20240515Staff Comments.pdf

RECEIVED
2024 May 14, 4:40PM
IDAHO PUBLIC
UTILITIES COMMISSION
ADAM TRIPLETT
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 10221
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 ROCKY MOUNTAIN )
POWER'S APPLICATION FOR APPROVAL ) CASE NO. PAC-E-24-05
OF $62.4 MILLION ECAM DEFERRAL )
COMMENTS OF THE
COMMISSION STAFF
COMMISSION STAFF ("STAFF") OF the Idaho Public Utilities Commission, by and
through its Attorney of record, Adam Triplett, Deputy Attorney General, submits the following
comments.
BACKGROUND
On April 1, 2024, Rocky Mountain Power, a division of PacifiCorp ("Company"),
applied for Commission authorization to adjust its rates under the Energy Cost Adjustment
Mechanism ("ECAM"). Specifically, the Company seeks approval of approximately $62.4
million in ECAM deferral for the period of January 1, 2023, through December 31, 2023, with a
10.5 percent increase to Electric Service Schedule No. 94, Energy Cost Adjustment. The
monthly bill for a typical residential customer using 783 kilowatt-hours of electricity per month
would increase by $7.39. The Company requests its proposed adjustment be processed by
Modified Procedure and become effective on June 1, 2024.
STAFF COMMENTS 1 MAY 14, 2024

The ECAM allows the Company to increase or decrease its rates each year to reflect
changes in the Company's power supply costs. These costs vary by year with changes in the
Company's fuel (gas and coal) costs, surplus power sales, power purchases, and associated
transmission costs. Each month, the Company tracks the difference between the actual net
power costs ("NPC") it incurred to serve customers, and the embedded(or base)NPC it collected
from customers through base rates. The Company defers the difference between actual NPC and
base NPC into a balancing account for treatment at the end of the yearly deferral period. At that
time, the ECAM allows the Company to credit or collect the difference between actual NPC and
base NPC through a decrease or increase in customer rates. Neither the Company nor its
shareholders will receive any financial return because of this filing.
Besides the NPC difference, this year's ECAM includes: (1) the Load Change
Adjustment Revenues; (2) coal stripping costs under Emerging Issues Task Force 04-6; (3)
Renewable Energy Credit revenues; (4) Production Tax Credits; (5) the reasonable energy price,
as defined in the 2020 Protocol; (6) qualified facility costs; and(7)wind availability liquidated
damages.
The Company seeks: (1) an order approving its request for$62.4 million ECAM deferral;
and(2) a 10.5 percent increase to Electric Service Schedule No. 94. The Company represents
that, if its proposal is approved,prices for customer classes would increase as follows:
• Residential Schedule 1 —(7.6%);
• Residential Schedule 36, Optional Time-of-Day Service—(8.7%);
• General Service Schedule 6—(10.7%);
• General Service Schedule 9—(13.1%);
• Irrigation Service Schedule 10—(9.5%);
• General Service Schedule 23 —(9.0%);
• General Service Schedule 35 —(10.3%);
• Public Street Lighting—(5.2%); and
• Tariff Contract, Schedule 400—(13.5%).
STAFF COMMENTS 2 MAY 14, 2024

STAFF ANALYSIS
Staff reviewed the Company's external audit reports,journal entries, invoices, contracts,
and the Company's adjustment to actual costs. Staff reconciled the general ledger amounts to the
NPC provided in Exhibit No. 1 of Jack Painter's testimony. In addition, Staff reviewed the
Company's hedge contracts and policies, and believe they reasonably safeguard price and fuel
stability. Staff also reviewed the transactions and invoices for the Energy Imbalance Market
("EIM")revenues. In this ECAM filing, the Company included additional costs related to the
State of Washington's Climate Commitment Act("CCA"). Staff removed Idaho's portion of
CCA costs from the ECAM deferral. In Order No. 36015, the Commission found"that it is not
fair,just, or reasonable to include the costs associated with CCA compliance in Idaho rates."
This adjustment reduces the Company's Idaho jurisdictional request by $2.3 million and is
reflected in Table No. 1 —ECAM Deferral.
Table No. 1 —ECAM Deferral
NPC Differential for Deferral 65,874,728
EITF 04-6 Adjustment 60,594
LCAR 268,994
Washinton CCA Adjustment (2,568,948
Total Deferral Before Sharing 63,635,368
Sharing Band 90%
Customer Responsibility 57,271,832
Production Tax Credits 907,177
REP QF Adjustment 1,450,130
Wind Liquidated Damages (310,085)
REC Deferral (357,308)
Interest on Deferral 1,157,387
Removing Interest on Washington CCA (25,172)
Annual Deferral(Jan-Dec 2023) 60,093,960
Unamortized Previous Balance 41,941,478
ECAM Rider Revenues 28,953,155
Total Company Recovery 73,082,282
STAFF COMMENTS 3 MAY 14, 2024

