHONE: [phone] REQUEST:
Mr. Kinney 's Direct Testimony states that Avista's 2020 IRP identified the need for additional renewable resources to meet clean energy goals of carbon neutrality by 2027, 100 percent clean electricity by 2045, and that the 2020 RFP was issued to meet the need. The Chelan contracts were selected in the 2020 RFP. Please explain whether the Chelan contracts were intended to meet clean
energy goals only, or energy needs and capacity needs as well. Please provide evidence to support
your answer. RESPONSE: While the 2020 RFP was primarily directed at meeting renewable requirements in Washington, the
energy provided by the Chelan PUD PPA will also satisfy customer energy and capacity
requirements in both jurisdictions as compared to other resource options. As identified within the Company’s RFP scoring summary, the Rocky Reach and Rock Island projects provide a combined 265 MW (AC) of additional capacity and 154 aMW. Among alternatives considered within the 2020 RFP, the Chelan projects were evaluated across several factors including risk management,
net price score, price risk, electric factors, environmental and community impact. Please see Table No. 7 of Mr. Kinney’s Direct Testimony for the evaluation criteria and weightings associated with evaluating these projects. The evaluation methodology has been included in Confidential Exhibit No. 6, Schedule 5C.

AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/11/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Scott Kinney REQUESTER: IPUC RESPONDER: Ryan Finesilver TYPE: Production Request DEPARTMENT: Energy Supply
REQUEST NO.: Staff-181 TELEPHONE: [phone] REQUEST:
Mr. Kinney's Testimony states that the two newly signed Chelan contracts include one with a term of January 1, 2024, through December 31, 2033, and one with a term of January 1, 2026, through December 31, 2045. Please confirm that the Company is only seeking prudence determination of the contract with a term of January 1, 2024, through December 31, 2033, in this
case. RESPONSE: The Company is not seeking prudence determination of the second contract beginning January 1,
2026 as it is outside of the scope of the Two-Year Rate Plan ending August 31, 2025. This contract will be evaluated for prudence in the Company’s next general rate case, or in the 2026 Annual PCA filing.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/08/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Clint Kalich REQUESTER: IPUC RESPONDER: Lori Hermanson TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-182 TELEPHONE: [phone] REQUEST: Please provide an Excel file that contains the following information for the Chelan
contract with a term of January 1, 2024, through December 31, 2033.
a. The expected hourly generation profile of the project for the contract term.
b. The hourly contract prices.
c. The 500 Net Present Values ("NPV") results of the following calculation: (1) Calculate the hourly differences between the project values and the market values using Hourly Difference= (Hourly Contract Price -Mid-C
Price)* Hourly Generation, where Mid-C Prices are developed from the
500 iterations of the Expected Case in Chapter 10 of the 2021 IRP, and (2) using the discount rate from the 2021 IRP to calculate the NPV of the hourly differences. (This step may use a query function similar to the method used in "Staff_PR_115C Confidential Supplemental Attachment
B - Rattlesnake Margin by Iteration.xlsx" in Case No. AVU-E-19-04).
d. The percentage of the 500 NPVs from part (c) that have values greater than 0.
e. The 500 NPV results calculated by repeating part (c) with one change to the formula :
Hourly Difference = (90%*Hourly Contract Price - Mid-C Price) *
Hourly Generation.
f. The percentage of the 500 NPVs from part (e) that have values greater than 0. RESPONSE: Please see Avista's response 182C, which contain TRADE SECRET, PROPRIETARY or CONFIDENTIAL information and are separately filed under IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code.
Please see Staff_PR_182C Confidential Attachment A. The 2024-2033 slice wasn’t modeled in the 2021 IRP. However, the contract value is estimated by combining the existing Chelan PUD 5 percent slice and the generic NW Hydro slice resource option for the 2024-2033 time
period of the contract. The resulting energy value is then lessened by the Canadian
Entitlement requirements and the contract price in shown in the attachment. It should be noted that this analysis represents the wholesale unspecified energy only and doesn’t include the REC/clean energy and capacity values, which must be considered in the valuation and
comparison to the contract price. Lastly, Aurora optimizes hydro using a load following algorithm
and may underestimate the dispatchability of the resource in markets where the wholesale market price does not correlate with load.

AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/08/2023 CASE NO: AVU-E-23-01 / AVU-G-23-01 WITNESS: Clint Kalich REQUESTER: IPUC RESPONDER: Lori Hermanson TYPE: Production Request DEPARTMENT: Energy Resources
REQUEST NO.: Staff-183 TELEPHONE: [phone] REQUEST: Please provide an excel file that contains the following information for each of the CBH
projects.
a) The expected hourly generation profile of the project for the contract
term.
b) The hourly contract prices. c) The 500 Net Present Values ("NPV") results of the following calculation: (1) Calculate the hourly differences between the project values and the market values using Hourly Difference = (Hourly
Contract Price -Mid-C Price) * Hourly Generation, where Mid-C Prices
are developed from the 500 iterations of the Expected Case in Chapter 10 of the 2021 IRP; and (2) using the discount rate from the 2021 IRP to calculate the NPV of the hourly differences. (This step may use a query function similar to the method used in "Staff_PR_l 15C
Confidential Supplemental Attachment B - Rattlesnake Margin by
lteration.xlsx" in Case No. AVU-E-19-04).
d) The percentage of the 500 NPVs from part (c) that have values greater than 0.
e) The 500 NPV results calculated by repeating part (c) with one change to
the formula: Hourly Difference = (90%*Hourly Contract Price - Mid-C Price) * Hourly
Generation.
f) The percentage of the 500 NPVs from part (e) that have values greater than 0.
RESPONSE:
Please see Staff_PR_183 Attachment A. The expected hourly generation profile of the project for
the contract term can be found on sheet ‘EnergyandPrice’ in columns E-K and the contract price in column L.
These energy value (energy shape * Mid-C price) results in sheets ‘Summer_Falls’, ‘Main_Canal’, ‘PEC_Headworks’, “Quincy_Chute’, ‘Russell_Smith’, “PEC_66’ and ‘EBC_46’were calculated within a database using the 500 stochastic hourly Mid-C prices and expected hourly generation of each project for the contract term.
It should be noted that the individual CBH project sheets represent only the wholesale unspecified energy market value and does not include the REC/clean energy and capacity value which are also components of the product. Further, contract costs do not include transmission which is shown separately in the exhibit.
CBH and other RFP submissions were not evaluated using the 2021 IRP prices but rather an
updated electric price forecast yielding higher electric wholesale prices similar to the 2023 IRP.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/11/2023 CASE NO: AVU-E-23-01/AVU-G-23-01 WITNESS: Elizabeth Andrews REQUESTER: IPUC RESPONDER: Liz Andrews TYPE: Production Request DEPARTMENT: Regulatory Affairs
REQUEST NO.: Staff – 184 TELEPHONE: [phone] REQUEST: Please provide the Idaho Jurisdictional net rate base for both electric and natural gas service
calculated as of March 31, 2023, using both the Average of Monthly Averages ("AMA") and End of Year calculations. Please provide all workpapers supporting the calculations. RESPONSE:
Please see Avista’s Results of Operations reports provided as follows:
Idaho Electric 12.2022 AMA: Staff_PR_184 Attachment A 12.2022 ID Electric AMA Idaho Electric 12.2022 EOP: Staff_PR_184 Attachment B 12.2022 ID Electric EOP Idaho Electric 03.2023 AMA: Staff_PR_184 Attachment C 03.2023 ID Electric AMA Idaho Electric 03.2023 EOP: Staff_PR_184 Attachment D 03.2023 ID Electric EOP

