20240911Staff Comments.pdf

RECEIVED
Wednesday, September 11, 2024 9.28.51 AM
IDAHO PUBLIC
UTILITIES COMMISSION
CHRIS BURDIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 9810
Street Address for Express Mail:
11331 W CHINDEN BLVD, BLDG 8, SUITE 201-A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE POWER COST )
ADJUSTMENT (PCA)ANNUAL RATE ) CASE NO. AVU-E-24-07
ADJUSTMENT FILING OF AVISTA )
CORPORATION )
COMMENTS OF THE
COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission, by and
through its Attorney of record, Chris Burdin, Deputy Attorney General, submits the following
comments.
BACKGROUND
On July 31, 2024, Avista Corporation, doing business as Avista Utilities ("Company"),
filed its annual Power Cost Adjustment ("PCA") application("Application"). The Company
requests that the Commission issue an order approving the level of power costs deferred in the
rebate direction for the period of July 1, 2023, through June 30, 2024, and approving a PCA
rebate rate of 0.2050 per kilowatt-hour to be effective October 1, 2024. Application at 1.
The PCA is a mechanism used to track changes in revenues and costs associated with
variations in hydroelectric generation, secondary prices, thermal fuel costs, and changes in power
contract revenues and expenses. The present PCA surcharge is a rate of 0.4990 per kilowatt-
STAFF COMMENTS 1 SEPTEMBER 11, 2023

hour, based on an overall surcharge of approximately $15.7 million, which was approved by the
Commission in Order No. 35937, dated September 28, 2023, and is effective October 1, 2023,
through September 30, 2024.
The Company represents that the proposed PCA rate adjustment of 0.2050 per kilowatt-
hour would rebate approximately $6.6 million to customers effective October 1, 2024. Id. at 3.
The Company states that the rebate is primarily associated with power supply costs that were
lower than those included in retail rates, due to lower wholesale electric and natural gas prices,
and that the net effect of the expiring surcharge, and the proposed rebate, is an overall decrease
in revenue of approximately 7.4 percent, or$22.8 million. Id.
STAFF REVIEW
Staff reviewed the Company's Application, testimonies of Company witnesses Kevin
Holland and Kaylene Schultz, and additional information provided in responses to production
requests. Staff also reviewed Energy Imbalance Market(`BIM")benefits, Washington Climate
Commitment Act("CCA") allowance costs, Palouse Wind and Rattlesnake Flat Wind stipulated
adjustments from the previous general rate case, Clearwater-related items, and Chelan Hydro and
Columbia Basin Hydro ("CBH") stipulated adjustments from the previous general rate case.
Based on its review, Staff believes the PCA is generally prudent and recommends
approval of the Company's Application updating Schedule 66, Temporary Power Cost
Adjustment—Idaho with Staff s adjustments as discussed in further detail below.
Review of PCA Deferral
Staff performed an audit of the Company's Net Power Costs ("NPC")by reviewing the
Company's natural gas purchases, market purchases, transmission revenue and expenses, and
other deferral items. Based on review of the transactions, Staff believes the various power cost
transactions are reasonable, prudently incurred, and comply with previous Commission orders
and the Company's risk management policies, except for two recommended adjustments to
actual NPC for Chelan Hydro and Clearwater contracts.
Under Avista's PCA mechanism, the Company and its ratepayers share the difference
between actual NPC and the NPC embedded in base rates. The sharing percentage is 90% for
ratepayers and 10% for the Company. When actual costs are higher than those recovered
STAFF COMMENTS 2 SEPTEMBER 11, 2023