Net Power Cost Deferral
The NPC adjustment within the ECAM allows the Company to collect or credit the
difference between NPC incurred to serve customers in Idaho and the NPC collected from Idaho
customers through base rates during the deferral period. In Order No. 35277, the NPC embedded
in rates was set at $24.54 per megawatt hour("M)"").
The revenue collected through base rates is calculated by multiplying $24.54 by
3,495,580 MWh of actual Idaho sales, for a total of$85.7 million. The difference between base
rate revenue and Idaho's share of actual 2023 NPC of$149 million, leaves an under-collected
balance of$63.3 millions after removal of compliance costs associated with the CCA. The
under-collected balance is subject to a 90/10 customer sharing band, with the Company paying
10% of the NPC balance.2 After removing the Company's 10%, the amount customers are
responsible to pay through Schedule 94 rates is $57.2 million.
Emerging Issues Task Force ("EITF')
The EITF 04-6 adjustment is the difference between coal stripping costs the Company
incurred and recorded, as stated in the accounting pronouncement EITF 04-6, and the
amortization approved by Order No. 30987 in Case No. PAC-E-09-08. The Company uses this
account to "undo"the effects of EITF 04-6 that requires the Company to expense coal stripping
costs opposed to amortizing it over the coal produced from the section of open mines. The
adjustment increases the deferral by $60,594. Staff reviewed the adjustment and believes it was
accurately calculated.
Load Change Adjustment Revenues ("LCAR")
Staff believes the Company's LCAR adjustment complies with Order No. 35277. The
LCAR adjusts for the under-or over-recovery of fixed energy-classified production cost
(excluding NPC)resulting from the difference between Idaho sales used to determine base rates
and the sales from the deferral year. The LCAR of$8.74 per MWh was set in Case No. PAC-E-
21-07. Multiplying the LCAR by the actual Idaho sales of 3,495,580 MWh shows that the
' See Table 1 $65.9 million less$2.6 million.
2 Under the 90/10 sharing band customers pay 90%of the under-collected balances and the Company pays the
remaining 10%. For over-collected balances,customers receive 90%of the benefit and the Company keeps 10%.
STAFF COMMENTS 4 MAY 14, 2024

Company collected$30.5 million of energy-classified fixed production costs through base rates.
The difference between the actual energy-classified fixed production costs collected and the
$30.8 million embedded in base rates increases the ECAM deferral by $268,994.
Production Tax Credits ("PTC")
In Order No. 33440, the Commission approved a settlement in Case No. PAC-E-15-09
that moved the PTC true-up to the ECAM, with a$1.99 per MWh benefit to customers included
in base rates. In Order No. 35277, the Commission approved a settlement increasing the PTC to
$4.16 per MWh. In 2023, base rates included a$14.6 million benefit from PTCs; however, the
actual PTCs allocated to Idaho customers in 2023 was $13.6 million. The $907,177 difference
between the PTCs in base rates and the actual PTCs is a surcharge to the customers.
Reasonable Energy Price QF Adjustment
The 2020 Protocol, approved by Order No. 34640, included a provision that all QF
contracts approved in 2020 and after would be subject to a reasonable price adjustment. The
amount the Company paid for energy under each QF contract over a reasonable energy price
would be SITUS allocated to the state that approved the QF contract. Painter Di. at 10.
In this case, there are 11 contracts requiring comparison for the reasonable energy price
QF adjustment-with four incurring a SITUS allocation adjustment to Idaho. Staff reviewed the
process for creating the reasonable energy price and the energy price for those contracts and
Staff believes it complies with the 2020 Protocol. The reasonable energy price QF adjustment
results in a $1.5 Million increase to the deferral to Idaho.
Renewable Energy Credits ("REC"�
In Order No. 35277, the Commission approved $0.07 per MWh in REC revenues to be
included in base rates. The difference between the embedded amount and actual REC revenue is
trued-up in the ECAM. In 2023,base rates included $239,273 in benefits from REC revenues.
Idaho's share of the Company's actual REC revenues was $596,582. The difference of$357,308
offsets the deferral balance.
Wind Availability Liquidated Damages
The Company included a $310,085 credit to customers for a wind availability liquidated
damages credit. In the stipulation approved in Order No. 33954, Case No. PAC-E-17-06, the
STAFF COMMENTS 5 MAY 14, 2024