Idaho Natural Gas 12.2022 AMA: Staff_PR_184 Attachment E 12.2022 ID Natural Gas AMA Idaho Natural Gas 12.2022 EOP: Staff_PR_184 Attachment F 12.2022 ID Natural Gas EOP Idaho Natural Gas 03.2023 AMA: Staff_PR_184 Attachment G 03.2023 ID Natural Gas AMA Idaho Natural Gas 03.2023 EOP: Staff_PR_184 Attachment H 03.2023 ID Natural Gas EOP
Included as Staff_PR_184 Attachment I is a reconciliation showing Idaho electric and natural gas net rate base as of: 06.30.2022 AMA (Test Period as-filed), 06.30.2022 EOP, 12.31.2022 AMA, 12.31.2022 EOP, 03.31.2023 AMA, 03.31.2023 EOP, as well as the updated Rate Year 1 (effective
09.01.2023) and updated Rate Year 2 (effective 09.01.2024). An excerpt of the specific periods and
comparison is provided in Table No. 1 (Electric) and Table No. 2 (natural gas), provided below. Updated Capital additions were provided in Staff_PR_016 Supplemental 2 on April 24, 2023, including actual transfers to plant through February 28, 2023, and resulting changes flow through
Capital Adjustments 3.08 – 3.11 and 24.01 – 24.02. See Staff_PR_016 Supplemental 2 Attachment
A for the updated capital additions workpapers (referred to in the Company’s original filing as Ms. Benjamin’s workpapers titled ‘3.08-3.11 – 24.01-24.02 PF – CAPITAL ADDITIONS’). Within this attachment, the Company has updated transfers-to-plant (TTP) with actuals for July 1, 2022 through February 28, 2023 and a revised TTP forecast for all pro forma capital additions for March 1, 2023
through December 31, 2023. Pro forma capital additions (TTP) from January 1, 2024 through
August 31, 2025 remain unchanged from the Company’s direct filed case. This attachment also provides the Revised Pro Forma Capital Additions Adjustments 3.08 through 3.11 in RY1, and Pro Forma Capital Additions Adjustments 24.01 and 24.02 in RY2 reflecting the impact of the updated TTP. Please note, while the TTP for 2024 and 2025 do not change, there is a flow through impact to
RY2 from the impact of updating TTP in RY1 (2022 and 2023), as noted in adjustments 24.01 and 24.02.

Table No. 1 - Idaho Electric Rate Base: Test Period, 12.31.2022, 03.31.2023 vs Updated As-Field

(See Capital update Staff_PR_016 Supplemental 2 discussion above, and Cash Working Capital update Staff_PR_185 below.)
Idaho Electric
06.30.2022 12.31.2022 03.31.2023 06.30.2022 12.31.2022 03.31.2023
Net Plant in Service 1,798,669$ 1,872,804$ 1,898,775$ 1,856,015$ 1,931,709$ 1,945,132$
Total Accumulated Depreciation (681,259)$ (708,442)$ (718,414)$ (701,792)$ (729,923)$ (740,585)$
Net Plant 1,117,410$ 1,164,362$ 1,180,361$ 1,154,223$ 1,201,786$ 1,204,547$
Accumulated Deferred Taxes (ADFIT)(197,501)$ (199,980)$ (200,286)$ (197,035)$ (201,467)$ (201,303)$
Net Plant After ADFIT 919,909$ 964,382$ 980,075$ 957,188$ 1,000,319$ 1,003,244$
Deferred Debits and Credits (13,048)$ (7,268)$ (3,382)$ (6,723)$ 621$ 5,337$
Working Capital 26,672$ 34,755$ 42,627$ 32,101$ 65,180$ 61,193$
Total Rate Base 933,533$ 991,869$ 1,019,320$ 982,566$ 1,066,120$ 1,069,774$
Test Period
AMA EOP
Idaho Electric Rate Base As Of Adj Proposed RY1 Rate Base Proposed RY2 Rate Base
08.31.2023 EOP 08.2024 AMA Effective 09.01.2023 Effective 09.01.2024
Net Plant in Service 1,963,480$ 38,108$ 2,001,588$ 2,080,968$
Total Accumulated Depreciation (759,052)$ (22,875)$ (781,927)$ (825,628)$
Net Plant 1,204,428$ 15,233$ 1,219,661$ 1,255,340$
Accumulated Deferred Taxes (ADFIT)(199,806)$ (790)$ (200,596)$ (202,609)$
Net Plant After ADFIT (1)
Deferred Debits and Credits (13,048)$ -$ (13,048)$ (13,048)$
Working Capital (2)
Total Rate Base 1,025,424$ 14,443$ 1,039,867$ 1,073,533$
For Comparison Purposes - As-filed (updated during process of case through Discovery)

Table No. 2 - Idaho Natural Gas Rate Base: Test Period, 12.31.2022, 03.31.2023 vs As-Field (Updated)

(See Capital update Staff_PR_016 Supplemental 2 discussion above, and Cash Working Capital
update Staff_PR_185 below.) Updated Cash Working Capital (CWC) workpapers as of December 31, 2022 is provided with Avista’s response to Staff_PR_185. As can be seen from the Tables No. 1 and No. 2 above, Idaho
CWC per the Company’s Results of Operations as of the as-filed test period 12ME 06.30.2022 (AMA) totaled $26.7 million for Idaho electric and $950,000 for Idaho natural gas. Updating these amounts to reflect more current information, results in CWC per the Company’s Results of Operations as of 12ME 12.31.2022 (AMA) of $34.8 million for Idaho electric and $2.7 million for
natural gas, and as of 12ME 03.31.2023 (AMA) of $42.6 million for Idaho electric and $4.8 million
for natural gas. Increases in CWC as of 12.31.2022 and 03.31.2023 (AMA) are the result of significant collateral (special security deposits) posted by the Company over the last several months related to required futures-based swaps for power and natural gas. See “Staff_PR_185 Attachment E 12.2022 CWC” for the updated CWC proposed with this update, reflecting the CWC as of December 31, 2022, adjusted to remove amounts earning interest – resulting in updated CWC of $33.9 million
for Idaho electric and $2.5 million for Idaho natural gas. The use of December 31, 2022 provides a conservative balance over the Two-Year Rate Plan.
Idaho Natural Gas 06.30.2022 12.31.2022 03.31.2023 06.30.2022 12.31.2022 03.31.2023
Net Plant in Service 349,218$ 357,990$ 362,460$ 356,819$ 366,032$ 369,064$
Total Accumulated Depreciation (121,214)$ (125,286)$ (127,575)$ (124,891)$ (129,263)$ (131,377)$
Net Plant 228,004$ 232,704$ 234,885$ 231,928$ 236,769$ 237,687$
Accumulated Deferred Taxes (ADFIT)(35,042)$ (34,857)$ (34,614)$ (34,842)$ (33,761)$ (33,862)$
Net Plant After ADFIT 192,962$ 197,847$ 200,271$ 197,086$ 203,008$ 203,825$
Gas Inventory 6,661$ 9,010$ 9,317$ 10,185$ 9,396$ 2,261$
Deferred Debits and Credits (8,523)$ (8,258)$ (8,110)$ (8,211)$ (8,081)$ (7,656)$
Working Capital 950$ 2,671$ 4,801$ (1,622)$ 11,310$ 13,687$
Total Rate Base 192,050$ 201,270$ 206,279$ 197,438$ 215,633$ 212,117$
Test Period
AMA EOP
Rate Base As Of Adj Proposed RY1 Rate Base Proposed RY2 Rate Base
Idaho Natural Gas 08.31.2023 EOP 08.2024 AMA Effective 09.01.2023 Effective 09.01.2023
Net Plant in Service 376,188$ 6,840$ 383,028$ 395,459$
Total Accumulated Depreciation (135,319)$ (3,732)$ (139,051)$ (146,451)$
Net Plant 240,869$ 3,108$ 243,977$ 249,008$
Accumulated Deferred Taxes (ADFIT)(34,468)$ (162)$ (34,630)$ (35,024)$
Net Plant After ADFIT (1)
Gas Inventory 6,661$ -$ 6,661$ 6,661$
Deferred Debits and Credits (8,523)$ -$ (8,523)$ (8,523)$
Working Capital (2)
Total Rate Base 206,988$ 2,946$ 209,934$ 214,571$
For Comparison Purposes - As-filed (updated during process of case through Discovery)
As noted within Staff_PR_185, Staff’s requests in Staff Production Requests 185 – 188 requesting Avista to update its filed data using a Test Year of twelve-months-ending March 31, 2023 (12ME
03.31.2023) are requests to recreate, or update, Avista’s entire filed rate case. These requests are too
voluminous in nature, which would require months of work for the Company to accomplish. Furthermore, if Avista was to oblige these requests, the result would not only require this work from Avista, it would also require significant hours on the part of Staff and all intervening parties, who would need to restart their review of Avista’s revenue requirement and revenue requirement models,
including each revised restating and pro forma adjustment, cost of service study, etc., - even many of Avista’s over 275 discovery responses answered-to-date, which would require revised responses to reflect a new test period of 12ME 03.31.2023. This request is therefore not feasible, or reasonable, for all parties involved, especially given the current date of May 11, 2023, a mere three weeks from the parties agreed-to first settlement meeting (June 1, 2023), or a mere five weeks from the
Commission Staff and Intervenor written testimony deadline of June 14, 2023. Consistent with all prior general rate cases before the IPUC, and accepted by the parties over numerous past proceedings, the Company proposes to update data previously as-filed with its direct
case, updated with information available and provided to all parties during the process of the case
through discovery. For example, consistent with prior ID general rate cases, the Company has provided its up-dated capital model all capital adjustments reflecting actual transfers-to-plant through February 28, 2023, and re-forecasted transfer-to-plant through December 31, 2023, as a result of updating actual transfers-to-plant, and the corresponding impact to its Capital Adjustments
3.08 – 3.11 and 24.01 – 24.02.
For a full explanation of the unreasonableness of the request to restate Avista’s entire case using a test period of 03.31.2023, rather than updating as-filed pro forma amounts, please see Avista’s response to Staff_PR_185.

AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/11/2023 CASE NO: AVU-E-23-01/AVU-G-23-01 WITNESS: E. Andrews / K. Schultz REQUESTER: IPUC RESPONDER: Liz Andrews TYPE: Production Request DEPARTMENT: Regulatory Affairs
REQUEST NO.: Staff – 185 TELEPHONE: [phone] REQUEST: Please update the Company's Idaho electric and Idaho gas revenue requirement models using a
March 31, 2023, test year end using AMA rate base. RESPONSE: Please see Avista's response Staff_PR_185C, which contains TRADE SECRET, PROPRIETARY or CONFIDENTIAL information and exempt from public view and is
separately filed under IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code. See also Avista’s responses to Staff_PRs_184, 186, 187 and 188.
Staff’s requests in Staff Production Requests 184 – 188 requesting Avista to update its filed data
using a Test Year of twelve-months-ending March 31, 2023 (12ME 03.31.2023) are requests which would require Avista to recreate its entire filed rate case. These requests are too voluminous in nature, which would require months of work for the Company to accomplish. Furthermore, if Avista was to oblige these requests, the result would not only require this work from Avista, it would also
require significant hours on the part of Staff and all intervening parties, who would need to restart their review of Avista’s revenue requirement and revenue requirement models, including each revised restating and pro forma adjustment, cost of service study, etc., - even many of Avista’s over 275 discovery responses answered-to-date, which would require revised responses to reflect a new test period of 12ME 03.31.2023. This request is therefore not feasible, or reasonable, for all parties
involved, especially given the current date of May 11, 2023, a mere three weeks from the parties agreed-to first settlement meeting (June 1, 2023), or a mere five weeks from the Commission Staff and Intervenor written testimony deadline of June 14, 2023.1 More importantly, as described further below, the Company believes the intent of this request can be accomplished by simply updating
existing as-filed pro forma adjustments, and certain restating adjustments as necessary, to reflect all
current information available and provided in response to discovery. Below the Company outlines what updated information has already been provided or is being provided as a part of Staff PRs 184, 185, 186 and other PRs as described below.
Specific to this request (Staff 185), to update the Company's Idaho electric and natural gas revenue
requirement models using a 12ME March 31, 2023 test year end using AMA rate base, would be voluminous and an extraordinary amount of work, as it would require Avista to recreate these models, starting with actual 03.31.2023 Results of Operations, and then adjusting each restating and pro forma adjustment from this new test period – even though the Rate Periods effective September
1, 2023 and September 1, 2024 would remain unchanged. For Avista’s electric and natural gas
revenue requirement models over the Two-Year Rate Plan, there are a total of 85 restating and pro