through base rates, Idaho customers pay 90% of the difference. When actual costs are lower,
customers are credited 90% of the difference allowing the Company to keep 10%. This provides
an incentive for the Company to lower NPC by operating its system more efficiently.
Staff s recommended deferral balance including a Clearwater adjustment is a negative
$6,991,612 as shown on Table No. 1 below. An adjustment for Chelan Hydro was subtracted
from the balancing account, resulting in a projected ending balance through September 2024 of
negative $7,944,802.
Table No. 1: Summary of Power Supply and Deferrals for Current PCA Year -Idaho
Idaho Power Cost Deferral Amount
LCAI —Idaho Sales Adjustment $ (1,160,814)
Net Power Supply—Actual Minus Authorized (3,458,527)
Clearwater Adjustment (Without Sharing) (823,962)
REC2 Revenues (2,226,028)
Schedule 25P Net Cost (478,630)
EIM3 Incremental O&M 379,503
Total Cost(Subject to Company Sharing) $ (7,768,458)
Sharing Percentage over Authorized 90%
Total Idaho Deferral Amount(W/out Clearwater Adjustment) $ (6,991,612)
Balancing Account
Beginning Balance as of July 2023 16,653,537
Incremental Deferral (6,991,612)
Amortizations (12,354,708)
Projected Amortization July 2024 through September 2024 (3,839,850)
Chelan Adjustment (581,315)
RPS4 Compliance (REC Retirement Benefit) Adjustment (1,058,163)
Interests 227,309
Projected Ending Balance through September 2024 (7,944,802)
1 Load Change Adjustment
2 Renewable Energy Credit
'Energy Imbalance Market
4 Renewable Portfolio Standards—Washington WA I-937
5 Calculated using the Authorized Customer Deposit Rate of 2%over a 6-month period and 5%over a 6-month period.
STAFF COMMENTS 3 SEPTEMBER 11, 2023

Load Change Adjustment("LCA")—Idaho Sales Adjustment
The Idaho LCA captures the over-or under-recovery of net power supply expense through
base rates attributable to the difference between actual sales and sales used to set base rates. The
Company used the correct Load Change Adjustment Rate ("LCAR") of$25.43/Megawatt-hour
("MWh") for the months of July and August 2023, and an LCAR of$24.41/MWh for the months
of September 2023 to June 2024.
Net Power Supply Deferral—Actual Minus Authorized
The net power supply deferral captures the difference between actual NPC and the NPC
embedded in base rates for the twelve months ending June 30, 2024. The deferral includes the
following Federal Energy Regulatory Commission ("FERC")Uniform System of Accounts: 555
—Purchased Power, 447— Sale for Resale, 501 —Thermal Fuel, 547—CT Fuel, 456—
Transmission Revenue, 565 —Transmission Expense, 557—Resource Optimization, 537—MT
Invasive Species Expense, and 557—Expense Broker Fees.
Purchased power costs reflect most of the Idaho jurisdictional share of the difference in
costs the Company incurred for power purchases during the deferral period and the authorized
power costs included in base rates. During the Review Period, actual NPC was lower than the
authorized NPC for the Idaho jurisdiction. The Company's proposed Idaho's jurisdictional share
of the base-to-actual difference is $3,458,527. However, the Company included Staff s
Clearwater Adjustment, as described below, resulting in a base-to-actual difference of
$4,282,489. Amended Response to Production Request No. 32.
The differences in actual NPC relative to NPC embedded in base rates can be attributed
to 1) lower than forecasted streamflow which reduced hydroelectric generation from both Avista-
owned and contracted-for resources; 2) higher level of generation from Avista's natural gas-fired
generation sources; and 3) increased activity in both market purchases and market sales.
Renewable Energy Credit Revenue
The Company books Renewable Energy Credit("REC")revenue in FERC Account No.
557. Based on Order No. 33605, the Company has separately reported actual and authorized
REC revenue and expenses in its PCA filing. Idaho customers are credited $2,226,028 for REC
revenues which reduce the deferral balance.
STAFF COMMENTS 4 SEPTEMBER 11, 2023

Schedule 25P Net Cost—Idaho
In Order No. 34252, the Commission authorized a Power Purchase and Sale Agreement
between the Company and Clearwater Paper Corporation ("Clearwater"). Clearwater owns and
operates four thermal electric generating units rated at 132.2 MW. The units are cogeneration
qualifying facilities under the Public Utility Regulatory Policies Act of 1978. The agreement
allows the Company to purchase the energy and capacity from Clearwater and directly assign it
to the Idaho jurisdiction. Any monthly difference between actual Clearwater power purchase
expense and the amount embedded in the base retail rates developed in AVU-E-23-01 general
rate case, is tracked through the PCA. Parties and ratepayers benefit from the Company selling
bundled RECs under the new agreement. Bundled RECs generally command a higher price than
unbundled REC's. Idaho customers received a benefit of$478,630 from the agreement during
the PCA year which helped offset the deferral balance.
Energy Imbalance Market ("EIM')
In Order Nos. 35156 and 35543, the Commission authorized the Company to include
EIM incremental expenses in the PCA up to the benefits realized from the EIM. The Company
included$379,503 (or$341,552 after sharing) in incremental EIM operation and maintenance
("O&M") expenditures for recovery in the Idaho PCA. During this PCA period, the EIM
benefits are $18.6 million at the system level, while the EIM O&M expenses are $1.1 million at
the system level. Response to Staff Production Request No. 9. Staff believes that the Company
has complied with Order No. 35156.
Renewable Portfolio Standard (Washington.) Compliance
The $1,058,163 of REC credits were retired for the REC Retirement Benefit to meet
Washington's Renewable Portfolio Standard("RPS"). The credit is based on the Idaho
allocation of RECs that were retired to meet Washington RPS (WA I-937) that otherwise would
have been sold. The RECs used to meet Washington RPS are tracked 100% in the PCA.
CCA Allowance Costs
The Commission rejected the costs associated with the CCA in its entirety in Order No.
36015. Accordingly, the Company excluded all the CCA allowance expenses associated with
STAFF COMMENTS 5 SEPTEMBER 11, 2023