Company agreed to pass on all liquidated damages received from suppliers in case the repowered
equipment does not meet the specifications required. The Company allocated liquidated
damages by the system generation("SG") factor and then applied that credit to customers. Staff
reviewed the supporting documentation provided by the Company and agree with the inclusion
of this reduction to NPC.
Washinton CCA
In 2023, the Company incurred $42 million in costs, on a system basis, to comply with
the Washington CCA. In Mr. Painter's testimony he stated, "These costs were necessary to
comply with applicable law for continued operation of Chehalis...Idaho customers received the
benefit of the generation from the Chehalis natural gas facility which reduced NPC. NPC would
have increased by $23.6 million on a total Company basis if the generation from Chehalis were
removed". (Painter, Di at 24 and 25).
In Order No. 36015, the Commission stated the following:
Based upon a review of the CCA, the Commission finds that it is not fair,
just, or reasonable to include the costs associated with CCA compliance in Idaho
rates. Idaho Code §§ 61-301, 61-502. The CCA is a Washington specific policy
initiative for which Washington has established a revenue generating market
through the creation and distribution of allowances for Washington GHG
emissions. Washington then requires Idaho customers to pay the costs associated
with complying with the CCA while at the same time mitigating the costs of that
compliance for Washington customers through no-cost allowances.
The Commission is asked to weigh the interests of Washington's social and
environmental policies, and its revenue generating market, against the interests of
Idaho customers in having just and reasonable rates. The Commission finds that
the interests of Idaho customers outweigh Washington's policy interests.
The current application of the CCA provides for disparate treatment
between Idaho and Washington ratepayers, and creates in essence, or perhaps in
fact, a one-sided tax upon Idaho ratepayers to pay for Washington's social and
environmental policies. The Commission cannot find it fair,just, or reasonable for
Idaho customers to fund Washinton's policy initiatives when none of the alleged
benefits will flow to Idaho customers.
Staff believes including the Washington CCA costs in the ECAM deferral is not
fair,just, or reasonable because it creates a one-sided tax for Idaho ratepayers. For this
reason and for the reasons mentioned above Staff recommends the Commission remove
CCA costs from the ECAM deferral. This adjustment reduces total ECAM recovery by
approximately $2.3 million.
STAFF COMMENTS 6 MAY 14, 2024