1 This may also possibly set an undesirable precedent by this Commission to require utilities go forward to restate their entire filed cases mid-way or later through each general rate case proceeding, burdening the utility, Staff and all
intervening parties, as well as the Commission to rule on such filings.
Page 2 of 10
forma adjustments, conversion factor results, as well as the Load Change Adjustment Rate (LCAR) – incorporating a myriad of supporting workpapers and information required to produce our Idaho
electric and natural gas Pro Forma Studies (revenue requirement models).
Specific to Avista’s use of its historical test period of 12ME 06.30.2022, the Company’s filed data is based on historical information as of a point in time but is adjusted to expected costs for the rate effective periods beginning September 1, 2023 and September 1, 2024, based on consistent
methodology used in prior cases. Avista has historically used a test period providing a period of 11 months before new rates go into effect, while in this case, to provide the time necessary to complete the preparation of its case, the Company used an historical test period resulting in 14 months between test period and its requested effective date. As case complexities have continued to grow over time, requiring more time to prepare each case, especially given a Two-Year Rate Plan, the
effects of COVID-19 on personnel and working from home environment, the Company required a five (5) month process rather than a three (3) month process to prepare its case. By utilizing the 12ME June month end, the Company was able to begin its case preparation beginning in August 2022. Utilizing a September month end would not allow preparation of the case until November. In
addition, the Company believes the use of calendar quarter ends provide the best auditable results of
operations, as the use of quarter end data utilizes data that is released publicly on a quarter basis and is audited by the Company’s external Accounting and Auditing firms. Furthermore, due to the quarter results being released publicly, and audited, extra emphasis is completed quarterly to ensure the quarter and year-to-date financial results are complete, account for material changes, reflect
proper accrual accounting of costs, and provide complete financial information.
Furthermore, through the use of pro forma or restated adjustments, with the exception of the Miscellaneous O&M Adjustment2 (using an historical average of O&M costs to escalate expenses not otherwise adjusted), the Company’s adjustments are prepared reflecting consistent historical
methodologies previously supported by Staff and other intervening parties, based mainly on known and measurable data3 to reflect rate period levels. Utilizing the Company’s as-filed information, updated during the process of discovery, results in reasonable levels of pro formed costs for the rate effective periods, reflecting results that would be similar to the results had the Company utilized a
test period ending September or later, versus that used by the Company as of June 2022.
As will be shown below, had the Company updated its as-filed case utilizing a more recent historical test period (12ME 12.31.2022 or 12ME 03.30.2023), the results of many of the pro forma adjustments (and the Company’s revenue requirement) would result in a similar position over the
Two-Year Rate Plan, because the Company is adjusting its as-filed results to reflect the most current
expected or actual information available during the process of this proceeding. As shown through these updated adjustments, regardless of whether the Company uses a historical test period as of 12ME 06.30.2022 or revises its test period to 09.30.2022, 12.31.2022 or 03.31.2023,
while the adjustment amount included in the pro forma would change, the level of expense included
in the case (as updated) would not. Furthermore, in cases where possible, and as provided below, the
2 The Miscellaneous O&M Expense Adjustment 3.15 (electric) and 24.07 (natural gas), escalates certain test period
expenses not otherwise restated or pro formed, by a three-year average O&M percentage, to reflect rate period level expenses expected for this subset of costs (approximately 10% of expenses). This adjustment has not been utilized prior to this case, but has been added to reflect the extraordinary inflation driven expense experienced by the Company on this subset of expenses, which would not otherwise have been adjusted, understating Avista’s expenses during the Two-Year
Rate Plan. 3 Including consistent pro forma net power supply cost methodologies (PF Power Supply /PF Transmission revenues),
Board approved non-union and union contract labor increases (PF Labor), third-party pension and medical actuarial reports (PF Benefits), known contract changes to expense (PF IS/IT), actual transfers-to-plant through February 28, 2023
(PF Capital), to name a few.
Page 3 of 10
Company has updated its costs during the process of the case to reflect changes to certain restating and pro forma adjustments as those changes became known - in effect correcting or updating for any
changes in expenses that come to light as we get closer to the rate effective date. See Staff_PR_185
Attachment A (electric) and Staff_PR_185 Attachment B (natural gas) for the updated revenue requirement models, reflecting updated information for these certain restating and pro forma adjustments available to date.
Below the Company describes certain Restating Adjustments and Pro Forma adjustments and provide the updated costs and change in rate base and expense over the Two-Year Rate Plan. Summary Tables No. 1 and 2 at the end of this response recap the results of these updates on a revenue requirement basis and rate base by adjustment.
RESTATING ADJUSTMENTS Restate Working Capital Adj. 1.03 – Included as “Staff_PR_185 Attachment E 12.2022 CWC” is
the revised Restating Cash Working Capital (CWC) Adjustment 1.03 reflecting the CWC as of
December 31, 2022. 4 See Avista’s response to Staff_PR_184 for further information regarding changes in rate base, including CWC. As can be seen in Staff_PR_184 Attachment I, Idaho CWC per the Company’s
Results of Operations as of the as-filed test period 12ME 06.30.2022 (AMA) totaled $26.7 million
for Idaho electric and $950,000 for Idaho natural gas. Updating these amounts to reflect more current information, results in CWC per the Company’s Results of Operations as of 12ME 12.31.2022 (AMA) of $34.8 million for Idaho electric and $2.7 million for natural gas, and as of 12ME 03.31.2023 (AMA) of $42.6 million for Idaho electric and $4.8 million for natural gas.
Increases in CWC as of 12.31.2022 and 03.31.2023 (AMA) are the result of significant collateral (special security deposits) posted by the Company over the last several months related to required futures-based swaps for power and natural gas. As noted above, “Staff_PR_185 Attachment E 12.2022 CWC” provides the updated CWC proposed with this update, reflecting the CWC as of December 31, 2023, adjusted to remove amounts earning interest – resulting in updated CWC of
$33.9 million for Idaho electric and $2.5 million for Idaho natural gas. The use of December 31, 2022 (versus the higher amount as of 03.31.2023) provides a conservative balance over the Two-Year Rate Plan. As shown in Table Nos. 1 and 2 below, the increase in revenue requirement associated with updating working capital is $635,000 (electric) and $153,000 (natural gas).
Restate Incentives Adj 2.09 – Included as “Staff_PR_185 Attachment D Revised Incentive Adjustment” is the revised Restating Incentive Adjustment 2.09 reflecting the 6-year average of payouts utilizing 2017 – 2022 (versus the as-filed average of 2016 – 2021). The impact of updating the 6-year average reflects a reduction to Idaho electric and natural gas incentive expense of
$498,000 and $118,000, respectively, versus the as-filed adjustments of $494,000 and $117,000,
respectively. This results in a slight reduction in Idaho expense and revenue requirement of $4,000 electric and $1,000 natural gas.5 Restate Debt Interest Adj. 2.13 + debt interest – Included as “Staff_PR_185 Attachment C is the
revised Thies Exhibit 2, Schedule 1, reflecting an updated actual cost of debt of 4.97% (versus as-filed of 4.92%), and the impact on Rate of Return to 7.62% (versus the as-filed 7.59%). The