the CCA obligations incurred. Response to Staff Production Request No. 11(b). Currently, the
Company assumes that all of the CCA obligations come from Idaho's share of Boulder Park
generation, and that no CCA obligations will be incurred from off-system sales. Supplemental
Response to Staff Production Request No. 10.
Although all the CCA allowance expenses associated with the Boulder Park generation
are excluded from NPC, Staff is concerned that the Company includes Idaho's portion of CCA
allowance costs in Boulder Park's dispatch costs. Response to Staff Production Request No.
10(c). By including these allowance costs in the dispatch, the Company is likely not dispatching
lower cost Boulder Park generation(without the cost allowances) in lieu of higher cost resources,
which would result in higher NPC for Idaho customers. However, if the Company were to
remove the cost of allowances from the dispatch cost, the Company would have to incur the cost
of the allowances for the incremental generation without being able to recover the cost.
Because dispatch decisions are based on the status of the Company's resources and
circumstances at the time each dispatch decision is made, Staff believes it would be very difficult
to quantify the impact; thus, Staff is not proposing an adjustment in this case. However, Staff
recommends the Company track the cost impact of using a Boulder Park dispatch cost without
the cost of allowances over the remaining PCA year to be reported in next year's PCA filing.
Palouse Wind and Rattlesnake Flat Wind
For Palouse Wind and Rattlesnake Flat Wind, the Settlement Stipulation in Case No.
AVU-E-23-01, approved in Order No. 35909, allowed 90% of actual costs and 90% of base costs
to be included in the PCA. Staff verified that this is accurately reflected in the Company's
proposal.
Clearwater-related Items
Staff reviewed Clearwater-related items, which include the treatment of Clearwater in the
PCA, the calculation of purchased power expenses, transmission expenses, and REC revenues.
In removing actual Clearwater's expense, the Company mistakenly calculated them using the
incorrect avoided cost rates for January through June of 2024. By using the correct avoided cost
rates, this results in a reduction in actual system Purchased Power expense of$2,390,366 (Idaho
STAFF COMMENTS 6 SEPTEMBER 11, 2023

Allocation is $823,962). After applying the authorized jurisdictional allocation factor and
customer sharing, Idaho customers will see an additional rebate of$741,566.
Staff verified that purchased power expenses associated with Clearwater are removed
from both authorized expenses and actual expenses. This treatment aligns with the arrangement
under the current Clearwater contract. Staff also verified that the purchased power expenses
Avista pays Clearwater are offset by the revenues associated with the Schedule 25P Block 2
Generation Load Clearwater pays Avista.
According to Section 10(d) of the Clearwater contract, all Net Revenue from Sales of the
Product will be split between Clearwater(90%) and Avista(10%). Avista's share of both
transmission costs and REC revenue from this contractual arrangement are within the definition
of"Net Revenue from Sales of the Product." Response to Staff Production Request No. 31.
Staff verified that 10% of these two components are included in the deferral,both of which are
subject to customer sharing.
Columbia Basin Hydro ("CBH") /Chelan Hydro Purchase Power Agreements
The Settlement approved through Order No. 35909 in Case No. AVU-E-23-01, stipulated
that the cost of CBH and Chelan Hydro would be included in the PCA using the "lesser of'
market or contract cost, and to allow the Company to recover all or some of the approximately
$1.007 million in transmission cost to the extent that Market prices are higher than the cost of
CBH generation with the cost of transmission included. Staff and the Company developed a
mechanism to meet the intent of the agreement, which was subsequently provided to the Settling
Parties intervening in the case for feedback and agreement. No party provided any feedback or
disagreement with the design of the mechanism. Staff s review of the actual amounts included in
the PCA were based on the design of the agreed upon"lesser of mechanism.
Chelan Hydro
Staff reviewed the actual costs included in the PCA relative to the agreed upon
mechanism but found that the Company did not use the correct contract rate, which should have
been based on invoiced amounts and actual generation resulting in a potential $1,399,513
adjustment benefiting Idaho customers. However, after discussions with the Company, Staff
believes the mechanism may be unfairly accounting for the cost of the contract relative to the
STAFF COMMENTS 7 SEPTEMBER 11, 2023