Prudence of Actual NPC
Staff believes the Company generally dispatched its resources, purchased from the
wholesale electricity market, and sold power into the market in a prudent manner while
encountering difficult circumstances and constraints during the deferral period. Staff reviewed
the Application, exhibits, and testimony to identify and understand the various contributors to
this year's higher levels of actual NPC compared to base amounts set to be recovered through
rates during the 2023 deferral period. Staffs conclusion is based on two types of analyses: (1) a
comparison of the actual and base amounts of energy and cost from the Company's resources
during the deferral period, and(2) an analysis of unit downtime of the Company's generation
resources to ensure the amount and causes of downtime were reasonable.
From an Idaho perspective, the 2023 annual ECAM deferral amount was $62.4 million
after applying the 90/10 sharing band(not including Staffs CCA cost adjustment), which is
75.3%higher than the amount recovered through base rates. On a total Company basis, the 2023
actual NPC was $2.53 billion and 85.2%higher than base NPC. The Company's base rates were
established by the Commission in Case No. PAC-E-21-07, with the new base rates put into effect
on January 1, 2022.
Comparison of Base and Actual NPC
Staff compared the amount and cost of energy embedded in base rates to the actual
amount and cost of energy incurred during the deferral period for the different types of resources
needed to meet load and to maximize the amount of wholesale sales to other utilities. Staff
believes that the higher actual NPC is attributed to a combination of several factors such as
increased power purchase expenses, lack of coal generation due to coal supply constraints,
decreased wholesale sales, increased natural gas expense, and reduced hydro generation.
First, Staff compared the 2023 adjusted actual Company NPC with the NPC included in
base rates by resource type, with the results of that analysis summarized in Table No. 2, below.
STAFF COMMENTS 7 MAY 14, 2024

Table No. 2: Comparison between 2023 Adiusted Actual NPC and Base NPC.
Source Adjusted Base NPC3 Base-to-Actual Percentage
Actual NPC ($) ($) Difference ($) Difference
Wholesale Sales (174,104,342) (463,692,258) 289,587,9174 (62.5%)
Revenue
Purchased Power 1,421,234,074 844,451,804 576,782,270 68.3%
Expense
Coal Fuel Expense 557,291,331 599,876,421 (42,585,090) (7.1%)
Natural Gas Expense 556,454,677 228,727,764 327,726,913 143.3%
Wheeling Expense 165,290,267 154,137,105 11,153,161 7.2%
Geothermal and Other
Generation Expense
7,616,464 4,416,584 3,199,880 72.5%
Total System NPC 2,533,782,470 1,367,917,419 1,165,865,050 85.2%
The largest base-to-actual dollar differences contributing to higher actual NPC compared
to base NPC stemmed from higher purchased power expense of approximately $577 million,
higher natural gas expense of$328 million, and lower wholesale sales revenue of$290 million.
To understand the reasons for these reductions, Staff then compared the amount of
generation from the Company's different resources that was assumed in base rates to the actual
amounts as reflected in Table No. 3,below.
Table No. 3: Comparison of 2023 Actual Generation in Mega-Watt Hour("MWh") and
Base Generation (MWh).
2023 Base
Difference Percentage
Generation Generation
(MWh) Difference
(MWh) (MWh)
Purchased Power 18,753,118 18,280,773 472,345 2.6%
Coal Generation 21,951,022 29,875,118 (7,924,096) (26.5%)
Gas Generation 14,049,912 8,487,500 5,562,412 65.5%
Geothermal and Other 252,013 250,943 1,070 0.4%
Generation
Wind Generation 6,499,381 7,869,533 (1,370,152) (17.4%)
Hydro Generation 3,000,399 4,440,989 (1,440,590) (32.4%)
Total System Generation 64,505,845 69,204,856 (4,699,011) (6.8%)
s Case No.PAC-E-21-07 PacifiCorp—General Rate Case.
a The positive amount for the wholesale sales base-to-actual difference represents a reduction in revenue from the
total actual amount of sales relative to the base amounts;whereas positive amounts for base-to-actual cost
components represent increases in actual cost as compared to base amounts.
STAFF COMMENTS 8 MAY 14, 2024