4 Note this update information was readily available due to the preparation of the 12.31.2022 Washington Commission Basis report filed 04.28.2023, in which Idaho information is available as a result of this work.
5 Ibid.
Page 4 of 10
updated cost of debt reflects the actual cost of debt for the April 1, 2023, issuance (versus the forecasted as-filed). The impact of updating for this actual cost of debt increases the Company’s
overall revenue requirement by $311,000 in RY1 and $11,000 in RY2 for Idaho electric. The impact
to Idaho natural gas is an increase in revenue requirement of $62,000 in RY1 and $2,000 in RY2. The increase in debt cost to the test period is reflected in Restated Debt Interest Adj. 2.13 ($75,000 for electric and $15,000 for natural gas), with the remaining reflected amongst all adjustments impacting rate base.
Other Restating Adjustments - No additional restating adjustments need revision, as the remaining restating adjustments primarily are completed to normalize costs (e.g., Regulatory Expense, Injuries and Damages, etc.) or eliminate expenses/revenues from the test period (e.g., Eliminate B&O Taxes, Eliminate Adder Schedules), and do not have a correction or update using 12ME 06.30.2022 results,
nor is it expected to materially change, if at all, the overall revenue requirement requested if the adjustments were based on 12.31.2022 or 03.31.2023 Results of Operations.
PRO FORMA ADJUSTMENTS
PF Labor Non-Executive PF Adj 3.01 - Included as “Staff_PR_185C Confidential Attachment F – 3.01 Non-Executive Labor Adj” is the updated labor expense for Non-Exec Labor Adjustment 3.01, reflecting the incremental union/non-union labor expense as result of updating labor for actual labor
expenses as of December 31, 2022, and adjusting for labor increases approved per Union contract or
Board approval in 2023 (effective 03.2023) and 2024 (effective 03.2024), and expected in 2025 (effective 03.2025). Note, as discussed in testimony, labor expense included in the Company’s as-filed case is based on actual labor expense as of 12ME 06.30.2022, plus incremental increases approved 2023-2025. This update provides the incremental increase in labor as a result of
comparing actual 12ME 06.30.2022 labor expense plus increases for 2023-2025, versus 12ME 12.31.2022 actual labor expense6 plus incremental increases for 2023-2025 – the difference in expense totaling $382,000 in RY1 for Idaho electric, and $220,000 in RY1 for Idaho natural gas. The incremental expense amount in RY2 of $13,000 (electric) and $8,000 (natural gas) is
immaterial, and therefore ignored at this time. The Company does not have a revision to the as-filed
PF Executive Adjustment 3.02. PF Benefits Adj 3.03 & 24.08 - Included as “Staff_PR_185 Attachment G 3.03 & 24.08 2022 Benefit Adj Revised” is the updated Benefit Adjustment 3.03 & 24.08, reflecting updated costs for
pension and medical expenses from that as-filed by the Company in its direct filed case. As stated in
the direct testimony of Ms. Schultz, the Company would update its Pro Forma Benefit adjustment once the third-party actuarial report was received reflecting actual information as of 12.22.2022 year-end. See “Staff_PR_185C Confidential Attachment H for the Willis Towers Watson Actuarial Valuation Report as of December 31, 2022. The result of using this updated information, reduces
over pension/medical expense approximately $5.0 million (system expense) in RY1 below 12ME
06.30.2022 test period levels, and $604,000 (system expense) below RY1 levels. The overall impact of this update reduces the Idaho electric and natural gas as-filed pro forma expense (included in the Company’s case) by an additional $1.05 million (electric) and $249,000 (natural gas) for RY1, and $412,000 (electric) and $97,000 (natural gas) for RY2. This information is usually updated to show
the most current information during the process of the case.
6 Labor expense for the period 12ME 12.31.2022 in this format was readily available as a result of 12.31.2022 Oregon
Commission Basis Report filed 4.28.2023.
Page 5 of 10
PF IS/IT Adj 3.04 - Included as “Staff_PR_185C Confidential Attachment I - ISIT PF Adj Revised” is the updated IS/IT Adjustment 3.04, including incremental ISIT labor employee
expenses, reflecting actual IS/IT expenses as of 12ME 04.30.2023 compared to the proposed RY1
pro forma level per that as-filed by the Company (using 12ME 06.22.2023 plus known pro forma increases) in its direct filed case. The Company’s direct-filed case reflected known contractual changes at the time of filing resulting in a level of expense in RY1 (09.01.2023 – 08.31.2024) known of $21,404,000 system, or a pro forma increase of $837,000 above 12ME 06.30.2022 test period
levels ($20.57 million system). As can be seen from the supporting attachment “Staff_PR_185C Confidential Attachment I - ISIT PF Adj Revised”, tab “ISIT 2 Non Labor,” the actual expense as of 12ME 04.30.2023 totals $21,431,000 (system), an overall increase at this time of $24,000 (system). In addition, the final incremental employee (see Staff_PR_185C Confidential Attachment I - ISIT PF Adj Revised”, tab “New Labor”) has been filled before year-end 2022 – reflecting that the 8
incremental employees pro formed beyond the test period were filled prior to 12.31.2022 year-end – associated with incremental TSA and security needs); there is no change in labor expense from that as-filed. The overall impact on IS/IT expense from that included by the Company in its as-filed case in RY1, is minimal at this time, of $11,000 increase for Idaho electric and $1,000 decrease for
natural gas. There is no impact on RY2, as no adjustment was proposed in RY2. At this time, the
Company is evaluating incremental known changes in contracts that may increase the known level of IS/IT expense over the Two-Year Rate Plan and will supplement this response with that information, if necessary, when available. This information is usually updated to show the most current twelve-months of expense for IS/IT expense during the process of the case.
PF Property Tax Adj 3.05 and 24.03 – Included as “Staff_PR_185 Attachment J – PF Property Tax Revised” is the updated Property Tax Adjustment 3.05 & 24.03, reflecting updated costs for property tax from that as-filed by the Company in its direct filed case. This update reflects the impact of actual invoices and lowered levy rates from that as-filed, reducing property tax expense levels for
RY1 for Idaho electric and natural gas by $1.48 million and $790,000, below as-filed levels, respectively. For RY2, Idaho electric and natural gas expense is lowered by $183,00 and $72,000, below as-filed RY2 levels, respectively. This information is usually updated to show the most current information during the process of the case. PF Insurance Adj 3.067 – Included as “Staff_PR_151C Confidential Attachment B”, is the updated PF Insurance Adjustment 3.06. As noted within this file, the overall decrease in insurance premiums decreases overall insurance expense pro formed by the Company by approximately $361,000 (system basis), decreasing insurance expenses by $39,000 for Idaho electric and $17,000 for Idaho
natural gas. There is no impact on RY2. This information is usually updated to show the most current
information during the process of the case. See also Avista’s response to Staff_PR_156C and Staff_PR_157C. This update also revises the proposed Insurance Balancing Account Baseline to the following:
Effective 9.2023 Total Insurance
ID E 4,314,600$ Proposed Baseline
ID G 697,543$ Proposed Baseline PF EDIT (RSGM) Adj 3.07 – Included as “IFG_PR_045 Attachment B” is the revised 2023 - 2025 excess deferred tax expense, updated to reflect 2022 year-end changes and the expected impact of the proposed depreciation study. The impact of this adjustment increases EDIT expense for Idaho electric and natural gas by $151,000 and 18,000, respectively. There is no impact on RY2.

7 Actual overall Insurance Expense as of 12.31.2022 totals $14.3 million (Idaho’s share of $3.7 million for electric and $618,000 for natural gas), versus the requested $16.6 million noted in the Company’s RY1 pro forma request for the
period 09.01.2023 – 8.31.2024 (Idaho’s share $4.3 million for electric and $698,000 for natural gas).
Page 6 of 10
PF Capital Additions and Depreciation Study Adjs. 3.08 – 3.11, and 24.01 – 24.02 – Included as
“Staff_PR_016 Supplemental 2 Attachment A” is the Company’s update to PF Capital Additions
and Depreciation Study Adjs. 3.08 – 3.11, and 24.01 – 24.02, reflecting actual transfers-to-plant (TTP) with actuals for July 1, 2022 through February 28, 2023 and a revised TTP forecast for all pro forma capital additions for March 1, 2023 through December 31, 2023. Pro forma capital additions (TTP) from January 1, 2024 through August 31, 2025 remain unchanged from the Company’s direct
filed case. Please note, while the TTP for 2024 and 2025 do not change, there is a flow through impact to RY2 from the impact of updating TTP in RY1 (2022 and 2023), as noted in adjustments 24.01 and 24.02. Updating capital additions and depreciation expense for actual or corrected information during the
process of the Company’s case is consistent with prior rate case proceedings. As discussed by Ms. Schultz in her direct filed testimony, overall increases in capital additions and depreciation expense is one of the largest drivers of the Company’s case above current authorized base rates pro formed in this general rate case. Reflecting updated information over the Two-Year Rate Plan for RY1 and
RY2, reflects the largest portion of the Company’s need for rate relief.
For Idaho electric, the impact of updating the capital additions workpapers related to Pro Forma Capital Additions Adjustments 3.08 through 3.11 in RY1, result in an overall reduction to net rate base of approximately $2.1 million, reduction to expense of $1.1 million, and reduction in overall
RY1 revenue requirement of $1.3 million. For RY2, updated electric Pro Forma Capital Additions
Adjustments 24.01 and 24.02, result in an overall reduction to net rate base of $1.2 million, reduction to expense of $0.7 million, and reduction in RY1 revenue requirement of $0.8 million. For the Two-Year Rate Plan, the total reduction to net rate base is $3.3 million, reduction to expense is $1.8 million, and reduction to total revenue requirement is $2.1 million. (See tab “ID-E As-Filed vs
Update”) For Idaho natural gas, the impact of updating the capital additions workpapers related to Pro Forma Capital Additions Adjustments 3.08 through 3.11 in RY1, result in an overall increase to net rate
base of approximately $1.7 million, reduction to expense of $87,000, and an increase in overall RY1
revenue requirement of $63,000. For RY2, updated electric Pro Forma Capital Additions Adjustments 24.01 and 24.02, result in an overall increase to net rate base of $33,000, increase to expense of $73,000, and increase in RY2 revenue requirement of $76,000. For the Two-Year Rate Plan, the total increase to net rate base is $1.7 million, reduction to expense is $14,000, and increase
to total revenue requirement is $140,000. (See tab “ID-G As-Filed vs Update”). PF Revenue & O&M Offsets Adj. 3.12 and 24.06 – Included as “Staff_PR_185 Attachment L Electric New Cust Revenue May 2023” and “Staff_PR_185 Attachment M Natural Gas New Cust Revenue May 2023” is the new growth revenue amounts included in updated PF Revenue & Offsets
Adjs. 3.12 & 24.06, reflecting the impact of lower expected loads in RY1 and RY2.
For electric, the result of updating load information on the PF Revenue offset in Adjs. 3.12 & 24.06, results in new customer revenue of $3.30 million in RY1 and $1.77 million in RY2, versus as-filed revenue of $3.32 million in RY1 and $1.83 million in RY2. The net impact to revenues between
updated versus as-filed, results in a reduction of revenue of $22,000 in RY 1 and $56,000 in RY2. See file Staff_PR_185 Attachment L Electric New Cust Revenue May 2023. For natural gas , the result of updating load information on the PF Revenue offset in Adjs. 3.12 &
24.06, results in new customer revenue of $1.25 million in RY1 and $773,000 in RY2, versus
as-filed revenue of $1.44 million in RY1 and $795,000 million in RY2. The net impact to revenues
Page 7 of 10
between updated versus as-filed, results in a reduction of revenue of $194,000 in RY 1 and $23,000 in RY2. See file Staff_PR_185 Attachment M Natural Gas New Cust Revenue May 2023.
PF Miscellaneous O&M Expense Adj. 3.15 and 24.07 – Included as “Staff_PR_185 Attachment K” is an update to PF Miscellaneous O&M Expense Adjustments 3.15 and 24.07, reflecting the incremental increase in the subset8 of actual expenses (not otherwise restated or pro formed through other adjustments in the Company’s case), between the 12ME 0
6.30.2022 actual as-filed expenses, versus the 12ME 12.31.2022 actual Results of Operations expenses. In addition, this adjustment reflects the incremental escalated expense as a result of reflecting the actual 3-year average 2019 – 2022 % increase in O&M expenses applied to the subset of O&M expenses.9 For this purpose, the Company has updated this adjustment reflecting the use of December 31.2022 Results of Operations (provided as Staff_PR_184 Attachment A 12.2022 ID
Electric AMA (electric) and Staff_PR_184 Attachment E 12.2022 ID Natural Gas AMA (natural gas)), reflecting only this subset of expenses updated as of 12.31.2022, plus its escalated amounts. For electric updating PF Adjustments 3.15 and 24.07 results in a total increase in expense of $5.75
million in RY1 above 12ME 06.30.2022 test period levels, and $2.4 million in RY2 above RY1
levels. Please note, of the increase of $5.7 million proposed in RY1, $1.7 million is associated with actual increase in expense from 12ME 06.30.2022 versus 12ME 12.31.2022 for this 10% subset of O&M/A&G expenses alone. The impact of updating Adjustments 3.15 and 24.07 increases the Company’s overall O&M/A&G expense by $1.5 million in RY1 and $475,000 in RY2, versus that
as-filed.
For natural gas updating PF Adjustments 3.15 and 24.07 results in a total increase in expense of $2.0 million in RY1 above 12ME 06.30.2022 test period levels, and $550,000 in RY2 above RY1 levels. Please note, of the increase of $2.0 million proposed in RY1, $1.1 million is associated with actual increase in expense from 12ME 06.30.2022 versus 12ME 12.31.2022 for this 10% subset of O&M/A&G expenses alone. The impact of updating Adjustments 3.15 and 24.07 increases the Company’s overall O&M/A&G expense by $1.1 million in RY1 and $157,000 in RY2, versus that as-filed.