benefits by using unit cost "lower of"monthly monthly comparisons. Staff believes that an adjustment
amount of$581,315 instead of the $1,399,513 is more reasonable for the current circumstances
in this case and that the mechanism should be re-evaluated prior to the next PCA. Therefore,
Staff recommends an adjustment of$581,315 and that the Company, Staff, and interested parties
meet after the case is closed to re-evaluate the mechanism to ensure it protects Idaho customers
while balancing benefits the contract may provide prior to filing the next PCA.
Table No. 1 illustrates alternatives for the adjustment. The first two columns show the
Mid-C market price and the contract actual amounts for January through June of 2024, when the
contract term was in force during the PCA year. The third column shows the $356,186
adjustment as originally proposed by the Company, the fourth column shows the adjustment of
$1,399,513 if done by strict adherence to the agreed upon mechanism, and for illustrative
purposes, the fifth column includes the benefits of the contract for January when Mid-C prices
were abnormally high with the resulting total net benefits across the deferral period.
Table No. 2
Column 1 Column 2 Column 3 Column 4 Column 5
"Lesser Of "Lesser Of'
Mid-C Contract AcutaI Adjustment as Adjustment per Net Benefits
Amount Filed Agreed upon
Mechanism
Jan-24 $ 7,156,142 $ 1,755,720 $ - $ - $ 5,400,422
Feb-24 $ 1,024,745 $ 1,755,720 $ (61,682) $ (730,976) $ (730,976)
Mar-24 $ 929,623 $ 1,755,720 $ (401,685) $ (826,098) $ (826,098)
Apr-24 $ 837,306 $ 1,755,720 $ (222,625) $ (918,414) $ (918,414)
May-24 $ 905,486 $ 1,755,720 $ (156,620) $ (850,235) $ (850,235)
Jun-24 $ 1,021,353 $ 1,755,720 $ (190,709) $ (734,367) $ (734,367)
YTD System Total $ 11,874,655 $ 10,534,320 $ (1,033,321) $ (4,060,090) $ 1,340,332
Idaho Share $ (356,186) $ (1,399,513) $ 462,012
Through discussions with the Company, Staff recommends an adjustment of$581,315.
Staff believes the adjustment should honor the stipulation and work done to develop the currently
agreed upon mechanism by basing an adjustment using the $1,399,513 adjustment as a starting
point. To get to a final recommended adjustment amount, the adjustment should be reduced by
the $356,186 amount the Company has already incorporated into the deferral, and Staff believes
it would be fair to further reduce it by the $462,012 net benefits that occurred over the six-month
STAFF COMMENTS 8 SEPTEMBER 11, 2023

period. Staff recommends that this adjustment only apply in this case and that the Company,
Staff, and interested parties reevaluate the mechanism prior to next year's PCA filing.
CBH
Staff verified that CBH has the correct contract price and actual generation amounts, and
that the actual cost passed into the deferral uses the lower of market or contract price per the
agreed upon mechanism.
CBH transmission expenses may be incurred to accommodate CBH hydro projects.
However, the existing CBH hydro projects have not incurred any incremental transmission costs
during the PCA deferral period. Response to Staff Production Request No. 18. Because the
existing transmission capacity can accommodate the existing CBH hydro projects, Staff believes
it is reasonable to not include CBH transmission expenses in this PCA.
Analysis of PCA Rates
Through a supplement to Staff Production Request No. 32, the Company provided new
PCA rate calculations that incorporate adjustments for Clearwater of$741,566 and for Chelan
Hydro of$581,315, which both increase the amount of the proposed rebate. Based on its review
of the PCA rate calculations, Staff verified that the result is accurate and will reasonably refund
customers for overcollection of actual NPC embedded in base rates. Using the PCA rebate rate
of 0.2460 per kilowatt-hour, residential customers using an average of 927 kilowatt-hours per
month would see their monthly bills decrease from $104.18 to $97.10, a decrease of$7.08 per
month, or 6.8%. Table No. 3 provides a summary of the PCA rate calculation to be effective
October 1, 2024, if authorized.
Table No. 3: Summary of Proposed Rebate Rate
Proposed rate
Total Amortization and Deferral Balance including interest thru 9/30/24 $ (7,945)
Conversion factor(Case No.AVU-E-23-01: Per Final Stipulation&Settlement) 0.996223
Revenue Requirement $ (7,975)
kWh's from above 3,240,155
Proposed rate: $ (0.00246)
STAFF COMMENTS 9 SEPTEMBER 11, 2023