As can be seen from the table, the amount of generation from hydro, coal, and wind, three
of the Company's lowest cost energy resources, had significantly lower amounts of generation
with Hydro being 32.4% less, coal being 26.5% less, and wind being 17.4% less, when compared
to base amounts. The lower amounts of zero fuel cost hydro and wind generation was due to
lack of availability of water and wind during the deferral period. As discussed in more detail
below, the lower amount of coal generation was mostly due to coal supply issues, and
transmission constraints between the Bridger coal plant and loads west of the facility. Case No.
PAC-E-23-09—2022 ECAM Investigation Report at 13 and 19. Because of these issues, the
Company had to rely on 65.5% more gas generation to meet customer load, the actual price of
which was $39.61/MWh and 47%higher than the price assumed in base rates. The Company
also had to rely heavily on market purchases; however, the price of market purchases was
$75.79/MWh, 64.1% greater than prices assumed in base rates. Both of these resources were
significant contributing factors to overall higher actual NPC costs.
Because of the lower amounts of generation from coal, wind, and hydro resources, the
Company sold 62.5% less generation into the wholesale market than the amounts assumed in
base rates. Revenue from Wholesale sales has traditionally been a method for the Company to
offset its actual NPC to customers. However, some of this difference can be attributed to
inaccuracies in the model the Company used to set its base rates. The Company stated that it
plans to improve its modeling of NPC, which should provide a more precise estimation of
wholesale sales revenues in the future. The Company expects to supply the details of its updated
NPC model in its next general rate case. See Company's Response to Production Request No. 8.
Resource Downtime
Staff believes that the amount and causes of resource downtime were reasonable. Staff
analyzed the amount of downtime and causes of downtime provided through discovery requests.
See Company's Response to Production Request No. 5. Although Staff is not concerned about
the amount of total resource downtime and understands that the Company made prudent
decisions in taking its resources out of service based on various needs, Staff notes two of the
major downtime events occurred with the "Prospect 3"hydro unit and five Swift hydro units. In
STAFF COMMENTS 9 MAY 14, 2024

both cases, Staff believes the reasons for the downtime were legitimate and that the amount of
downtime for each of these projects were reasonable given the work that needed to be completed.
Proposed Rates
As shown in Table No. 4 below, the Company's proposed rates increase Schedule 94
rates by about 101.1%with an approximate 10.5% increase in base rate revenue. However,
given Staff s recommended CCA adjustment, Staff proposes about a 93.7% increase in Schedule
94 rates, which results in an increase in base rate revenue of about 9.7%.
Table No. 4: Schedule 94 ECAM Adiustments.
Current Company Proposed Staff Proposed
Service Type Rates Rates Increase % Rates Increase %
(¢/kWh) (¢/kWh) from Increase (¢/kWh) from Increase
Current Current
¢/kWh (0/kWh)
Secondary 0.934 1.878 0.944 101.1% 1.809 0.875 93.7%
Primary 0.917 1.844 0.927 101.1% 1.776 0.859 93.7%
Transmission 0.886 1.782 0.896 101.1% 1.717 0.831 93.8%
Staff verified that the methods for determining the Company's proposed Schedule 94
ECAM rates follow past Commission orders, and that the calculations were accurate. See
Company Application—Exhibit 2. The method approved in Order No. 33440 was used to spread
the increase appropriately across each of the customer classes; however, the Company's revenue
increases from specific customer classes vary because of the rate design. The proposed ECAM
rates in Schedule 94 are voltage-level specific, which considers line losses due to the type of
service for each class of customer.
Under the Company's proposal, a typical Schedule 1 residential customer who receives
service at the secondary distribution level would receive a $7.39 increase in their monthly bill.
Under Staff s proposal, the same customer would see about a$6.85 in their monthly bill. A full
summary of Staff s proposed rates is included in Staff Attachment No. 1.
NPC Coal
In 2022, the Company experienced supply problems for its Hunter Power Plant
("Hunter") and its Huntington Power Plant("Huntington"), both coal plants in Utah. The
STAFF COMMENTS 10 MAY 14, 2024