PF Miscellaneous O&M Expense Adj. 3.15 and 24.07 are new adjustments in this case. The various restating and pro forma information needed to update this expense in this case was available due to pro forma information provided as noted above, as well as various information readily available because of the production of the Washington 2022 Commission Basis Report filed April 28, 2023, in
which certain Idaho (common costs) were available. PF Wildfire Plan Expenses Adj. 3.16 – Included as “Staff_PR_039 - Attachment A - Revised 1) 3.16 Wildfire Expense-2023,” is the updated PF Wildfire Plan Expense Adjustment 3.16. As discussed in Staff_PR_039, after completion of the preparation of the Company’s revenue
requirement in this proceeding, and completion of calendar year 2022 Wildfire Plan efforts, the
Wildfire Plan capital additions and O&M expenses for 2023 – 2029 were revised to reflect lessons learned in 2022. Specifically, Wildfire capital additions and O&M expenses were revised upward,
8 Reflects 10% of overall electric and 7% of overall natural gas O&M/A&G expenses not otherwise adjusted through restating or pro forma adjustments to reflect expected levels for these expenses during RY1 and RY2. Miscellaneous O&M Expense adjustments 3.15 and 24.07 attempts to capture the increases expected during the Two-Year Rate Plan
due to the significant increase in inflation experienced by the Company. 9 In the Company’s as-filed case, the Company used a 7.22% average O&M % increase over the period 2019 to expected
2022. As can be seen in Staff_PR_185 Attachment K, tab “Util IS”, actual expenses were $11.1 million (system) more than projected earlier in the year (06.30.2022) and used for the Company’s pro forma, resulting in an average % from
2019 – 2022 of 8.45%.
Page 8 of 10
impacting the Two-Year Rate Plan. Specifically, Wildfire O&M expenses were revised to $17.7 million, $16.5 million and $15.3 million respectively, for the periods 2023, 2024 and 2025. The
Company also explained it would update this information (expenses, capital additions and revenue
requirement over the Two-Year Rate Plan), during the pendency of this case. PR_Staff_039 Attachment A includes the Pro Forma Wildfire expenses expected over the Two-Year Rate Plan (electric system and Idaho), which have been slightly refined to $17.1 million, $16.1
million and $14.9 million, respectively. The updated O&M expense pro-rated in Rate Year 1 results in total O&M wildfire expense of $15.95 million system (excluding labor/benefits), and $6.7 million Idaho share. The updated Idaho Wildfire Balancing Account proposed baseline, therefore is $6,732,000. The impact of updating wildfire expenses increases overall wildfire expenses by approximately $2.096 million and increases the Company’s revenue requirement associated with
these expenses by $2.1 million. Specific to updated Wildfire capital additions, see Avista’s responses to Staff_DR_038 for actual 2022 transfers-to-plant, and Staff_DR_040 for revised monthly 2023 expected transfers-to-plant (TTP). See Staff_PR_016 Supplemental 2 Attachment A for all capital additions changes, and the impact on Adjustments 3.08 – 3.11, and 24.01 – 24.02
OTHER ITEMS OF NOTE Pro Forma Power Supply PF 3.00P and 24.00P – See Avista’s response to Staff_PR_186. With
regards to the Pro Forma Power Supply adjustments 3.00P and 24.00P, regardless of the starting
point (12ME test period 06.2022, 03.2023 or other), the results of the Pro Forma Power Supply Aurora modeling used to support these adjustments by Mr. Kalich over the Two-Year Rate Plan, everything else being equal (i.e., same input assumptions, including loads, natural gas, electricity prices, and contract information, etc.,) would result in the same pro forma level net power supply
costs as produced per the Model’s simulation, as long as the pro forma rate period remains the same (Two-Year Rate Plan rate effective period of September 1, 2023 through August 31, 2024 (RY1) and September 1, 2023 through August 31, 2024 (RY2)).
Consistent with all prior Avista general rate cases before this Commission, the Company has
provided updated net power supply information as requested by Staff in response to Staff_PR_175 provided May 11, 2023. This information provides the most current information with regards to net power supply costs for the Two-Year Rate Plan, effective RY1 (09.01.2023) and RY2 (09.01.2024), without the need to update the Company’s 12ME 06.30.2022 historical test period. As discussed in
Avista’s response to Staff_PR_175, the impact of updated forwards results in $60.0 million ($20.7
million Idaho share) less net power supply costs. Due to the size of this adjustment (reduction to Idaho electric of approximately $20.7 million) and the variability of discussions and requested information from Staff – the Company has chosen at this time to exclude this updated adjustment until further understanding of the appropriate modeling of net power supply costs. As with prior
cases, any actual differences in net power supply costs from that authorized net power supply costs
would flow through the PCA. See Staff_PR_175 Attachment B for a reconciliation of the impact to Rate Year 1 (effective 09.01.2023) and Rate Year 2 (effective 09.01.2024) over the Two-Year Rate Plan of the requested updated information including: 1) updating forward prices alone, versus 2) updating forward prices and wind projects (Rattlesnake Flats/Palouse), versus that as-filed per the
Company’s direct filed case. No changes impacting Pro Forma Transmission Revenue and Expense PF Adjustments 3.00T / 24.00T are known at this time.