Table No. 4 provides the percent change by rate schedule to show the impact to each
schedule. Because the PCA rate adjustments are spread on a uniform cents-per-kWh basis, the
resulting revenue percentage change varies by customer class.
Table No. 4: Percent Change of Billed Revenue by Schedule
Residential 1 1,362,736 $ 148,447 $ (10,152) -6.8%
General Service 11,12 591,380 $ 53,229 $ (4,406) -8.3%
Large General Service 21,22 492,856 $ 51,143 $ (3,672) -7.2%
Extra Large General Service 25 344,595 $ 22,608 $ (2,567) -11.4%
Clearwater 25P 377,883 $ 22,810 $ (2,815) -12.3%
Pumping Service 31,32 60,691 $ 7,173 $ (452) -6.3%
Street&Area Lights 41-49 10,014 ` 3,932 $ (75) -1.9%
Total 3,240,155 $ 309,342 $ (24,139) -7.8%
Customer Notice and Press Release
The Company's press release and customer notice were included with its Application.
Each document addresses the following cases: (1) this case (AVU-E-24-07); (2) electric FCA
(AVU-E-24-08); (3) the natural gas FCA(AVU-G-24-01); and(4)the natural gas PGA(AVU-E-
24-02). Staff reviewed the documents and determined both meet the requirements of Rule 125 of
the Commission's Rules of Procedure. See IDAPA 31.01.01 .125. The notice was included with
bills mailed to customers beginning August 2, 2024, and ending August 30, 2024.
The Commission set a comment deadline of September 11, 2024. Some customers in the
last billing cycles will not have received or had adequate time to submit comments before the
deadline. Customers should have the opportunity to file comments and have those comments
considered by the Commission. Staff recommends that the Commission consider late filed
comments from customers. As of September 10, 2024, no customer comments had been filed.
STAFF RECOMMENDATION
Staff recommends the Commission approve a revenue requirement of$7,974,923 and the
resulting rates with an effective date of October 1, 2024.
Staff also recommends the Commission:
STAFF COMMENTS 10 SEPTEMBER 11, 2023

1. Approve the adjustment for Clearwater Purchased Power Cost reducing the
deferral by an incremental $741,566;
2. Approve the adjustment for Chelan Hydro purchased power cost reducing the
deferral by$581,315;
3. Order the Company to file conforming tariffs for Schedule 66 Temporary Power
Cost Adjustment—Idaho reflecting the Commission-approved rates;
4. Order the Company, Staff, and interested parties to meet after the case is closed to
re-evaluate the "lesser of market or contract" mechanism to ensure it protects
Idaho customers while balancing benefits the contract may provide, prior to filing
the next PCA;
5. Order the Company to track the cost impact of using a Boulder Park dispatch cost
without the cost of allowances over the remaining PCA year to be reported in next
year's PCA filing; and
6. Consider late-filed comments from customers.
Respectfully submitted this 1 Ith day of September 2024.
k, - 1,/q.,
Chris Burdin
Deputy Attorney General
Technical Staff: Laura Conilogue
Yao Yin
Curtis Thaden
I:\Utility\UMISC\COMMENTS\AVU-E-24-07 Comments.docx
STAFF COMMENTS 11 SEPTEMBER 11, 2023

CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS DAY OF SEPTEMBER
2024, SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. AVU-E-24-07, BY &MAILING A COPY THEREOF TO THE FOLLOWING:
PATRICK EHRBAR DAVID J MEYER
DIR OF REGULATORY AFFAIRS VP & CHIEF COUNSEL
AVISTA CORPORATION AVISTA CORPORATION
PO BOX 3727 PO BOX 3727
SPOKANE WA 99220-3727 SPOKANE WA 99220-3727
E-mail: patrick.ehrbargavistacorp.com E-mail: david.meyer(a avistacorp.com
[e-mail]
;X�vo�t
PATRICIA JORD , SECRETARY
CERTIFICATE OF SERVICE