Company received force majeure letters from its coal suppliers including one relating to a fire in
the Lila Canyon coal mine. The Lila Canyon coal mine produces more than 25% of the total
coal supply for all of Utah. This continued into 2023, with additional force majeure letters, and
notice that the Lila Canyon mine would remain permanently closed.
Through 2023, the Company scrambled to find all reasonably priced coal supplies that
could be sent to Hunter and Huntington. The Company's attempts to find coal included a short-
term coal supply contract with the Gentry Mountain Mining, using their supply at the Rock
Garden Safety Pile, and even shipping some coal from the Gadsby Power Plant.
Additionally, the Company controlled the burn from both Hunter and Huntington to
ensure there was coal available for the peak usage times by increasing the dispatch price above
the cost of fuel for those plants. The Company used an internally created model to estimate the
amount of coal the plants would have on hand at the end of the year at various dispatch prices.
The dispatch price was then set to ensure there was a reasonable amount of coal in the pile at the
end of the year. This model was updated weekly, and the price adjusted accordingly. The
dispatch price ranged from the $30 range to over $80 per MWH.
Going forward, the Company has negotiated new contracts to supply coal to both Hunter
and Huntington, but at a significant price increase. There are provisions in the contract that will
help in attempting to restore supplies for the region and protections for the company paying too
much for the coal in this contract. This price increase will prevent these plants from being the
lowest price coal plant in the Company's fleet but will still make a reasonable hedge against high
prices in the future. Staff estimates this will put the cost per MWH for coal from these plants to
the midpoint of the Company's natural gas plants.
Overall, the last two years have been very difficult years for the Utah coal plants. Staff
believes the Company operated the plants prudently and sought alternative coal supplies in a
manner that mitigated costs while setting up its Utah plants to be a useful hedge against high
prices in the future.
Customer Notice and Press Release
The Company's press release and customer notice were included with its Application.
Staff reviewed the documents and determined that both meet the requirements of Rule 125 of the
Commission's Rules of Procedure (IDAPA 31.01.01.125). The notice was included with bills
mailed to customers beginning April 3, and ending May 2, 2024,providing customers with a
STAFF COMMENTS 11 MAY 14, 2024

i
reasonable opportunity to file timely comments with the Commission by the May 14, 2024
deadline. As of May 13, 2024, no customer comments had been filed.
STAFF RECOMMENDATION
Staff recommend the Commission:
1. Approve Staff s revised ECAM deferral of approximately$60.1 million.
2. Remove Washington CCA costs (approximately$2.3 million) from the ECAM deferral.
3. Order the Company to provide revised tariffs to include Staffs adjustments to NPC.
Respectfully submitted this 141h day of May 2024.
411"
Adam Triplett
k4—Deputy Attorney General
Technical Staff: Ty Johnson
Joe Terry
Matt Suess
Shubhra Deb Paul
Curtis Thaden
1:\Utility\UMISC\COMMENTS\PAC-E-24-05 Comments confidential.docx
STAFF COMMENTS 12 MAY 14, 2024

1
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS "I DAY OF MAY 2024,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. PAC-E-24-05, BY E-MAILING A COPY THEREOF, TO THE FOLLOWING:
MARK ALDER JOE DALLAS
ROCKY MOUNTAIN POWER ROCKY MOUNTAIN POWER
1407 WEST NORTH TEMPLE STE 330 825 NE MULTNOMAH ST
SALT LAKE CITY UT 84116 STE 2000
E-MAIL: [e-mail] PORTLAND OR 97232
E-MAIL: oseph.dallas(cbpacificorp.com
DATA REQUEST RESPONSE CENTER
E-MAIL ONLY:
datarequest ,pacificorp.com
PATR C A J6RDAN, S CR TARY
CERTIFICATE OF SERVICE