Page 9 of 10
SUMMARY To summarize all restating and pro forma adjustments to date discussed above, the Company has
created Tables No. 1 (electric) and No. 2 (natural gas) reflecting the individual change in revenue
requirement and rate base, from that as filed, as well as the discovery response location of each adjustment. Table No. 1 – Updated Electric Revenue Requirement and Rate Base Recap

Please note, although the results of all updates as discussed above, support an overall increase in electric revenue requirement in RY1 of an incremental $1.3 million above the Company’s as-filed case (and $462,000 during the Two-Year Rate Plan), the Company is not requesting this revised
revenue increase in RY1, or the net total over the Two-Year Rate Plan.

Electric Revenue Requirement Recap
Revenue Requirement Rate Base
As-Filed RY1 37,462$ 1,034,938$
Incremental Cost of Debt 391$ Staff 185 Att A
1.03 Working Capital 635$ 7,044$ Staff 185 Att E
2.09 Restate Incentives (4)$ Staff 185 Att D
2.13 Restate Debt Interest (75)$ Staff 185 Att A/C
3.01 PF Labor - Non-Exec 383$ Staff 185C Att F
3.03 PF Employee Benefits (1,058)$ Staff 185 Att G
3.04 PF IS/IT Expense 11$ Staff 185C Att I3.05 PF Property Tax (1,482)$ Staff 185 Att J3.06 PF Insurance (39)$ Staff 151C 3.07 PF EDIT (RSGM)191$ IFG 045 Att B3.08 PF Capital 12.2022 EOP (1,104)$ (9,135)$ Staff 016 Sup 2
3.09 PF Capital 08.2023 EOP 487$ 10,130$ Staff 016 Sup 2
3.10 PF Depreciation Study (32)$ Staff 016 Sup 2
3.11 PF Capital 08.2024 AMA (618)$ (3,111)$ Staff 016 Sup 2
3.16 PF Wildfire Plan Expenses 2,103$ Staff 039
3.12 PF Revenue & O&M Offset 21$ Staff 185 Att L Net Changes
3.15 PF Misc. O&M Expense 1,510$ Staff 185 Att K Rev. Req. Rate Base
1,320$ 4,928$
Rate Year 1 38,782$ 1,039,866$
Total RB RY1
Incremental Revenue Requirement Rate Base
As-Filed RY2 13,150$ 1,069,797$
4,928$ See Above
Incremental Cost of Debt 13$ Staff 185 Att A
24.01 PF Capital 08.2024 EOP (127)$ (1,396)$ Staff 016 Sup 2
24.02 PF Capital 08.2025 AMA (681)$ 203$ Staff 016 Sup 2
24.03 PF Property Tax (184)$ Staff 185 Att J
24.08 PF Employee Benefits (414)$ Staff 185 Att G
24.06 PF Revenue & O&M Offset 56$ Staff 185 Att L Net Changes
24.07 PF Misc. O&M Expense 478$ Staff 185 Att K Rev. Req. Rate Base
(859)$ (1,193)$
Incremental Rate Year 2 12,291$ 1,073,532$
Total RB RY2
Rate Year 1 Update Location
Rate Year 2
Page 10 of 10
Table No. 2 – Updated Natural Gas Revenue Requirement and Rate Base Recap
Natural Gas Revenue Requirement Recap
Revenue Requirement Rate Base
As-Filed RY1 2,771$ 206,562$
Incremental Cost of Debt 78$ Staff 185 Att A
1.03 Working Capital 153$ 1,692$ Staff 185 Att E
2.09 Restate Incentives (1)$ Staff 185 Att D2.13 Restate Debt Interest (15)$ Staff 185 Att A/C3.01 PF Labor - Non-Exec 221$ Staff 185C Att F
3.03 PF Employee Benefits (250)$ Staff 185 Att G
3.04 PF IS/IT Expense (1)$ Staff 185C Att I
3.05 PF Property Tax (793)$ Staff 185 Att J
3.06 PF Insurance (15)$ Staff 151C
3.07 PF EDIT (RSGM)23$ IFG 045 Att B
3.08 PF Capital 12.2022 EOP (186)$ (1,306)$ Staff 016 Sup 23.09 PF Capital 08.2023 EOP 233$ 3,018$ Staff 016 Sup 23.10 PF Depreciation Study (86)$ Staff 016 Sup 2
3.11 PF Capital 08.2024 AMA 103$ (32)$ Staff 016 Sup 2
3.12 PF Revenue & O&M Offset 195$ Staff 185 Att M Net Changes
3.15 PF Misc. O&M Expense 1,141$ Staff 185 Att K Rev. Req. Rate Base
(538)$ 3,372$
Rate Year 1 3,569$ 209,934$
Total RB RY1
Incremental Revenue Requirement Rate Base
As-Filed RY2 120$ 211,166$
RY1 Rate Base Changes 3,372$ See Above
Incremental Cost of Debt 2$ Staff 185 Att A
24.01 PF Capital 08.2024 EOP 1$ 11$ Staff 016 Sup 2
24.02 PF Capital 08.2025 AMA 75$ 22$ Staff 016 Sup 2
24.03 PF Property Tax (72)$ Staff 185 Att J
24.08 PF Employee Benefits (98)$ Staff 185 Att G24.06 PF Revenue & O&M Offset 22$ Staff 185 Att M Net Changes
24.07 PF Misc. O&M Expense 158$ Staff 185 Att K Rev. Req. Rate Base
(92)$ 33$
Incremental Rate Year 2 207$ 214,571$
Total RB RY2
Rate Year 1 Update Location
Rate Year 2
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/11/2023 CASE NO: AVU-E-23-01/AVU-G-23-01 WITNESS: Elizabeth Andrews REQUESTER: IPUC RESPONDER: Liz Andrews TYPE: Production Request DEPARTMENT: Regulatory Affairs
REQUEST NO.: Staff – 186 TELEPHONE: [phone] REQUEST: Please provide an updated Net Power Cost using a March 31, 2023, test year end.
RESPONSE: This request to update Net Power Cost using a Test Year of twelve-months-ending March 31, 2023
(12ME 03.31.2023), would require an extraordinary amount of work to start from scratch using an updated test period for net power supply related revenues and expenses, requiring work to re-create historical normalized loads and other calculations using updated data, and the myriad of other supporting workpapers and information required to do so. In essence, this request would require the Company to re-produce the Pro Forma Power Supply Adjustments 3.00P (Rate Year 1 “RY1”) and
24.00P (Rate Year 2 “RY2”), which would then need to flow through an updated Idaho electric requirement model using a March 31, 2023 test year. Company witness Clint Kalich summarizes at page 22 of his direct testimony, the Pro Forma Power
Supply adjustments: “The pro forma power supply adjustment determines revenues and expenses
associated with dispatch of Company resources and contract rights, as determined by the [Aurora] Model’s simulation for the pro forma rate period under normal weather and median hydro generation conditions. Further adjustments are made to reflect contract changes between the historical test period and the pro forma period.” (emphasis added) At page 2, Mr. Kalich describes that the results
from the Aurora Model includes key inputs and assumptions driving power supply cost values
including loads, natural gas and electricity prices, and a comparison to current levels of authorized power supply expense, as well as an overview on contract changes since our last filing. As discussed further in Staff_PR_185, with regards to the Pro Forma Power Supply adjustments
3.00P and 24.00P, regardless of the starting point (12ME test period 06.2022, 03.2023 or other), the results of the Pro Forma Power Supply Aurora modeling used to support these adjustments by Mr. Kalich over the Two-Year Rate Plan, everything else being equal (i.e., same input assumptions, including loads, natural gas, electricity prices, and contract information, etc.,) would result in the same pro forma level net power supply costs as produced per the Model’s simulation, as long as the
pro forma rate period remains the same (Two-Year Rate Plan rate effective period of September 1, 2023 through August 31, 2024 (RY1) and September 1, 2023 through August 31, 2024 (RY2). In addition to this request to update Net Power Costs, as noted within Staff_PR_185, Staff’s requests
in Staff Production Requests 184 – 188 requesting Avista to update its filed data using a Test Year of
12ME 03.31.2023 are requests to recreate, or update, Avista’s entire filed rate case. These requests are too voluminous in nature, which would require months of work for the Company to accomplish. Furthermore, if Avista was to oblige these requests, the result would not only require this work from Avista, it would also require significant hours on the part of Staff and all intervening parties, who
would need to restart their review of Avista’s revenue requirement and revenue requirement models,
including each revised restating and pro forma adjustment, cost of service study, etc., - even many of Avista’s over 275 discovery responses answered-to-date, which would require revised responses to
reflect a new test period of 12ME 03.31.2023. This request is therefore not feasible, or reasonable, for all parties involved, especially given the current date of May 11, 2023, a mere three weeks from
the parties agreed-to first settlement meeting (June 1, 2023), or a mere five weeks from the
Commission Staff and Intervenor written testimony deadline of June 14, 2023. For a full explanation of the unreasonableness of this request, please see Avista’s response to Staff_PR_185.
Please note, consistent with all prior Avista general rate cases before this Commission, the Company has provided updated information as requested by Staff in response to Staff data requests 175 provided May 11, 2023. This information would provide the most current information with regards to net power supply costs for the Two-Year Rate Plan, effective RY1 (09.01.2023) and RY2
(09.01.2024), without the need to update the Company’s 12ME 06.30.2022 historical test period. As discussed in Avista’s response to Staff_PR_175, the impact of updated forwards results in $60.0 million ($20.7 million Idaho share) less net power supply costs. The impact of adding in Palouse and
Rattlesnake is $11.9 million ($4.1 million). The total impact of both changes is a reduction of $71.9
million. See Staff_PR_175 Attachment B for a reconciliation of the impact to Rate Year 1 (effective 09.01.2023) and Rate Year 2 (effective 09.01.2024) over the Two-Year Rate Plan of the requested
updated information including 1) updating forward prices alone, versus 2) updating forward prices
and wind projects (Rattlesnake Flats/Palouse), versus that as-filed per the Company’s direct filed case. Note that the impact to the Company’s case of updating forward prices (excluding wind) would
reduce the Company’s net power supply expense by $20.7 million (Idaho Share) in Rate Year 1 below as-filed levels. Whereas, net power supply expense would increase $9.8 million (Idaho Share) in Rate Year 2, above updated Rate Year 1 levels, or $5.2 million above as-filed Rate Year 2 levels of $4.6 million.

The impact to the Company’s case of updating forward prices, plus including wind, would reduce the Company’s net power supply expense by $24.8 million (Idaho Share) in Rate Year 1 below as-filed levels. Whereas, net power supply expense would increase $10.4 million (Idaho Share) in Rate Year 2, above updated Rate Year 1 levels, or $5.8 million above as-filed Rate Year 2 levels of
$4.6 million. (The net difference of including wind results in an overall decrease in net power
supply expense of $11.9 million in Rate Year 1, or $4.1 million Idaho share.)
Change from Filed Case:
RY1 RY2 RY1 RY2
As-Filed 179,030$ 119,023 179,030$ 107,158
Updated 119,023$ 147,321 107,158$ 137,289
(60,008)$ 28,298$ (71,873)$ 30,132$
ID Share (Reduction RY1)(20,685)$ 9,754$ (24,775)$ 10,386$
As-Filed 4,553$ As-Filed 4,553$
ID Share (increase RY2)5,202$ (increase RY2)5,834$
*PT ratio 34.47%System Idaho Share
**Difference in Rate Year 1 with wind (11,865)$ (4,090)$
Updated Fwds Updated Fwds+wind

AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/11/2023 CASE NO: AVU-E-23-01/AVU-G-23-01 WITNESS: Elizabeth Andrews REQUESTER: IPUC RESPONDER: Liz Andrews TYPE: Production Request DEPARTMENT: Regulatory Affairs
REQUEST NO.: Staff – 187 TELEPHONE: [phone] REQUEST: Please provide updated weather and revenue normalization calculations using a March 31, 2023, test
year end. RESPONSE: This request to update weather and revenue normalization calculations using a March 31, 2023, test
year end would require an extraordinary amount of work to start from scratch with its weather and
revenue normalization calculations using updated data, updated loads, and the myriad of other supporting workpapers and information required to do so, in essence to re-produce the Revenue Adjustment 2.07, and then feed this information into updated Idaho electric and natural gas revenue requirement models using a March 31, 2023 test year.

As noted within Staff_PR_185, Staff’s requests in Staff Production Requests 184 – 188 requesting Avista to update its filed data using a Test Year of twelve-months-ending March 31, 2023 (12ME 03.31.2023) are requests to recreate, or update, Avista’s entire filed rate case. These requests are too voluminous in nature, which would require months of work for the Company to accomplish.
Furthermore, if Avista was to oblige these requests, the result would not only require this work from Avista, it would also require significant hours on the part of Staff and all intervening parties, who would need to restart their review of Avista’s revenue requirement and revenue requirement models, including each revised restating and pro forma adjustment, cost of service study, etc., - even many of
Avista’s over 275 discovery responses answered-to-date, which would require revised responses to
reflect a new test period of 12ME 03.31.2023. This request is therefore not feasible, or reasonable, for all parties involved, especially given the current date of May 11, 2023, a mere three weeks from the parties agreed-to first settlement meeting (June 1, 2023), or a mere five weeks from the Commission Staff and Intervenor written testimony deadline of June 14, 2023.

For a full explanation of the unreasonableness of this request, please see Avista’s response to Staff_PR_185.
AVISTA CORPORATION RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: IDAHO DATE PREPARED: 05/11/2023 CASE NO: AVU-E-23-01/AVU-G-23-01 WITNESS: Elizabeth Andrews REQUESTER: IPUC RESPONDER: Liz Andrews TYPE: Production Request DEPARTMENT: Regulatory Affairs
REQUEST NO.: Staff – 188 TELEPHONE: [phone] REQUEST: Please provide an updated Cost of Service Model using a March 31, 2023 test year end.
RESPONSE:
The Company cannot produce updated Idaho electric and natural gas Cost of Service Models using
March 31, 2023 test year, without the creation of updated Idaho electric and natural gas revenue requirement models using a March 31, 2023 test year. As noted within Staff_PR_185, Staff’s requests in Staff Production Requests 184 – 188 requesting
Avista to update its filed data using a Test Year of twelve-months-ending March 31, 2023 (12ME 03.31.2023) are requests to recreate, or update, Avista’s entire filed rate case. These requests are too voluminous in nature, which would require months of work for the Company to accomplish. Furthermore, if Avista was to oblige these requests, the result would not only require this work from Avista, it would also require significant hours on the part of Staff and all intervening parties, who
would need to restart their review of Avista’s revenue requirement and revenue requirement models, including each revised restating and pro forma adjustment, cost of service study, etc., - even many of Avista’s over 275 discovery responses answered-to-date, which would require revised responses to reflect a new test period of 12ME 03.31.2023. This request is therefore not feasible, or reasonable, for all parties involved, especially given the current date of May 11, 2023, a mere three weeks from
the parties agreed-to first settlement meeting (June 1, 2023), or a mere five weeks from the Commission Staff and Intervenor written testimony deadline of June 14, 2023. For a full explanation of the unreasonableness of this request, please see Avista’s response to
Staff_PR_185.