STAFF EXHIBIT NO.1
ROCKY MOUNTAIN POWER
FROM ELECTRIC SALES TO ULTIMATE CONSUMERS
DISTRIBUTED BY RATE SCHEDULES IN IDAHO
ADJUSTED HISTORICAL 12 MONTHS ENDED DECEMBER 2020
Present At Meter At ECAM Proposal Present
Line Average Base MWh by Voltage Generation Rev Rate 0/kWh ECAM Rev Net Change
No. Description Sch. Customers MWH ($000) S P T MWh ($000) S P T ( 000) ( 000)
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15) (16)
Residential
1 Residential Service 1 55,659 523,107 $60,147 523,107 570,505 $9,462 1.809 1.776 1.717 $4,886 $4,576 7.0%
2 Residential Optional TOD 36 11,711 196,337 $19,448 196,337 214,128 $3,551 1.809 1.776 1.717 $1,834 $1,718 8.1%
3 AGA Revenue $4
4 Total Residential 67,370 719,444 $79,599 719,444 0 0 784,633 $13,014 $6,720 $6,294 7.3%
5 Commercial&Industrial
6 General Service-Large Power 6 1,158 345,854 $27,087 303,007 42,847 376,344 $6,242 1.809 1.776 1.717 $3,223 $3,019 10.0%
7 General Svc.-Lg.Power(R&F) 6A 207 26,805 $2,326 26,656 149 29,231 $485 1.809 1.776 1.717 $250 $234 9.1%
8 Subtotal-Schedule 6 1,365 372,659 $29,413 329,663 42,996 0 405,575 $6,727 $3,473 $3,253 9.9%
9 General Service-High Voltage 9 17 222,699 $13,225 0 0 222,699 230,500 $3,823 1.809 1.776 1.717 $1,973 $1,850 12.2%
10 Irrigation 10 5,971 615,886 $55,363 615,886 671,691 $11,140 1.809 1.776 1.717 $5,752 $5,388 8.8%
11 General Service 23 7,734 183,016 $17,375 182,662 353 0 199,592 $3,310 1.809 1.776 1.717 $1,709 $1,601 8.4%
12 General Service(R&F) 23A 2,576 39,710 $3,922 38,626 1,084 43,287 $718 1.809 1.776 1.717 $371 $347 8.1%
13 Subtotal-Schedule 23 10,310 222,726 21,298 221,289 1,437 0 242,879 4,028 2,080 1,948 8.3%
14 General Service Optional TOD 35 2 278 $23 278 303 $5 1.809 1.776 1.717 $3 $2 9.6%
15 General Service Optional TOD(R&F) 35A 0 0 $0 0 0 $0 1.809 1.776 1.717 $0 $0
16 Subtotal-Schedule 35 2 278 23 278 0 0 303 5 1.809 1.776 1.717 3 2 9.6%
17 Special Contract 400 1 1,369,716 $79,465 1,369,716 1,417,697 $23,730 1.733 $12,218 $11,512 12.6%
18 AGA Revenue $602
19 Total Commercial&Industrial 17,666 2,803,964 $199,389 1,167,116 44,433 1,592,415 2,968,646 $49,454 $25,499 $23,954 10.7%
20 Public Street Lighting
21 Security Area Lighting 7 188 274 $50 274 298 $5 1.809 1.776 1.717 $3 $2 4.6%
22 Security Area Lighting(R&F) 7A 132 106 $24 106 115 $2 1.809 1.776 1.717 $1 $1 3.7%
23 Street Lighting-Company 11 57 154 $61 154 168 $3 1.809 1.776 1.717 $1 $1 2.1%
24 Street Lighting-Customer 12 256 2,417 $368 2,417 2,636 $44 1.809 1.776 1.717 $23 $21 5.4%
25 AGA Revenue $0
26 Total Public Street Lighting 633 2,950 $503 2,950 0 0 3,218 $53 $28 $26 4.9%
27 Total Sales to Ultimate Customers 85,669 3,5 66,359 $279,491 1,8 99,511 44,433 1,5 22,415 3,7 66,496 $62,521 $32,246 $30,274 9.7%
28 Total Excluding Special Contract 400 85,668 2,1 66,643 $200,026 1,8 99,511 44,433 222,699 2,338,799 $38,791 $20,029 $18,762 8.5%
Rev.Rqmt Unallocated Allocated Proposed Rates Current Rates
29 Voltage Line Loss Factors applied to rates(2018 Study): 1.09061 1.07082 1.03503 S P T S P T
30 Tariff Customer ECAM deferral and Rate(cents/kWh): $38,791 1.659 1.809 1.776 1.717 Tariff Customer Rate 1.809 1.776 1.717 0.934 0.917 0.886
31 REC Adjustment and Rate(cents/kWh): ($357) -0.010 -0.010 -0.010 -0.010 Schedule 400 Rate 1.733 0.892
32 Total Idaho ECAM Rate(cents/kWh): $62,521 1.664 1.815 1.782 1.723 REC Adj -$135
Attachment No. 1
Case Number PAC-E-24-05
Comments
May 14, 2024